ML13169A134

{{Adams | number = ML13169A134 | issue date = 06/13/2013 | title = Comanche Peak, Units 1 and 2 and ISFSI - Enclosure 7 to TXX-13095 - Additional Documentation for Energy Future Holdings Corporation, and Enclosures 8, 9B, 10, 11 and 12. Part 2 of 2 | author name = | author affiliation = Luminant Generation Co, LLC, Luminant Power, Energy Future Holdings Corp | addressee name = | addressee affiliation = NRC/NSIR/DSO | docket = 05000445, 05000446, 07200074 | license number = | contact person = | case reference number = CP-201300695, TXX-13095, TAC ME9767, TAC ME9768 | document type = - No Document Type Applies, Letter, Operating Plan | page count = 694 | project = TAC:ME9767, TAC:ME9768 | stage = }}

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{{#Wiki_filter:Enclosure 7 with TXX-13095Additional Documentation forEnergy Future Holdings CorporationAmended and Restated BylawsRestated Certificate of Formation of Energy Future Holdings Corp.EFH Corp. 10K ENERGY FUTURE HOLDINGS CORP.Amended and Restated BylawsSECTION 1. REGISTERED OFFICE. The registered office of the Corporation required by theTexas Business Organizations Code (the "TBOC") to be maintained in the State of Texas shallbe the register'ed office named in the Certificate of Formation of the Corporation (the "Certificateof Formation") or such other office (which need not be a place of business of the Corporation) asmay be designated from time to time by the board of directors in the manner provided by law.SECTION 2. PLACE OF MEETINGS. All meetings of the shareholders shall be held at theprincipal place of business of the Corporation or at such other place within or without the Stateof Texas as shall be specified or fixed in the notices or waivers of notice thereof.SECTION 3. QUORUM; REQUIRED VOTE FOR SHAREHOLDER ACTION; ADJOURNMENT OFMEETINGS.(a) Quorum. With respect to any matter, a quorum shall be present at a meeting ofshareholders if the holders of a majority of the shares entitled to vote on that matter arerepresented at the meeting in person or by proxy, unless otherwise provided in the Certificate ofFormation of the Corporation, as the same may be amended from time to time, in accordancewith the TBOC.(b) Voting on Matters Other Than the Election of Directors. With respect to anymatter, other than the election of directors or a matter for Which the affirmative vote of theholders of a specifiedportion of the shares of any class or series entitled to vote is required bythe TBOC, the affirmative vote of the holders of a majority of the shares of any class or seriesentitled to vote on that matter and represented in person or by proxy at a meeting of shareholdersat which a quorum is present shall be the act of the shareholders, unless otherwise provided inthe Certificate of Formation or these bylaws in accordance with the TBOC.(c) Voting in the Election of Directors. Unless otherwise provided in the Certificateof Formation or these bylaws .in accordance with the TBOC, directors shall be elected by aplurality of the votes cast by the holders of shares entitled to vote in the election of directors at ameeting of shareholders at which a quorum is present.(d) Adjournment. Notwithstanding the other provisions of the Certificate ofFormation or these bylaws, the chairman of the meeting or the holders of a majority of the sharesentitled to vote that are represented in person or by proxy at any meeting of shareholders,whether or not a quorum is present, shall have the power to adjourn such meeting from time totime, without any notice other than announcement at the meeting of the time and place of theholding of the adjourned meeting. If such meeting is adjourned by the shareholders, such timeand place shall be determined by a vote of the holders of a majority of the shares entitled tovotethat are represented in person or by proxy at such meeting. Upon the resumption of suchadjourned meeting, any business may be transacted that might have been transacted at themeeting as originally called. SECTION 4. ANNUAL MEETINGS. An annual meeting of the shareholders, for the election ofdirectors to succeed those whose terms expire and for the transaction of such other business asmay properly come before the meeting, shall be held at such place, within or without the State ofTexas, on such date and at such time as the board of directors shall fix and set forth in the noticeof the meeting.SECTION 5. SPECIAL MEETINGS. Unless otherwise provided in the Certificate of Formation,special meetings of the shareholders for any proper purpose or purposes may be called at anytime by (a) the chairman of the board (if any), the president, the board of directors, or such otherperson or persons as may be authorized in the Certificate of Formation or (b) unless theCertificate of Formation provides otherwise, the holders of at least twenty-five percent of all theshares entitled to vote at the proposed special meeting.Only business within the purpose or purposes described in the notice (or waiver thereof) requiredby these bylaws may be conducted at a special meeting of the shareholders.SECTION 6. RECORD DATE. For the purpose of determining shareholders entitled to notice ofor to vote at any meeting of shareholders or any adjournment thereof, or to receive payment ofany dividend, or for any other proper purpose, the board of directors may fix in advance a recorddate for any such determination, such date to be not more than sixty days and, in case of ameeting of shareholders, not less than ten days, prior to the date on which the particular actionrequiring such determination of shareholders is to be taken.SECTION 7. NOTICE OF MEETINGS. Written or printed notice stating the place, day and hour ofthe meeting, the means of any remote communications by which shareholders may be consideredpresent and may vote at the meeting, and, in the case of a special meeting, the purpose orpurposes for which the meeting is called, shall be delivered not less than ten days nor more than60 days before the date of the meeting, personally, by electronic transmission or by mail, by or atthe direction of the president, the secretary or the officer or calling the meeting, to eachshareholder entitled to vote at such meeting.SECTION 8. VOTING. Unless otherwise required by law or provided in the Certificate ofFormation, each outstanding share, regardless of class, shall be entitled to one vote on eachmatter submitted to a vote at a meeting of shareholders. If the Certificate of Formation providesfor more or less than one vote per share for all the outstanding shares or for the shares of anyclass or series on any matter, every reference in these bylaws or in the Certificate of Formation(unless expressly stated otherwise therein), in connection with such matter, to a specified portionof such shares shall mean such portion of the votes entitled to be cast in respect of such shares byvirtue of the provisions of such Certificate of Formation.SECTION 9. ACTION BY WRITTEN CONSENT. Any action required by the TBOC to be taken atany annual or special meeting of shareholders, or any action which may be taken at any annual orspecial meeting of shareholders, may be taken without a meeting, without prior notice, andwithout a vote, if a consent or consents in writing, setting forth the action so taken, shall besigned by the holders of shares having not less than the minimum number of votes that would benecessary to take such action at a meeting at which the holders of all shares entitled tovote onthe action were present and voted. Prompt notice of the taking of any action by shareholders2 without a meeting by less than unanimous written consent shall be given to those shareholderswho did not consent in writing to the taking of such action.SECTION 10. FORM OF CERTIFICATES OF STOCK, UNCERTIFICATED SHARES AND TRANSFEROF SHARES. The shares of the Corporation's stock may be certificated or uncertificated, asprovided under the TBOC, and shall be entered in the books of the Corporation and registered asthey are issued. Certificates of stock of the Corporation shall be of such form and device as theboard of directors may from time to time determine. The stock of the Corporation shall betransferable only on the books of the Corporation by registered owners of uncertificated sharesand by the holders in person or by attorney on surrender of the certificates therefor properlyendorsed. Upon surrender to the Corporation or the transfer agent of the Corporation of acertificate for shares duly endorsed or accompanied by proper evidence of succession,assignment, or authority to transfer, and upon payment of all taxes as may be imposed by law, itshall be the duty of the Corporation to issue a new certificate or evidence of the issuance ofuncertificated shares to the person entitled thereto, cancel the old certificate, and record thetransaction upon the Corporation's books. The board of directors may appoint one or moretransfer agents and one or more registrars of the stock. The Corporation shall be entitled to treatthe holder of record of any shares of the Corporation as the owner thereof for all purposes, andshall not be bound to recognize any equitable or other claim to, or interest in, such shares or anyrights deriving from, such shares, on the part of any other person, unless and until such otherperson becomes theholder of record of such shares, whether or not the Corporation shall haveeither actual or constructive notice of the interest of such other person. Within a reasonable timeafter the issuance or transfer of uncertificated stock, the Corporation shall send to the registeredowner thereof a written notice that shall set forth the information required by Section 3.205(a) ofthe TBOC.SECTION 11. SIGNING OF CERTIFICATES OF STOCK. Certificates of stock of the Corporationshall be signed by the chairman of the board, the chief executive, the president or any vicepresident and either the secretary or an assistant secretary, and shall be sealed with the seal of theCorporation or a facsimile thereof. The signatures of such officers upon a certificate may befacsimiles if the certificate is countersigned by a transfer agent or registered by a registrar, eitherof which is other than the Corporation itself or an employee of the Corporation. In case anyofficer who has signed or whose facsimile signature has been placed upon such certificate shallhave ceased to be such officer before such certificate is issued, it may be issued by theCorporation with the same effect as if he were such officer at the date of its issuance.SECTION 12. DIRECTORS.(a) Number of Directors; Vacancies. The board of directors shall consist of not lessthan two nor more than seventeen directors. Subject to the foregoing sentence, the specificnumber constituting the board of directors shall be determined by resolution of the board ofdirectors, but no decrease in the number of directors shall have the effect of shortening the termof any incumbent director. Newly created directorships resulting from any increase in theauthorized number of directors or any vacancies in the board of directors resulting from death,resignation, retirement, disqualification, removal from office or other cause may be filled by theaffirmative vote of a majority of the remaining directors then in office, regardless of whether thatmajority is less than a quorum, and directors so chosen shall hold office until the expiration of3 the term of office of the director whom he or she has replaced or until his or her successor shallbe elected and qualified. A director elected to fill a vacancy is elected for the unexpired term ofthe member's predecessor in office.(b) Meetings; Quorum. Meetings of the board of directors shall be held at the timeand place fixed by resolution of the board of directors or upon the call of the chairman of theboard or the president. The secretary or officer performing his duties shall give two days' noticeof all meetings of directors by mail or telegram to the last known address of each director, or, onconsent of a director, by electronic transmission, provided that a meeting may be held withoutnotice immediately after the annual election, and notice need not be given of regular meetingsheld at such time as may be fixed by a resolution of the board. Meetings of the directors may beheld at any time without notice if all directors are present or if those not present waive noticeeither before or after the meeting. At any meeting of directors a majority of the whole number ofdirectors shall constitute a quorum, but less than a quorum shall have power to adjourn themeeting from time to time.SECTION 13. OFFICERS. Each year, the board of directors may elect one of their numberchairman of the board, shall elect a president of the Corporation, shall elect one or more vicepresidents, a secretary and a treasurer, and may elect one or more assistant secretaries andassistant treasurers and such other officers as they may from time to time deem proper. The sameperson may be elected to and hold more than one office, except that the president and thesecretary shall not be the same person* The term of office of all officers shall be one year, oruntil their respective successors are chosen and qualified, but any officer may be removed fromoffice for or without cause at any time by the board of directors. Whenever any vacancy shalloccur in any office by death, resignation, increase in the number of offices of the Corporation, orotherwise, the same shall be filled by the board of directors, and the officer so elected shall holdoffice until his successor is chosen and qualified. The officers of the Corporation shall have suchpowers and duties as usually pertain to their offices, respectively, as well as such powers andduties as may from time to time be conferred by the board of directors.SECTION 14. COMMITTEES. The board of directors may establish committees, each committeeto consist of one or more directors, which committees shall have such power and authority andshall perform such functions as may be provided in such resolution. Unless the chair is appointedby the board, each committee shall designate a chair by majority vote of the committee. Eachcommittee may make rules for the conduct of its business as it may deem necessary. A majorityof the members of each committee shall constitute a quorum. Each committee shall act only onthe affirmative vote of a majority of the members present at a meeting.SECTION 15. INSURANCE, INDEMNIFICATION AND OTHER ARRANGEMENTS. Without furtherspecific approval of the shareholders of the Corporation, the Corporation may purchase, enterinto, maintain or provide insurance, indemnification or other arrangements for the benefit of anyperson who is or was a director, officer, employee or agent of the Corporation or is or wasserving another entity at the request of the Corporation as a director, officer, manager, member,partner, venturer, proprietor, trustee, employee, agent or similar functionary, to the fullest extentpermitted by the laws of the State of Texas, including without limitation Chapter 8 of the TexasBusiness Organizations Code or any successor provision, against any liability asserted against orincurred by any such person in any such capacity or arising out of such person's service in such4 capacity whether or not the Corporation would otherwise have the power to indemnify againstany such liability under the Texas Business Organizations Code. If the laws of the State of Texasare amended to authorize the purchase, entering into, maintaining or providing of insurance,indemnification or other arrangements in the nature of those permitted hereby to a greater extentthan presently permitted, then the Corporation shall have the power and authority to purchase,enter into, maintain and provide any additional arrangements in such regard as shall be permittedfrom time to time by the laws of the State of Texas without further approval of the shareholdersof the Corporation. No repeal or modification of such laws or this Section 15 shall adverselyaffect any such arrangement or right to indemnification existing at the time of such repeal ormodification.SECTION 16. COMPENSATION OF DIRECTORS. The board of directors shall have power toauthorize the payment of compensation to the directors for services to the Corporation, includingfees for attendance at meetings of the board of directors, committees, and to determine theamount of such compensation and fees.SECTION 17. AMENDMENT OF BYLAWS. These bylaws may be altered, changed or amended asprovided by statute, or at any meeting of the board of directors by affirmative vote of a majorityof all of the directors.June 4, 20125 RESTATED CERTIFICATE OF FORMATIONOFENERGY FUTURE HOLDINGS CORP.ARTICLE I.The name of the corporation is Energy Future Holdings Corp. (the "Corporation").ARTICLE II.The Corporation is a for-profit corporation.ARTICLE III.The purposes for which the Corporation is formed are all lawful purposes for which for-profitcorporations may be formed under the Texas Business Organizations Code (the "TBOC").ARTICLE IV.The street address of the registered office of the Corporation is 350 North St. Paul Street, Dallas,Texas 75201, and the name of its registered agent at such address is CT Corporation System.ARTICLE V.The number of directors currently constituting the board of directors is fourteen, and the namesand addresses of the persons who are to serve, as directors until the next annual meeting of shareholdersor until their successors are elected and qualified are as follows:NameAddressDavid BondermanDonald L. EvansSteven FeldmanFrederick M. GoltzJames R. HuffinesScott LebovitzJeffrey LiawMarc S. LipschultzMichael MacDougallLyndon L. OlsonKenneth PontarelliWilliam K. ReillyJonathan D. SmidtKneeland Youngblood1601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas; Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 75201160i Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 752011601 Bryan St., Dallas, Texas 75201 ARTICLE VI.1. Authorized Capital. The Corporation is authorized to issue one class of stock to bedesignated "Common Stock," without par value. The total number of shares which the Corporation isauthorized to issue is 2,000,000,000.2. Stock Split. Effective as of the effectiveness of this Restated Certificate of Formationpursuant to Section 3.063(c) of the TBOC (the "Effective Time"), and without any further action on thepart of the Corporation or its shareholders, each share of Common Stock issued and outstanding at suchtime shall be and hereby is automatically reclassified, changed and converted into 1,760,000 shares ofCommon Stock without any action by the holder thereof. Such reclassification, change and conversionshall not change the par value of the Common Stock.ARTICLE VII.Any action required by the TBOC to be taken at any annual or special meeting of shareholders, orany action which may be taken at any annual or special meeting of shareholders, may be taken without ameeting, without prior notice, and without a vote, if a consent or consents in writing, setting forth theaction so taken, shall be signed by the holders of shares having not less than the minimum number ofvotes that would be necessary to take such action at a meeting at which the holders of all shares entitledto vote on the action were present and voted. Prompt notice of the taking of any action by shareholderswithout a meeting by less than unanimous written consent shall be given to those shareholders who did:not consent in writing to the taking of such action.ARTICLE VIII.No shareholder shall have any preemptive right to acquire any proportional amounts of theCorporation's unissued or treasury shares on the decision of the board of directors to issue such shares.ARTICLE IX.1. Right to Indemnification. Subject to the limitations and conditions as provided in this'Article IX, each person who was or is made a party or is threatened to be made a party to or is involved inany threatened, pending or completed action or other proceeding, whether civil, criminal, administrative,arbitrative or investigative, or any appeal in such a proceeding or any inquiry or investigation that couldlead to such a proceeding (hereinafter a "proceeding"), by reason of the fact that he or she, or a person ofwhom he or she is the legal representative, is or was a director or officer of the Corporation or while adirector or officer of the Corporation is or was serving at the request of the Corporation as a director,:officer, partner, venturer, proprietor, trustee, employee, agent, or similar functionary of another foreignor domestic corporation, limited liability company, partnership, joint venture, sole proprietorship, trust,employee benefit plan or other enterprise shall be indemnified by the Corporation to the fullest extentpermitted by the TBOC, as the same exists or may hereafter be amended against judgments, penalties(including excise and similar taxes and punitive damages), fines, settlements and reasonable expenses(including, without limitation, attomeys' fees) actually incurred by such person in connection with suchproceeding, and indemnification under this Article IX shall continue as to a person who has ceased to:serve in the capacity which initially entitled such person to indemnity hereunder. The rights grantedpursuant to this Article IX shall be deemed contract rights, and no amendment, modification or repeal ofthis Article IX shall have the effect of limiting or denying any such rights with respect to actions taken or.proceedings arising prior to any such amendment, modification or repeal. It is expressly acknowledgedthat the indemnification provided in this Article IX could involve indemnification for negligence or undertheories of strict liability.2

2. Advancement of Expenses. The right to indemnification conferred in this Article IX shallinclude the right to be paid or reimbursed by the Corporation the reasonable expenses incurred by aperson of the type entitled to be indemnified above who was, is or is threatened to be made a nameddefendant or respondent in a proceeding in advance of the final disposition of the proceeding andwithout any determination as to the person's ultimate entitlement to indemnification; provided, however,that the payment of such expenses incurred by any such person in advance of the final disposition of aproceeding shall be made only upon delivery to the Corporation of a written affirmation by suchindemnified person of his or her good faith belief that he or she has met the standard of conductnecessary for indemnification under this Article IX and a written undertaking, by or on behalf of suchperson, to repay all amounts so advanced if it shall ultimately be determined that such indemnifiedperson is not entitled to be indemnified under this Article IX or if such indemnification is prohibited byapplicable law.3. Indemnification of Employees and Agents. The Corporation, by adoption of a resolution bythe board of directors or a duly appointed committee of the board of directors, may indemnify andadvance expenses to an employee or agent of the Corporation to the same extent and subject to the sameconditions under which it may indemnify and advance expenses to directors and officers under thisArticle IX; and the Corporation, by adoption of a resolution by the board of directors or a duly appointedcommittee of the board of directors, may indemnify and advance expenses to persons who are not orwere not directors, officers, employees or agents of the Corporation but who are or were serving at therequest of the Corporation as a director, officer, manager, member, partner, venturer, proprietor, trustee,employee, agent or similar functionary of another foreign or domestic corporation, limited liabilitycompany, partnership, joint venture, sole proprietorship, trust, employee benefit plan or other enterpriseagainst any liability asserted against him or her and incurred by him or her in such a capacity or arisingout of his or her status as such. a person to the same extent that it may indemnify and advance expenses to* directors and officers under this Article IX.4. Appearance as a -Witness. Notwithstanding any other provision of this Article IX, theCorporation may pay or reimburse expenses incurred by a 'director, officer, employee, agent or otherperson in connection with his or her appearance as a witness or other participation in a proceeding at atime when he or she is not a named defendant or respondent in the proceeding.5. Nonexclusivity of Rights. The right to indemnification and the advancement and paymentof expenses conferred in this Article IX shall not be exclusive of any other right which a director or officer,or other person indemnified pursuant to this Article IX may have or hereafter acquire under any law(common or statutory), provision of this certificate of formation or the bylaws of the Corporation,agreement, vote of shareholders or disinterested directors or otherwise.6. Insurance. The Corporation may purchase, procure, establish and maintain, at its.expense, insurance or another arrangement to indemnify or hold harmless, to protect itself and anyperson who is or was serving as a director, officer, employee or agent of the Corporation or is or wasserving at the request of the Corporation as a director, officer, manager, member, partner, venturer,proprietor, trustee, employee, agent or similar functionary of another foreign or domestic corporation,.limited liability company, partnership, joint venture, proprietorship, employee benefit plan, trust or otherenterprise against any expense, liability or loss, whether or not the Corporation would have the power toindemnify such person against such expense, liability or loss under this Article IX.7. Savings Clause. If this Article IX or any portion hereof shall be invalidated on any groundby any court of competent jurisdiction, then the Corporation shall nevertheless indemnify and holdharmless each director, officer or any other person indemnified pursuant to this Article IX as to costs,charges and expenses (including attorneys' fees), judgments, fines and amounts paid in settlement with3 respect to any action, suit or proceeding, whether civil, criminal, administrative or investigative to the fullextent permitted by any applicable portion of this Article DC that shall not have been invalidated and tothe fullest extent permitted by applicable law.For purposes of this Article IX, the term "Corporation" shall include any predecessor of theCorporation and any constituent corporation (including any constituent of a constituent) absorbed by theCorporation in a consolidation or merger; the term "other enterprise" shall include any corporation,limited liability company, partnership, joint venture, trust or employee benefit plan; service "at therequest of the Corporation" shall include service as a director, officer, manager, member or employee ofthe Corporation which imposes duties on, or involves services by, such director, officer, manager,member or employee with respect to an employee benefit plan, its participants or beneficiaries; any excisetaxes assessed on a person with respect to an employee benefit plan shall be deemed to be indemnifiableexpenses; and action by a person with respect to an employee benefit plan which such person reasonablybelieves to be in the interest of the participants and beneficiaries of such plan shall be deemed to be actionnot opposed to the best interests of the Corporation.ARTICLE X.A director of the Corporation shall .not be liable to the Corporation or its shareholders formonetary damages for any act or omission in -the director's capacity as a director, except that thisprovision does not eliminate or limit the liability of a director to the extent the director is found liableunder applicable law for:(a) a breach of the director's duty of loyalty to the Corporation or its shareholders;(b) an act or omission not in good faith that constitutes a breach of duty of thedirector to the Corporation or that involves intentional misconduct or a knowing violation of the law;(c) a transaction from which the director received. an improper benefit, regardless ofwhether the benefit resulted from an action taken within the scope of the director's duties; or(d) an act or omission for which the liability of the director is expressly provided forby an applicable statute.If the TBOC is amended to authorize action further eliminating or limiting the personal,liability of directors, then the liability of a director of the Corporation shall be eliminated or limited to thefullest extent permitted by the TBOC as so amended. Any repeal or modification of this Article X shallnot adversely affect any right of protection of a director of the Corporation existing at the time of suchrepeal or modification.ARTICLE XI.The bylaws of the Corporation may be altered, changed or amended as provided by statute, or atany meeting of the board of directors by affirmative vote of a majority of all of the directors.ARTICLE XII.A. Certain Definitions. For purposes of this Article XII, (i) "Affiliate" of any Person shall include anyprincipal, member, director, partner, shareholder, officer, employee or other representative of any Personthat, directly or indirectly, is controlled by such Person, controls such Person or is under common controlwith such Person (other than the Corporation and any entity that is controlled by the Corporation) or any4 Person that, directly or indirectly, is controlled by such Person, controls such Person or is under commoncontrol with such Person, (ii) "Person" shall mean any individual, corporation, general or limitedpartnership, limited liability company, joint venture, trust, association or any other entity and (iii)"Sponsor-Affiliates" shall mean Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., Goldman, Sachs &Co. and each of their respective Affiliates.B. Certain Activities. In anticipation of the benefits to be derived by the Corporation through itscontinued contractual, corporate and business relationships with the Sponsor-Affiliates and inanticipation and recognition that (i) certain directors, principals, officers, employees and/or otherrepresentatives of Sponsors-Affiliates may serve as directors or officers of the Corporation, (ii) theSponsor-Affiliates may now engage and may continue to engage in the same or similar activities orrelated lines of business as those in which the Corporation, directly or indirectly, may engage and/orother business activities that overlap with or compete with those in which the Corporation, directly orindirectly, may engage, and (iii) members of the Board of Directors who are not employees of theCorporation ("Non-Employee Directors") and their respective Affiliates may now engage and maycontinue to engage in the same or similar activities or related lines of business as those in which theCorporation, directly or indirectly, may engage and/or other business activities that overlap with orcompete with those in which the Corporation, directly or indirectly, may engage, the provisions of thisArticle XII are set forth to define the circumstances in which the fiduciary duties of the Non-EmployeeDirectors and the Sponsor-Affiliates would not be breached even if certain classes or categories ofbusiness opportunities are alleged to have been usurped by one or more of the Sponsor-Affiliates, theNon-Employee Directors or their respective Affiliates.C. Certain Transactions. None of (i) any Sponsor-Affiliate or (ii) any Non-Employee Director or hisor her Affiliates (any such Person identified in clause (i) or (ii), an "Identified Person") shall be in breachof a fiduciary duty for failing to refrain from directly or indirectly (A) engaging in a corporateopportunity in the same or similar business activities or lines of business in which the Corporation or anyof its Affiliates has a reasonable expectancy interest or property right or (B) otherwise competing with theCorporation. For the avoidance of doubt, to the extent that any purchase, sale or other transaction by anyIdentified Person involving any securities or indebtedness of the Corporation or any of its Affiliates (orinvolving any hedge, swap, derivative or other instrument relating to or in respect of any of the foregoingsecurities or indebtedness) may deemed to be a corporate opportunity or to be in competition with theCorporation, the Identified Persons shall be fully protected by the foregoing provisions of this Article XIIin pursuing such purchase, sale or other transaction or in taking any other action in respect of or affectingsuch securities, indebtedness or other instrument. The Corporation hereby renounces any reasonableexpectancy interest or property right in any business opportunity which may be a corporate opportunityfor both an Identified Person and the Corporation or any of its Affiliates, except as provided in paragraphD of this Article XII. In the event that any Identified Person acquires knowledge of a potential transactionor other business opportunity which may be a corporate opportunity for itself, himself or herself and theCorporation or any of its Affiliates, such Identified Person would not be in breach of a fiduciary duty forfailing to communicate or offer such transaction or other business opportunity to the Corporation or anyof its Affiliates. To the fullest extent permitted by law, no Identified Person can be held individuallyliable to the Corporation or its stockholders or creditors for any damages as a result of engaging in any ofactivities permitted pursuant to this paragraph C.D. Usurping Certain Corporate Opportunities Are Breadces of Fiduciary Duty. The Corporation does notrenounce its expectancy interest or property right in any corporate opportunity offered to any Non-Employee. Director (including any Non-Employee Director who serves as an officer of the Corporation) ifsuch opportunity is expressly offered to such person solely in his or her capacity as a director or officer ofthe Corporation and the provisions of paragraph C of Article XII shall not apply to any such corporateopportunity.5 E. Exclusion. In addition to and without limiting the foregoing provisions of this Article XII, acorporate opportunity shall not be deemed to be a potential corporate opportunity for the Corporation ifthe Corporation is not financially capable or contractually permitted or legally able to undertake it, or if itis, from its nature, not in the line of the Corporation's business or is of no practical advantage to it or it isone in which the Corporation has no reasonable expectancy interest of property right.6 Table of ContentsUNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K[El ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012-OR-0 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Commission File Number 1-12833Energy Future Holdings Corp.(Exact name of registrant as specified in its charter)Texas 75-2669310(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)1601 Bryan Street, Dallas, TX 75201-3411 (214) 812-4600(Address of principal executive offices) (Zip Code) (Registrant's telephone number, including area code)Securities registered pursuant to Section 12(b) of the Act:Title of Each Class Name of Each Exchange on Which Registered9.75% Senior Notes due 2019 New York Stock ExchangeSecurities registered pursuant to Section 12(g) of the Act: NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 0 No 0Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes 0 No [9lIndicate by check mark whether the registrant (I) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Actof 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subjectto such filing requirements for the past 90 days. Yes HI No 0Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive DataFile required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (orfor such shorter period that the registrant was required to submit and post such files). Yes [El No 0Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein,and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in PartIII of this Form 10-K or any amendment to this Form 10-K. [ElIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reportingcompany. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.Large accelerated filer 0 Accelerated filer 0 Non-Accelerated filer E0 (Do not check if a smaller reporting company)Smaller reporting company 03Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes 0 No 0At February 19, 2013, there were 1,681,031,995 shares of common stock, without par value, outstanding of Energy Future Holdings Corp.(substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.'s parent holdingcompany, and none of which is publicly traded).DOCUMENTS INCORPORATED BY REFERENCENone Table of ContentsTABLE OF CONTENTSPAGEGlossary iiPART IItems 1. and 2. BUSINESS AND PROPERTIES 1Item IA. RISK FACTORS 20Item lB. UNRESOLVED STAFF COMMENTS 40Item 3. LEGAL PROCEEDINGS 40Item 4. MINE SAFETY DISCLOSURES 41PART I1Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERMATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 42Item 6. SELECTED FINANCIAL DATA 42Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 44RESULTS OF OPERATIONSItem 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 88Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 95Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING 177AND FINANCIAL DISCLOSUREItem 9A. CONTROLS AND PROCEDURES 177Item 9B. OTHER INFORMATION 178PART IIIItem 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 179Item 11. EXECUTIVE COMPENSATION 185Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENTAND RELATED STOCKHOLDER MATTERS 213Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORINDEPENDENCE 216Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 220PART IVItem 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 228Energy Future Holdings Corp.'s (EFH Corp.) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports onForm 8-K and any amendments to those reports are made available to the public, free of charge, on the EFH Corp. website athttp://www.energyfzitureholdings. corn, as soon as reasonably practicable after they have been filed with or furnished to the Securitiesand Exchange Commission. The information on EFH Corp.'s website shall not be deemed a part of, or incorporated by referenceinto, this annual report on Form 10-K. The representations and warranties contained in any agreement that we have filed as anexhibit to this annual report on Form 10-K or that we have or may publicly file in the future may contain representations andwarranties made by and to the parties thereto at specific dates. Such representations and warranties may be subject to exceptionsand qualifications contained in separate disclosure schedules, may represent the parties' risk allocation in the particular transaction,or may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.This annual report on Form 10-K and other Securities and Exchange Commission filings of EFH Corp. and its subsidiariesoccasionally make references to EFH Corp. (or "we," "our," "us" or "the company"), EFCH, EFIH, TCEH, TXU Energy, Luminant,Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflectthe fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statementsfor financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actuallyundertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.i Table of ContentsGLOSSARYWhen the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.2011 Form 10-KAdjusted EBITDAancillary servicesCAIRCFTCCO2CPNPCEFH Corp.'s Annual Report on Form 10-K for the year ended December 31, 2011Adjusted EBITDA means EBITDA adjusted to exclude noncash items, unusual items andother adjustments allowable under certain of our debt arrangements. See the definition ofEBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under US GAAPand, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in thisForm 10-K (see reconciliations in Exhibits 99(b), 99(c) and 99(d)) solely because of theimportant role that Adjusted EBITDA plays in respect of certain covenants contained in ourdebt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternativeto net income as a measure of operating performance or an alternative to cash flows fromoperating activities as a measure of liquidity or an alternative to any other measure of financialperformance presented in accordance with US GAAP. Additionally, we do not intend forAdjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available formanagement's discretionary use, as the measure excludes certain cash requirements such asinterest payments, tax payments and other debt service requirements. Because not allcompanies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA)may not be comparable to similarly titled measures of other companies.Refers to services necessary to support the transmission of energy and maintain reliableoperations for the entire transmission system. These services include monitoring andproviding for various types of reserve generation to ensure adequate electricity supply andsystem reliability.Clean Air Interstate RuleUS Commodity Futures Trading Commissioncarbon dioxideRefers to Comanche Peak Nuclear Power Company LLC, which was formed bysubsidiaries of TCEH (holding an 88% equity interest) and Mitsubishi Heavy IndustriesLtd. (MHI) (holding a 12% equity interest) for the purpose of developing two new nucleargeneration units and obtaining a combined operating license from the NRC for the units.the EFH Corp. business segment that consists principally of TCEHCompetitive Renewable Energy Zonethe final Cross-State Air Pollution Rule issued by the EPA in July 2011 and vacated by theUS Court of Appeals for the District of Columbia Circuit in August 2012 (see Note 3 toFinancial Statements)US Department of Energyearnings (net income) before interest expense, income taxes, depreciation and amortizationEnergy Future Competitive Holdings Company, a direct, wholly-owned subsidiary of EFHCorp. and the direct parent of TCEH, and/or its subsidiaries, depending on contextEnergy Future Holdings Corp., a holding company, and/or its subsidiaries, depending oncontext, whose major subsidiaries include TCEH and OncorRefers, collectively, to EFH Corp.'s 10.875% SeniorNotes due November 1,2017 (EFH Corp.10.875% Notes) and EFH Corp.'s 11.25%/12.00% Senior Toggle Notes due November 1,2017 (EFH Corp. Toggle Notes).Refers, collectively, to EFH Corp.'s 9.75% Senior Secured Notes due October 15, 2019 (EFHCorp. 9.75% Notes) and EFH Corp.'s 10.000% Senior Secured Notes due January 15, 2020(EFH Corp. 10% Notes).Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary ofEFH Corp. and the direct parent of Oncor HoldingsEFIH Finance Inc., a direct, wholly-owned subsidiary of EFIH, formed for the sole purposeof serving as co-issuer with EFIH of certain debt securitiesCompetitive Electric segmentCREZCSAPRDOEEBITDAEFCHEFH Corp.EFH Corp. Senior NotesEFH Corp. Senior SecuredNotesEFIHEFIH Financeii Table of ContentsEFIH NotesEPAERCOTERISAFERCGAAPGHGGWhIRSkWhLIBORLuminantRefers, collectively, to EFIH's and EFIH Finance's 6.875% Senior Secured Notes due August15, 2017 (EFIH 6.875% Notes), 9.75% Senior Secured Notes due October 15, 2019 (EFIH9.75% Notes), 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% Notes),S1I% Senior Secured Second Lien Notes due October 1, 2021 (EFIH 11% Notes), 11.75%Senior Secured Second Lien Notes due March 1, 2022 (EFIH 11.75% Notes) andI 1.25%/12.25% Senior Toggle Notes due December 1, 2018 (EFIH Toggle Notes).US Environmental Protection AgencyElectric Reliability Council of Texas, Inc., the independent system operator and the regionalcoordinator of various electricity systems within TexasEmployee Retirement Income Security Act of 1974, as amendedUS Federal Energy Regulatory Commissiongenerally accepted accounting principlesgreenhouse gasgigawatt-hoursUS Internal Revenue Servicekilowatt-hoursLondon Interbank Offered Rate, an interest rate at which banks can borrow funds, inmarketable size, from other banks in the London interbank marketsubsidiaries of TCEH engaged in competitive market activities consisting of electricitygeneration and wholesale energy sales and purchases as well as commodity risk managementand trading activities, all largely in TexasHeat rate is a measure of the efficiency of converting a fuel source to electricity. Market heatrate is the implied relationship between wholesale electricity prices and natural gas prices andis calculated by dividing the wholesale market price of electricity, which is based on the priceoffer of the marginal supplier in ERCOT (generally natural gas plants), by the market priceof natural gas. Forward wholesale electricity market price quotes in ERCOT are generallylimited to two or three years; accordingly, forward market heat rates are generally limited tothe same time period. Forecasted market heat rates for time periods for which market pricequotes are not available are based on fundamental economic factors and forecasts, includingelectricity supply, demand growth, capital costs associated with new construction of generationsupply, transmission development and other factors.the Mercury and Air Toxics Standard finalized by the EPA in December 2011 and publishedin February 2012The transaction referred to in the Agreement and Plan of Merger, dated February 25, 2007,under which Texas Holdings agreed to acquire EFH Corp., which was completed on October10, 2007.market heat rateMATSMergerMMBtuMoody'sMWMWhNERCmillion British thermal unitsNOxMoody's Investors Services, Inc. (a credit rating agency)megawattsmegawatt-hoursNorth American Electric Reliability Corporationnitrogen oxidesUS Nuclear Regulatory Commissionthe New York Mercantile Exchange, a physical commodity futures exchangeOncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of OncorHoldings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remotefinancing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending oncontext, that is engaged in regulated electricity transmission and distribution activitiesNRCNYMEXOncoriii Table of ContentsOncor HoldingsOncor Ring-Fenced EntitiesOPEBPUCTPURApurchase accountingRegulated Delivery segmentREPRRCS&PSECSecurities ActSG&ASO,Sponsor GroupOncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIHand the direct majority owner of Oncor, and/or its subsidiaries, depending on contextOncor Holdings and its direct and indirect subsidiaries, including Oncorother postretirement employee benefitsPublic Utility Commission of TexasTexas Public Utility Regulatory ActThe purchase method of accounting for a business combination as prescribed by US GAAP,whereby the cost or "purchase price" of a business combination, including the amount paidfor the equity and direct transaction costs are allocated to identifiable assets and liabilities(including intangible assets) based upon their fair values. The excess of the purchase priceover the fair values of assets and liabilities is recorded as goodwill.the EFH Corp. business segment that consists primarily of our investment in Oncorretail electric providerRailroad Commission of Texas, which among other things, has oversight of lignite miningactivity in TexasStandard & Poor's Ratings Services, a division of the McGraw-Hill Companies Inc. (a creditrating agency)US Securities and Exchange CommissionSecurities Act of 1933, as amendedselling, general and administrativesulfur dioxideRefers, collectively, to certain investment funds affiliated with Kohlberg Kravis Roberts &Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GS Capital Partners, anaffiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Holdings.Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary ofEFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context,that are engaged in electricity generation and wholesale and retail energy markets activities,and whose major subsidiaries include Luminant and TXU EnergyRefers to certain loans from TCEH to EFH Corp. in the form of demand notes to finance EFHCorp. debt principal and interest payments and, until April 2011, other general corporatepurposes of EFH Corp., that are guaranteed on a senior unsecured basis by EFCH and EFIH.TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purposeof serving as co-issuer with TCEH of certain debt securitiesRefers, collectively, to TCEH's and TCEH Finance's 10.25% Senior Notes due November 1,2015 and 10.25% Senior Notes due November 1, 2015, Series B (collectively, TCEH 10.25%Notes) and TCEH's and TCEH Finance's 10.50%/11.25% Senior Toggle Notes due November1, 2016 (TCEH Toggle Notes).Refers, collectively, to the TCEH Term Loan Facilities, TCEH Revolving Credit Facility,TCEH Letter of Credit Facility and, until it expired on December 31,2012, TCEH CommodityCollateral Posting Facility. See Note 8 to Financial Statements for details of these facilities.TCEH's and TCEH Finance's 11.5% Senior Secured Notes due October 1, 2020Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notesdue April 1, 2021 and TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notesdue April 1, 202 1, Series B.Texas Commission on Environmental QualityTexas Energy Future Holdings Limited Partnership, a limited partnership controlled by theSponsor Group, that owns substantially all of the common stock of EFH Corp.TCEHTCEH Demand NotesTCEH FinanceTCEH Senior NotesTCEH Senior SecuredFacilitiesTCEH Senior Secured NotesTCEH Senior Secured SecondLien NotesTCEQTexas Holdingsiv Table of ContentsTexas Holdings GroupTexas TransmissionTRETexas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-FencedEntitiesTexas Transmission Investment LLC, a limited liability company that owns a 19.75% equityinterest in Oncor and is not affiliated with EFH Corp., any of EFH Corp.'s subsidiaries or anymember of the Sponsor GroupTexas Reliability Entity, Inc., an independent organization that develops reliability standardsfor the ERCOT region and monitors and enforces compliance with NERC standards andERCOT protocolsTXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH that is a REPin competitive areas of ERCOT and is engaged in the retail sale of electricity to residentialand business customersTXU EnergyUsVIEUnited States of Americavariable interest entityv Table of ContentsPART I.Items 1. and 2. BUSINESS AND PROPERTIESReferences in this report to "we," "our," "us" and "the company" are to EFH Corp. and/or its subsidiaries, as apparent in thecontext. See "Glossary" for descriptions of major subsidiaries and other defined terms.EFH Corp. Business and StrategyWe are a Dallas, Texas-based energy company with a portfolio of competitive and regulated energy businesses in Texas.EFH Corp. is a holding company conducting its operations principally through its TCEH and Oncor subsidiaries. EFCH and itsdirect subsidiary, TCEH, are wholly-owned. EFIH is wholly-owned and indirectly holds an approximate 80% equity interest inOncor. Immediately below is an organization chart of the key subsidiaries discussed in this report.EFCH's principal asset is its investment in TCEH. EFCH is a guarantor of a significant portion of TCEH's debt and $60million principal amount of EFH Corp.'s debt.TCEH, through its subsidiaries, is engaged in competitive electricity market activities largely in Texas including electricitygeneration, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales.TCEH owns or leases 15,427 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. TCEH is also one of the largest purchasers of wind-generated electricity in Texas and the US. TCEHprovides competitive electricity and related services to 1.75 million retail electricity customers in Texas.EFIH's principal assets consist of its investment in Oncor Holdings, the principal asset of which is an 80% equity interestin Oncor. EFIH is also a guarantor of $60 million principal amount of EFH Corp.'s debt.Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated bythe PUCT and, in certain instances, the FERC. Oncor provides transmission and distribution services to REPs, which sell electricityto residential and business consumers, as well as transmission services to other electricity distribution companies, cooperativesand municipalities. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to more than3.2 million homes and businesses and operating more than 119,000 miles of transmission and distribution lines. A significantportion of Oncor's revenues represent fees for services provided to TCEH. Revenues from services provided to TCEH represented29% and 33% of Oncor's total reported consolidated revenues for the years ended December 31, 2012 and 2011, respectively.I Table of ContentsEFH Corp. and Oncor have implemented certain structural and operational "ring-fencing" measures based on commitmentsmade by Texas Holdings and Oncor to the PUCT to further enhance the credit quality of Oncor Holdings and Oncor. Thesemeasures serve to mitigate Oncor's and Oncor Holdings' credit exposure to the Texas Holdings Group with the intent to minimizethe risk that a court would order any of the assets and liabilities of the Oncor Ring-Fenced Entities to be substantively consolidatedwith the assets and liabilities of any member of the Texas Holdings Group in the event any such member were to become a debtorin a bankruptcy case. Accordingly, EFH Corp. and EFIH do not control and do not consolidate Oncor Holdings and Oncor forfinancial reporting purposes. See Notes I and 2 to Financial Statements for a description of the material features of these "ring-fencing" measures.At December 31, 2012, we had approximately 9,100 full-time employees (including approximately 3,500 at Oncor).Approximately 2,840 employees:are under collective bargaining agreements (including approximately 790 at Oncor).EFH Corp.'s MarketWe operate primarily within the ERCOT market. This market represents approximately 85% of the electricity consumptionin Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the IndependentSystem Operator (ISO) of the interconnected transmission grid for those systems. ERCOT's membership consists of approximately300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators,independent power marketers, investor-owned utilities, REPs and consumers.The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over theERCOT market to ensure adequacy and reliability of power supply across Texas' main interconnected transmission grid. TheERCOT ISO is responsible for scheduling power on the grid and maintaining reliable operations of the electricity supply systemin the market. Its responsibilities include centralized dispatch of the power pool and ensuring that electricity production anddelivery are accurately accounted for among the generation resources and wholesale buyers and sellers. The ERCOT ISO alsoserves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.Significant changes in the operations of the wholesale electricity market resulted from the change from a zonal to a nodalmarket implemented by ERCOT in December 2010. The nodal market design resulted in a substantial increase in the number ofsettlement price points for participants and established a new "day-ahead market," operated by ERCOT, in which participants canenter into forward sales and purchases of electricity. The nodal market also established hub trading prices, which represent theaverage of node prices within geographic regions, at which participants can hedge and trade power through bilateral transactionsand established congestion revenue rights, which are financial instruments auctioned by ERCOT that allow participants to hedgeprice differences between settlement points. See Item 7, "Management's Discussion and Analysis of Financial Condition andResults of Operations -Significant Activities and Events and Items Influencing Future Performance -Wholesale Market Design-Nodal Market" for additional discussion of the ERCOT nodal market.Oncor, along with other ow ners of transmission and distribution facilities in Texas, assists the ERCOT ISO in its operations.Oncor has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid andfor the load-serving substations it owns, primarily within its certificated distribution service area. Oncor participates with theERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing and constructing newtransmission lines in order to remove existing constraints on the ERCOT transmission grid. The new transmission lines arenecessary to meet reliability needs, support renewable energy production and increase bulk power transfer capability.The following data is derivIed from information published by ERCOT:Installed generation capacity in the ERCOT market for the year 2012 totaled approximately 84,500 MW, includingapproximately 2,900 MW mothballed (idled) capacity and more than 10,000 MW of wind and other resources that may not beavailable coincident with system need. Texas has more installed wind generation capacity than any other state in the US. In 2012,ERCOT's hourly demand peaked at 66,548 MW, which was less than the record peak demand of 68,305 MW in 2011. Of ERCOT'stotal installed capacity, approximately 59% is natural gas-fueled generation, approximately 28% is lignite/coal and nuclear-fueledgeneration and approximately 13% is wind and other renewable resources. In November 2010, ERCOT changed its minimumreserve margin planning criterion'to 13.75% from 12.5%. In December 2012, ERCOT projected the reserve margin for the summerpeak load period to be 13.2% in 2013, 10.9% in 2014, and 10.5% in 2015. Reserve margin represents the percentage by whichsystem generation capacity exceeds anticipated peak load. See Item 7, "Management's Discussion and Analysis of FinancialCondition and Results of Operations -Key Risks and Challenges -Declining Reserve Margins and Weather Extremes."2 Table of ContentsThe ERCOT market has limited interconnections to other markets in the US and Mexico, which currently limits potentialimports into and exports out of the ERCOT market to 1,106 MW of generation capacity (or approximately 2% of peak demand).In addition, wholesale transactions within the ERCOT market are generally not subject to regulation by the FERC.Natural gas-fueled generation is the predominant electricity capacity resource (approximately 59%) in the ERCOT marketand accounted for approximately 45% of the electricity produced in the ERCOT market in 2012. Because of the significant amountof natural gas-fueled capacity and the ability of such facilities to more readily increase or decrease production when compared tonuclear and lignite/coal-fueled generation, marginal demand for electricity is usually met by natural gas-fueled facilities. As aresult, wholesale electricity prices in ERCOT have generally moved with natural gas prices.EFH Corp.'s StrategiesEach of our businesses focuses its operations on key safety, reliability, economic and environmental drivers for that business,as described below:" TCEH focuses on optimizing and developing its generation fleet to safely provide reliable electricity supply in a cost-effective manner and in consideration of environmental impacts, hedging its commodity price and volume exposureand providing high quality service and innovative energy products to retail and wholesale customers." Oncor focuses on delivering electricity in a safe and reliable manner, minimizing service interruptions and investingin its transmission and distribution infrastructure to maintain its system, serve its growing customer base with amodernized grid and support renewable energy production.Other elements of our strategies include:" Increase value from existing business lines. We strive for top-tier performance across our operations in terms ofsafety, reliability, cost and customer service. In establishing strategic objectives, we incorporate the following coreoperating principles:" Safety: Placing the safety of communities, customers and employees first;" Environmental Stewardship: Continuing to make strategic and operational improvements that lead to cleaner air,land and water;* Customer Focus: Delivering products and superior service to help customers more effectively manage their useof electricity;* Community Focus: Being an integral part of the communities in which we live, work and serve;* Operational Excellence: Incorporating continuous improvement and financial discipline in all aspects of thebusiness to achieve top-tier results that maximize the value of the company for stakeholders, including operatingworld-class facilities that produce and deliver safe and dependable electricity at affordable prices, and* Performance-Driven Culture: Fostering a strong values- and performance-based culture designed to attract,develop and retain best-in-class talent." Drive and support growth of the ERCOT market. We expect to pursue growth opportunities across our existingbusiness lines, including:" Pursuing generation development opportunities to help meet ERCOT's growing electricity needs over the longerterm from a diverse range of energy sources such as natural gas, nuclear and renewable energy." Working with ERCOT and other market participants to develop policies and protocols that provide appropriatepricing signals that encourage the development of new generation to meet growing electricity demand in theERCOT market." Profitably increasing the number of retail customers served throughout the competitive ERCOT market areas bydelivering superior value through high quality customer service and innovative energy products, including leadingenergy efficiency initiatives and service offerings." Investing in transmission and distribution, including advanced metering systems initiatives, and constructing newtransmission and distribution facilities to meet the needs of the growing Texas market.3 Table of Contents" Manage exposure to wholesale electricity price volatility. We actively manage our exposure to wholesale electricityprices in ERCOT through contracts for physical delivery of electricity, exchange traded and "over-the-counter" financialcontracts, ERCOT "day-ahead market" transactions and bilateral contracts with other wholesale market participants,including other generators and end-use customers. These hedging activities include shorter-term agreements, longer-term electricity sales contracts and forward sales of natural gas.The historical relationship between natural gas prices and wholesale electricity prices in the ERCOT market has providedus an opportunity to manage a portion of our exposure to variability of wholesale electricity prices through a naturalgas price hedging program. Under this program, TCEH has entered into market transactions involving natural gas-related financial instruments, and at December 31, 2012, has effectively sold forward approximately 360 millionMMBtu of natural gas (equivalent to the natural gas exposure of approximately 42,000 GWh at an assumed 8.5 marketheat rate) for the period January 1,2013 through December 31, 2014 at weighted average annual hedge prices rangingfrom $6.89 per MMBtu to $7.80 per MMBtu. Taking together forward wholesale and retail electricity sales with thenatural gas positions in the hedging program, we have effectively hedged an estimated 96% and 41% of the priceexposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2013 and 2014, respectively(assuming an 8.5 market heat rate). For additional discussion of the natural gas price hedging program, see Item 7,"Management's Discussion and Analysis of Financial Condition and Results of Operations," specifically sectionsentitled "Significant Activities and Events and Items Influencing Future Performance -Natural Gas Price HedgingProgram and Other Hedging Activities," "Key Risks and Challenges -Natural Gas Price and Market Heat RateExposure" and "Financial Condition -Liquidity and Capital Resources -Liquidity Effects of Commodity Hedgingand Trading Activities."" Strengthen our balance sheet through a liability management program. In 2009, we implemented a liabilitymanagement program focused on improving our balance sheet by reducing the amount and extending the maturity ofour outstanding debt. Activities under the liability management program do not include debt issued by Oncor or itssubsidiary. Since inception, the program has resulted in the capture of $2.5 billion of debt discount and the extensionof approximately $25.7 billion of debt maturities to 2017-2021. Activities to date have included debt exchanges,issuances and repurchases as well as amendments to, and extensions under, the Credit Agreement governing the TCEHSenior Secured Facilities. As a result of these and other activities, we expect TCEH will have sufficient liquidity tomeets its obligations until October 2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures.TCEH's ability to satisfy this obligation is dependent upon the implementation of one or more of the actions describedbelow. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -Significant Activities and Events and Items Influencing Future Performance -Liability Management Program" andNotes I and 8 to Financial Statements for additional discussion of these transactions.As part of the liability management program, EFH Corp. and its subsidiaries (other than Oncor Holdings and itssubsidiaries) continue to consider and evaluate possible transactions and initiatives to address their highly leveragedbalance sheets and significant cash interest requirements and may from time to time enter into discussions with theirlenders and bondholders with respect to such transactions and initiatives. These transactions and initiatives may include,among others, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debtfor equity exchanges or conversions, including exchanges or conversions of debt of EFCH and TCEH into equity ofEFH Corp., EFCH, TCEH and/or any of their subsidiaries. These actions could result in holders of TCEH debtinstruments not recovering the full principal amount of those obligations.In evaluating whether to undertake any liability management transaction, we will take into account liquidityrequirements, prospects for future access to capital, contractual restrictions, the market price of our outstanding debt,the maturity dates of our debt, potential transaction costs and other factors. Any liability management transaction,including any refinancing or extension, may occur on a stand-alone basis or in connection with, or immediatelyfollowing, other liability management transactions.Pursue new environmental initiatives. We are committed to continue to operate in compliance with all environmentallaws, rules and regulations and to reduce our impact on the environment. EFH Corp.'s Sustainable Energy AdvisoryBoard advises us in our pursuit of technology development opportunities that reduce our impact on the environmentwhile balancing the need to help address the energy requirements of Texas. The Sustainable Energy Advisory Boardis comprised of individuals who represent the following interests, among others: the environment, labor unions,customers, economic development in Texas and technology/reliability standards. See "Environmental Regulations andRelated Considerations" below for discussion of actions we are taking to reduce emissions from our generation facilitiesand our investments in energy efficiency and related initiatives.4 Table of ContentsSeasonalityOur revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, withrevenues being highest in the summer.Operating SegmentsWe have aligned and report our business activities as two operating segments: the Competitive Electric segment, consistinglargely of TCEH and its subsidiaries, and the Regulated Delivery segment, consisting largely of our investment in Oncor. SeeNote 16 to Financial Statements for additional financial information for the segments.Competitive Electric SegmentKey management activities, including commodity price risk management and electricity sourcing for our retail and wholesalecustomers, are performed on an integrated basis. This integration strategy, the execution of which is discussed below in describingthe activities of our wholesale operations, is a key consideration in our operating segment determination. For purposes of operationalaccountability and market identity, the segment operations have been grouped into Luminant, which is engaged in electricitygeneration and wholesale markets activities, and TXU Energy, which is engaged in retail electricity sales activities. These activitiesare conducted through separate legal entities.Luminant -Luminant's existing electricity generation fleet consists of 14 plants in Texas with total installed nameplategenerating capacity as shown in the table below:Installed Nameplate Number of Number ofFuel Tyve Capacity (MW) Plant Sites Units (a)Nuclear 2,300 1 2Lignite/coal (b) 8,017 5 12Natural gas (c) 5,110 8 26Total 15,427 14 40(a) Leased units consist of six natural gas-fueled combustion turbine units totaling 390 MW of capacity. All other units areowned.(b) Includes 1,130 MW representing two units at our Monticello facility for which operations have been suspended until summer2013 due to low wholesale power prices in ERCOT and other market conditions.(c) Includes 1,655 MW representing four units mothballed and not currently available for dispatch. See "Natural Gas-FueledGeneration Operations" below.The generation units are located primarily on owned land. Nuclear and lignite/coal-fueled units are generally scheduled torun at capacity except for periods of scheduled maintenance activities; however, we reduce production from certain lignite/coal-fueled generation units, referred to as economic backdown, during periods when wholesale electricity market prices are less thanthe unit's variable production costs. The natural gas-fueled generation units supplement the nuclear and lignite/coal-fueledgeneration capacity in meeting consumption in peak demand periods as production from certain of these units, particularlycombustion-turbine units, can be more readily ramped up or down as demand warrants.Nuclear Generation Operations -Luminant operates two nuclear generation units at the Comanche Peak plant site, eachof which is designed for a capacity of 1,150 MW. Comanche Peak's Unit 1 and Unit 2 went into commercial operation in 1990and 1993, respectively, and are. generally operated at full capacity. Refueling (nuclear fuel assembly replacement) outages foreach unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, therefueling cycle results in the refueling of both units during the same year, which last occurred in 2011. While one unit is undergoinga refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance,modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last threeyears the refueling outage period per unit has ranged from 22 to 25 days. The Comanche Peak facility operated at a capacity factorof 98.5%, 95.7% and 100% in 2012, 2011 and 2010, respectively.5 Table of ContentsLuminant has contracts in place for all of its uranium and nuclear fuel conversion, enrichment and fabrication services for2013. For the period of 2014 through 2019, Luminant has contracts in place for the acquisition of approximately 71% of itsuranium requirements and 87% of its nuclear fuel conversion services requirements. In addition, Luminant has contracts in placefor all of its nuclear fuel enrichment services through 2014, as well as all of its nuclear fuel fabrication services through 2018.Luminant does not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion andenrichment services in the foreseeable future.The nuclear industry is developing ways to store used nuclear fuel on site at nuclear generation facilities, primarily throughthe use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation inthe US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site usednuclear fuel storage capability is sufficient for the foreseeable future.The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date ofcommercial operation.Therefore, assuming that Luminant receives 20-year license extensions, similar to what has been granted by the NRC to severalother commercial generation reactors over the past several years, decommissioning activities would be scheduled to begin in 2050for Comanche Peak Unit 1 and 2053 for Unit 2 and common facilities. Decommissioning costs will be paid from a decommissioningtrust that, pursuant to Texas law, is intended to be fully funded from Oncor's customers through an ongoing delivery surcharge.(See Note 17 to Financial Statements for discussion of the decommissioning trust fund.)Nuclear insurance provisions are discussed in Note 9 to Financial Statements.Nuclear Generation Development -In 2008, a subsidiary of TCEH filed a combined operating license application withthe NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at its existing ComanchePeak nuclear plant site. In connection with the filing of the application, in 2009, subsidiaries of TCEH and Mitsubishi HeavyIndustries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company (CPNPC), to further the development ofthe two new nuclear generation units using MHI's US-Advanced Pressurized Water Reactor technology. The TCEH subsidiaryowns an 88% interest in CPNPC, and a MHI subsidiary owns a 12% interest.Based on the NRC's license application review schedule, we expect the NRC will complete its review in summer 2014 andthat a license could be issued by year-end 2014. We have filed a loan guarantee application with the DOE for financing theproposed units prior to commencement of construction.Lignite/Coal-Fueled Generation Operations -Luminant's lignite/coal-fueled generation fleet capacity totals 8,017 MWand consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (2 units) and Sandow (2 units)plant sites. Maintenance outages at these units are scheduled during seasonal off-peak demand periods. Over the last three years,the total annual scheduled and unscheduled outages per unit averaged 40 days (last two years include three recently constructedunits discussed immediately below). Luminant's lignite/coal-fueled generation fleet operated at a capacity factor of 70.0% in2012, 83.5% in 2011 and 82.2% in 2010. This performance reflects increased economic backdown of the units as described aboveand the suspension of operations until summer 2013 of two units at Monticello as reflected in the footnotes to the generatingcapacity table above.In 2009 and 2010, Luminant completed the construction of three lignite-fueled generation units with a total capacity of 2,180MW. The three units consist of one unit at a leased site that is adjacent to an existing lignite-fueled generation unit (Sandow) andtwo units at an owned site (Oak Grove). The Sandow unit and the first Oak Grove unit achieved substantial completion (as definedin the engineering, procurement and construction (EPC) agreements for the respective units) in the fourth quarter 2009. Thesecond Oak Grove unit achieved substantial completion (as defined in the EPC agreement for the unit) in the second quarter 2010.Approximately 71% of the fuel used at Luminant's lignite/coal-fueled generation units in 2012 was supplied from surface-minable lignite reserves dedicated to the Big Brown, Monticello, Martin Lake and Oak Grove plant sites, which are located adjacentto the reserves. Luminant owns or has under lease an estimated 735 million tons of lignite reserves dedicated to these sites, andhas an undivided interest in 200 million tons of lignite reserves that provide fuel for the Sandow facility. Luminant also owns orhas under lease approximately 85 million tons of reserves not currently dedicated to specific generation plants. In 2012, Luminantrecovered approximately 31 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipmentto remove the overburden and recover the lignite.6 Table of ContentsLuminant's lignite mining operations include extensive reclamation activities that return the land to productive uses such aswildlife habitats, commercial timberland and pasture land. In 2012, Luminant reclaimed more than 3,700 acres of land. In addition,Luminant planted 1.7 million trees in 2012, the majority of which were part of the reclamation effort.Luminant meets its fuel requirements at Big Brown, Monticello and Martin Lake by blending lignite with western coal fromthe Powder River Basin in Wyoming. The coal is purchased from multiple suppliers under contracts of various lengths and istransported from the Powder River Basin to Luminant's generation plants by railcar. Based on its current planned usage, Luminantbelieves that it has sufficient lignite reserves for the foreseeable future and has contracted the majority of its anticipated westerncoal requirements through 2013 and all of the related transportation through 2014.See "Environmental Regulations and Related Considerations -Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions"for discussion of potential effects of recent EPA rules on future operations of our generation units.Natural Gas-Fueled Generation Operations -Luminant owns or leases a fleet of 26 natural gas-fueled generation unitstotaling 5,110 MW of capacity, which includes 3,455 MW of currently available capacity and 1,655 MW of capacity representingfour units currently mothballed (idled). The natural gas-fueled units predominantly serve as peaking units that can be ramped upor down to balance electricity supply and demand.In December 2012, Luminant filed a permit application with the TCEQ to build two natural gas combustion turbines totaling420 MW at its existing DeCordova generation facility. While we believe the current market conditions do not provide adequateeconomic returns for the development or construction of new generation, we believe additional generation resources will be neededto support continued electricity demand growth in the ERCOT market. See "Management's Discussion and Analysis of FinancialCondition and Results of Operations -Significant Activities and Events and Items Influencing Future Performance -Recent PUCT/ERCOT Actions" for discussion of actions by the PUCT and ERCOT to encourage development of new generation resources.Wholesale Operations -Luminant's wholesale operations play a pivotal role in our Competitive Electric segment portfolioby optimally dispatching the generation fleet, sourcing all of TXU Energy's electricity requirements and managing commodityprice risk associated with retail and wholesale electricity sales and generation fuel requirements.Our electricity price exposure is managed across the complementary generation, wholesale and retail operations on a portfoliobasis. Under this approach, Luminant's wholesale operations manage the risks of imbalances between generation supply and salesload, as well as exposures to natural gas price movements and market heat rate changes (variations in the relationships betweennatural gas prices and wholesale electricity prices), through wholesale market activities that include physical purchases and salesand transacting in financial instruments.Luminant's wholesale operations provide TXU Energy and other retail and wholesale customers with electricity-relatedservices to meet their demands and the operating requirements of ERCOT. In consideration of electricity generation resourceavailability and consumer demand levels that can be highly variable, as well as opportunities to meet longer-term objectives oflarger wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-termforward electricity purchase and sales agreements. Luminant is also one of the largest purchasers of wind-generated electricityin Texas and the US with more than 900 MW of existing wind power under contract.Fuel price exposure, primarily relating to Powder River Basin coal, natural gas, uranium and fuel oil, as well as fueltransportation costs, is managed primarily through short- and long-term contracts for physical delivery of fuel as well as financialcontracts.In its hedging activities, Luminant enters into contracts for the physical delivery of electricity and fuel commodities, exchangetraded and "over-the-counter" financial contracts and bilateral contracts with other wholesale market participants, includinggenerators and end-use customers. Part of these hedging activities are achieved through a natural gas price hedging program,described above under "EFH Corp.'s Strategies", designed to reduce exposure to changes in future electricity prices due to changesin the price of natural gas, principally utilizing natural gas-related financial instruments.The wholesale operations also dispatch Luminant's available generation capacity. These dispatching activities includeeconomic backdown of lignite/coal-fueled units and ramping up and down of natural gas-fueled units as market conditions warrant.Luminant's dispatching activities are performed through a centrally managed real-time operational staff that optimizes operationalactivities across the fleet and interfaces with various wholesale market channels. In addition, the wholesale operations managethe fuel procurement requirements for Luminant's fossil fuel generation facilities.7 Table of ContentsLuminant's wholesale operations include electricity and natural gas trading and third-party energy management activities.Natural gas transactions include direct purchases from natural gas producers, transportation agreements, storage leases andcommercial retail sales. Luminant currently manages approximately 10 billion cubic feet of natural gas storage capacity.Luminant's wholesale operations manage exposure to wholesale commodity and credit-related risk within establishedtransactional risk management policies, limits and controls. These policies, limits and controls have been structured so that theyare practical in application and consistent with stated business objectives. Risk management processes include capturing transactiondata, monitoring transaction types and notional limits, reviewing and managing credit risk, performing and validating valuationsand reporting exposures on a daily basis using risk management information systems designed to support a large transactionalportfolio. A risk management forum meets regularly to ensure that business practices comply with approved transactional limits,commodities, instruments, exchanges and markets. Transactional risks are monitored to ensure limits comply with the establishedrisk policy. Risk management also includes a disciplinary program to address any violations of the risk management policies andperiodic reviews of these policies to ensure they are responsive to changing market and business conditions.TXU Energy -TXU Energy serves 1.75 million residential and commercial retail electricity customers in Texas.Approximately 67% of our reported retail revenues in 2012 represented sales to residential customers. Texas is one of the fastestgrowing states in the nation with a diverse economy and, as a result, has attracted a number of competitors into the retail electricitymarket; consequently, competition is robust. TXU Energy, as an active participant in this competitive market, provides retailelectric service to all areas of the ERCOT market now open to competition, including the Dallas/Fort Worth, Houston, CorpusChristi, and lower Rio Grande Valley areas of Texas. TXU Energy competitively markets its services to add new customers andretain its existing customer base,.as well as opportunistically acquire customers from other REPs. There are more than 100 REPscertified to compete within the State of Texas. Based upon data published by the PUCT, at June 30, 2012, approximately 59% ofresidential customers and 68% of small commercial customers in competitive areas of ERCOT are served by REPs not affiliatedwith the pre-competition utility. TXU Energy is a REP affiliated with a pre-competition utility, considering EFH Corp.'s historyprior to the deregulation of the Texas market.ITXU Energy's strategy focuses on providing its customers with high quality customer service and creating new productsand services to meet customer needs; accordingly, customer care enhancements are implemented on an ongoing basis to continuallyimprove customer satisfaction. TXU Energy offers a wide range of residential products to meet varying customer needs and hasinvested $100 million in energy efficiency initiatives over a five-year period through 2012 as part of a program to offer customersa broad set of innovative energy products and services.Regulation -Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to thejurisdiction of the NRC with respect to its nuclear generation units. NRC regulations govern the granting of licenses for theconstruction and operation of nuclear-fueled generation facilities and subject such facilities to continuing review and regulation.Luminant also holds a power marketer license from the FERC and, with respect to any wholesale power sales outside the ERCOTmarket, is subject to market behavior and any other competition-related rules and regulations under the Federal Power Act thatare administered by the FERC. In addition, Luminant is subject to the jurisdiction of the RRC's oversight of its lignite miningand reclamation operations.Luminant is also subject to the jurisdiction of the PUCT's oversight of the competitive ERCOT wholesale electricity market.PUCT rules establish robust oversight, certain limits and a framework for wholesale power pricing and market behavior. Luminantis also subject to the requirements of the ERCOT Protocols, including Nodal Protocols and ERCOT reliability standards as adoptedand enforced by the TRE and the NERC, including NERC critical infrastructure protection (CIP) standards. Luminant is alsosubject to the expanding authority of the CFTC as it continues to implement rules and provide oversight vested in the agency bythe Wall Street Reform and Consumer Protection Act of 2010, particularly Title VII, which deals with over-the-counter derivativemarkets.TXU Energy is a licensed REP under the Texas Electric Choice Act and is subject to the jurisdiction of the PUCT withrespect to provision of electricity service in ERCOT. PUCT rules govern the granting of licenses for REPs, including oversightbut not setting of retail prices. TXU Energy is also subject to the requirements of the ERCOT Protocols, including Nodal Protocolsand ERCOT reliability standards as adopted and enforced by the TRE and the NERC, including NERC CIP standards.8 Table of ContentsRegulated Delivery SegmentThe Regulated Delivery segment consists largely of our investment in Oncor. Oncor is a regulated electricity transmissionand distribution company that provides the service of delivering electricity safely, reliably and economically to end-use consumersthrough its distribution systems, as well as providing transmission grid connections to merchant generation facilities andinterconnections to other transmission grids in Texas. Oncor's service territory comprises 91 counties and over 400 incorporatedmunicipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler andKilleen. Oncor's transmission and distribution assets are located principally in the north-central, eastern and western parts ofTexas. Most of Oncor's power lines have been constructed over lands of others pursuant to easements or along public highways,streets and rights-of-way as permitted by law. Oncor's transmission and distribution rates are regulated by the PUCT.Oncor is not a seller of electricity, nor does it purchase electricity for resale. It provides transmission services to otherelectricity distribution companies, cooperatives and municipalities. It provides distribution services to REPs, which sell electricityto residential, business and other consumers. Oncor is also subject to the requirements of the ERCOT Protocols, including NodalProtocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC.Performance -Oncor achieved or exceeded market performance protocols in 12 out of 14 PUCT market metrics in 2012.These metrics measure the success of transmission and distribution companies in facilitating customer transactions in thecompetitive Texas electricity market.Investing in Infrastructure and Technology -In 2012, Oncor invested $1.4 billion in its network to construct, rebuild andupgrade transmission lines and associated facilities, to extend the distribution infrastructure, and to pursue certain initiatives ininfrastructure maintenance and information technology. Reflecting its commitment to infrastructure, Oncor and several otherERCOT utilities filed with the PUCT a plan to participate in the construction of transmission improvements designed to interconnectexisting and future renewable energy facilities to transmit electricity from Competitive Renewable Energy Zones (CREZs)identified by the PUCT. In 2009, the PUCT awarded CREZ construction projects to Oncor, and Oncor currently estimates theproject costs to total approximately $2.0 billion and be largely completed by the end of 2013. Additional voltage support projectsare expected to be completed by early 2014, with the exception of one series capacitor project that is scheduled to be completedin December 2015. The projects involve the construction of transmission lines to support the transmission of electricity fromrenewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state.Through 2012, Oncor's cumulative CREZ-related capital expenditures totaled $1.460 billion, including $561 million invested in2012. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -Significant Activitiesand Events and Items Influencing Future Performance -Oncor Matters with the PUCT."Oncor's technology upgrade initiatives include development of a modernized grid through the replacement of existing meterswith advanced digital metering equipment and development of advanced digital communication, data management, real-timemonitoring and outage detection capabilities. This modernized grid is producing electricity service reliability improvements andproviding for additional products and services from REPs that enable businesses and consumers to better manage their electricityusage and costs. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of eachmeter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount ofelectricity they are consuming and adjust their electricity consumption habits. Oncor reports 15-minute interval, billing-qualityelectricity consumption data from the meters to ERCOT for market settlement purposes. The data makes it possible for REPs tosupport new programs and pricing options.At December 31, 2012, Oncor had installed 3,263,000 advanced digital meters, including 961,000 in 2012, completing itsplanned deployment of advanced meters to all residential and most nonresidential retail electricity consumers in its service area.Cumulative capital expenditures for the deployment of the advanced meter system totaled $660 million through December 31,2012, including $142 million invested in 2012.In a stipulation that was approved by the PUCT in 2007, Oncor committed to a variety of actions, including minimum capitalspending of $3.6 billion and spending an additional $100 million (in excess of regulatory requirements discussed below) in energyefficiency initiatives over the five-year period ending December 31, 2012 (not including CREZ). Oncor satisfied thesecommitments in 2012.In addition to the potential energy efficiencies from advanced metering and the $100 million in energy efficency spendingdiscussed above, Oncor spent approximately $240 million over the five-year period ending December 31, 2012 in programsdesigned to improve customer electricity demand efficiencies, including approximately $50 million in 2012.9 Table of ContentsElectricity Transmission -Oncor's electricity transmission business is responsible for the safe and reliable operations ofits transmission network and substations. These responsibilities consist of the construction and maintenance of transmissionfacilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over Oncor's transmissionfacilities in coordination with ERCOT.Oncor is a member of ERCOT, and its transmission business actively assists the operations of ERCOT and market participants.Through its transmission business, Oncor participates with ERCOT and other member utilities to plan, design, construct andoperate new transmission lines, with regulatory approval, necessary to maintain reliability, interconnect to merchant generationfacilities, increase bulk power transfer capability and minimize limitations and constraints on the ERCOT transmission grid.Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to aninterconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity overtransmission facilities operating at 60 kilovolt (kV) and above. Other services offered by Oncor through its transmission businessinclude, but are not limited to: system impact studies, facilities studies, transformation service and maintenance of transformerequipment, substations and transmission lines owned by other parties.PURA allows Oncor to update its transmission rates periodically to reflect changes in invested capital. This "capital tracker"provision encourages investment in the transmission system to help ensure reliability and efficiency by allowing for timely recoveryof and return on new transmission investments.At December 31, 2012, Oncor's transmission facilities included 5,760 circuit miles of 345kV transmission lines and 9,713circuit miles of 138kV and 69kV transmission lines. Sixty-four generation facilities totaling 33,880 MW were directly connectedto Oncor's transmission system at December 31, 2012, and 288 transmission stations and 708 distribution substations were servedfrom Oncor's transmission system.At December 31, 2012, Oncor's transmission facilities have the following connections to other transmission grids in Texas:Number of Interconnected LinesGrid Connections 345kV 138kV 69kVCenterpoint Energy Inc. 8 --American Electric Power Company, Inc (a) 6 7 11Lower Colorado River Authority 10 22 3Texas Municipal Power Agency 7 6 -Texas New Mexico Power 4 9 12Brazos Electric Power Cooperative, Inc. 8 109 22Lone Star Transmission 12 --Electric Transmission Texas, LLC 2 1 -Rayburn Country Electric Cooperative, Inc. -38 6Tex-La Electric Cooperative of Texas, Inc. 12 1Other small systems operating wholly within Texas 7 2(a) One of the 345-kV lines is an asynchronous high-voltage direct current connection with the Southwest Power Pool.Electricity Distribution-- Oncor's electricity distribution business is responsible for the overall safe and efficient operationof distribution facilities, including electricity delivery, power quality and system reliability. These responsibilities consist of theownership, management, construction, maintenance and operation of the distribution system within Oncor's certificated servicearea. Oncor's distribution system receives electricity from the transmission system through substations and distributes electricityto end-users and wholesale customers through 3,169 distribution feeders.The Oncor distribution system includes over 3.2 million points of delivery at December 31,2012. Over the past five years,the number of distribution system points of delivery served by Oncor, excluding lighting sites, grew an average of just over 1%per year. Oncor added approximately 40,000 points of delivery in 2012.10 Table of ContentsThe Oncor distribution system consists of 56,615 miles of overhead primary conductors, 21,497 miles of overhead secondaryand street light conductors, 15,898 miles of underground primary conductors and 9,840 miles of underground secondary and streetlight conductors. The majority of the distribution system operates at 25 kV and 12.5 kV.Oncor's distribution rates for residential and small business users are based on actual monthly consumption (kWh), and ratesfor large commercial and industrial users are based primarily on the greater of actual monthly demand (kilowatts) or 80% of peakmonthly demand during the prior eleven months.Customers -Oncor's transmission customers consist of municipalities, electric cooperatives and other distributioncompanies. Oncor's distribution customers consist of more than 80 REPs, including TXU Energy and certain electric cooperativesin Oncor's certificated service area. Revenues from services provided to TCEH represented 29% of Oncor's total reportedconsolidated revenues for 2012. Revenues from REP subsidiaries of one nonaffiliated entity collectively represented 15% ofOncor's total reported consolidated revenues for 2012. No other customer represented more than 10% of Oncor's total operatingrevenues. The consumers of the electricity delivered by Oncor are free to choose their electricity supplier from REPs who competefor their business.Regulation and Rates --As its operations are wholly within Texas, Oncor is not a public utility as defined in the FederalPower Act and, as a result, it is not subject to general regulation under this Act. However, Oncor is subject to reliability standardsadopted and enforced by the TRE and the NERC, including NERC CIP standards, under the Federal Power Act.In January 2011, Oncor filed for a rate review with the PUCT and 203 cities based on a test year ended June 30, 2010 (PUCTDocket No. 38929). In August 2011, the PUCT issued a final order providing for a distribution rate increase as discussed in Item7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -Significant Activities and Eventsand Items Influencing Future Performance -Oncor Matters with the PUCT."As directed by Senate Bill 1693, which was passed by the Texas Legislature in 2011, the PUCT approved a periodic rateadjustment rule in September 2011, which allows utilities to file, under certain circumstances, up to four rate adjustments betweenrate reviews to recover distribution-related investments on an interim basis.At the state level, PURA requires owners or operators of transmission facilities to provide open-access wholesale transmissionservices to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility's ownuse of its system. The PUCT has adopted rules implementing the state open-access requirements for utilities, including Oncor,that are subject to the PUCT's jurisdiction over transmission services.Securitization Bonds -Oncor's operations include its wholly-owned, bankruptcy-remote financing subsidiary, OncorElectric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuingcertain securitization (transition) bonds in 2003 and 2004. Oncor Electric Delivery Transition Bond Company LLC issued $1.3billion principal amount of transition bonds to recover generation-related regulatory asset stranded costs and other qualified costsunder an order issued by the PUCT in 2002. At December 31, 2012, $436 million principal amount of transition bonds maturingbetween 2013 and 2016 was outstanding. See Note 15 to Financial Statements for discussion of agreements between TCEH andOncor regarding payment of interest and incremental taxes related to these bonds that were settled in 2012.II Table of ContentsEnvironmental Reeulations and Related ConsiderationsGlobal Climate ChangeBackground--There is a debate nationally and internationally about global climate change and how greenhouse gas (GHG)emissions, such as CO2, might contribute to global climate change. GHG emissions from the combustion of fossil fuels, primarilyby our lignite/coal-fueled generation units, represent the substantial majority of our total GHG emissions. C02, methane andnitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions. Weestimate that our generation facilities produced 57 million short tons of CO2 in 2012. Other aspects of our operations result inemissions of GHGs including, among other things, coal piles at our generation plants, sulfur hexafluoride in transmission anddistribution equipment, refrigerant from our chilling and cooling equipment, fossil fuel combustion in our motor vehicles andelectricity usage at our facilities and headquarters. Our financial condition, liquidity or results of operations could be materiallyaffected by the enactment of statutes or regulations that mandate a reduction in GHG emissions or that impose financial penalties,costs or taxes on those that produce GHG emissions. See Item IA, "Risk Factors" for additional discussion of risks posed to usregarding global climate change regulation.Global Climate Change Legislation -Over the past few years, several bills have been introduced in the US Congress oradvocated by the Obama Administration that were intended to address climate change using different approaches, including mostprominently a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade). In additionto potential federal legislation to regulate GHG emissions, the US Congress has also considered, and may in the future consider,other legislation that could result in the reduction of GHG emissions, such as the establishment of renewable or clean energyportfolio standards.Through our own evaluation and working in tandem with other companies and industry trade associations, we have supportedthe development of an integrated package of recommendations for the federal government to address the global climate changeissue through federal legislation at various times in the past few years. When GHG legislation involving a cap-and-trade programwas being debated, we expressed a view that any such program should be mandatory, economy-wide, consistent with expectedtechnology development timelines and designed in a way to limit potential harm to the economy or grid reliability and protectconsumers. We have held that any mechanism for allocation of GHG emission allowances should include substantial allocationof allowances to offset the cost of GHG regulation, including the cost to electricity consumers. In addition, we have participatedin a voluntary electric utility industry sector climate change initiative in partnership with the DOE through the Edison ElectricInstitute (EEl). Our strategies are generally consistent with the "EEI Global Climate Change Points of Agreement" published bythe EEl in January 2009 and "The Carbon Principles" announced in February 2008 by three major financial institutions. We havealso created a Sustainable Energy Advisory Board that advises us on technology development opportunities that reduce the effectsof our operations on the environment while balancing the need to address the energy requirements of Texas. Our SustainableEnergy Advisory Board is comprised of individuals who represent the following interests, among others: the environment,customers, economic development in Texas and technology/reliability standards. If, despite these efforts, a substantial numberof our customers or others refuse to do business with us because of our GHG emissions, it could have a material effect on ourresults of operations, liquidity and financial condition.12 Table of ContentsFederal Level -The EPA has taken a number of actions regarding GHG emissions. In September 2009, the EPA issued afinal rule requiring the reporting of calendar year GHG emissions from specified large GHG emissions sources in the US. Thisreporting rule applies to our lignite/coal-fueled generation facilities, and we have complied with the requirement since its effectivedate in 2011. In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment andthat emissions from motor vehicles contribute to that endangerment. The EPA's finding required it to begin regulating GHGemissions from motor vehicles and ultimately stationary sources under existing provisions of the federal Clean Air Act. In March2010, the EPA determined that the Clean Air Act's Prevention of Significant Deterioration (PSD) program permit requirementswould apply to newly identified pollutants such as GHGs when a nation-wide rule requiring the control of a pollutant takes effect.Under this determination, PSD permitting requirements became applicable to GHG emissions from planned stationary sources orplanned modifications to stationary sources that had not been issued a PSD permit by January 2, 2011 -the first date that newmotor vehicles were required to meet the new GHG standards. In June 2010, the EPA finalized its so-called "tailoring rule" thatestablished new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources,including our power generation facilities. The EPA's tailoring rule defines the threshold of GHG emissions for determiningapplicability of the Clean Air Act's PSD and Title V permitting programs at levels greater than the emission thresholds containedin the Clean Air Act. In December 2010, in response to the State of Texas's indication that it would not take regulatory action toimplement the EPA's tailoring rule, the EPA adopted a rule to take over the issuance of permits for GHG emissions from the TCEQ.The State of Texas challenged that rule and the GHG permitting rules through litigation and has refused to implement the GHGpermitting rules issued by the EPA. In June 2012, the D.C. Circuit Court upheld all of the EPA's GHG rules and regulations. Anumber of members of the US Congress from both parties have introduced legislation to either block or delay EPA regulation ofGHGs under the Clean Air Act, and legislative activity in this area in the future is possible. In August 2012, various industrygroups and states that challenged the rule filed petitions with the D.C. Circuit Court asking for review by the full D.C. CircuitCourt of the panel's decision. In December 2012, the D.C. Circuit Court denied these requests. Parties will have approximately90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeal will befiled.In March 2012, the EPA released a proposal for a performance standard for greenhouse gas emissions from new electricgeneration units (EGUs). The proposed standard, which is currently limited to new sources, is based on the carbon dioxide emissionrate from a natural gas-fueled combined cycle EGU. None of our existing generation units would be considered a new sourceunder the proposed rule. While we do not believe the proposed rule, as released, affects our existing generation units, we continueto monitor the rule.State and Regional Level -There are currently no Texas state regulations in effect concerning GHGs, and there are noregional initiatives concerning GHGs in which the State of Texas is a participant. We oppose state-by-state regulation of GHGs.In October 2009, Public Citizen Inc. filed a lawsuit against the TCEQ and its commissioners seeking to compel the TCEQ toregulate GHG emissions under the Texas Clean Air Act. The Attorney General of Texas filed special exceptions to the PublicCitizen pleading, which were granted by the court in May 2010. Public Citizen Inc. appealed the court's ruling and the appeal hasbeen fully briefed and submitted to the appellate court for decision on the briefs. We are not a party to this litigation, but we arecontinuing to monitor the case.International Level -In December 2009, leaders of developed and developing countries met in Copenhagen under theUnited Nations Framework Convention on Climate Change (UJNFCCC) and issued the Copenhagen Accord. The CopenhagenAccord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissionsof GHGs by 2020 and provides for developed countries to fund GHG emission mitigation projects in developing countries.President Obama participated in the development of, and endorsed, the Copenhagen Accord. In January 2010, the US informedthe United Nations that it would reduce GHG emissions by 17% from 2005 levels by 2020, contingent on Congress passing climatechange legislation. In December 2011, the UNFCCC met in Durban, South Africa and agreed to develop a document with "legalforce" to address climate change by 2015, with reductions effective starting in 2020. In December 2012, the UNFCCC met inDoha, Qatar and 194 countries agreed to an extension of the Kyoto Protocol through 2020. The United States and China are notparticipants in the Kyoto Protocol extension. The impact, if any, of the Durban agreement or the Kyoto Protocol extension onnear-term regulatory or legislative policy cannot yet be determined.We continue to assess the risks posed by possible future legislative or regulatory changes pertaining to GHG emissions.Because some of the proposals described above are in their formative stages, we are unable to predict the potential effects on ourbusiness, results of operations, liquidity or financial condition; however, any such effects could be material. The effect will depend,in large part, on the specific requirements of the legislation or regulation and how much, if any, of the costs are included in wholesaleelectricity prices.13 Table of ContentsEFH Corp.'s Voluntary Energy Efficiency, Renewable Energy, and Global Climate Change Efforts -We are activelyengaged in, considering, or expect to be actively engaged in, business activities that could result in reduced GHG emissionsincluding:Investing in Energy Efficiency and Related Initiatives by Our Competitive Businesses -Over the last five years, ourcompetitive businesses invested $100 million in energy efficiency and related initiatives, including software- andhardware-based services deployed behind the meter. These programs leverage advanced meter interval data and in-home devices to provide usage and other information and insights to customers, as well as to control energy-consumingequipment. Examples of these initiatives include: the TXU Energy MyEnergy DashboardsM, an online tool showingresidential customers how and when they use electricity; the BrightensM Personal Energy Advisor, an online energyaudit tool with personalized tips and projects for saving electricity; the BrightensM Online Energy Store that providescustomers the opportunity to purchase hard-to-find, cost-effective energy-saving products; the BrightensM iThermostat,a web-enabled programmable thermostat with a load control feature for cycling air conditioners during times of peakenergy demand; TXU Energy PowerSmartsM and TXU Energy Free NightssM, time-based electricity rates, and TXUEnergy FlexPower sM, prepaid electricity plans, that work in conjunction with advanced metering infrastructure; in-home display devices that enable residential customers to monitor whole-house energy usage and cost in real-time andproject month-end bill amounts; rate plans that include electricity from renewable resources; the BrightensM EnergyEfficiency Assistance Program that delivered products and services, as well as grants through social service agencies,to save energy at participating low income customer homes and apartment complexes; a program to refer customersto energy efficiency contractors, and the provision of rebates to business customers for purchasing new energy efficientequipment for their facilities through the BrightensM Greenback Energy Efficiency Rebate Program; the TXU EnergyElectricity Usage Report, a weekly email that contains charts and graphs that give customers insight to better controltheir electricity usage and bills; programs promoting distributed renewable generation to reduce peak summer demandon the grid; and mobile access through smart phones, tablets and other mobile devices with "alert" features that helpinform residential customers about recent electricity consumption thresholds." Investing in Energy Efficiency Initiatives by Oncor -In addition to the potential energy efficiencies from advancedmetering, Oncor spent approximately $340 million in energy efficiency initiatives over the five year period endingDecember 31, 2012 through such efforts as traveling across the State of Texas educating consumers about the benefitsof energy efficiency, advanced meters and renewable energy, and spending over $24 million in the installation of solarphotovoltaic systems in customer homes and facilities that is expected to result in savings of up to 18.8 million kWhof electricity;" Participating in the CREZ Program -Oncor is constructing CREZ transmission facilities (currently estimated byOncor to cost $2.0 billion) that are designed to connect existing and future renewable energy facilities to the electricitytransmission system in ERCOT (see Item 7, "Management's Discussion and Analysis of Financial Condition and Resultsof Operations -Signi'ficant Activities and Events and Items Influencing Future Performance -Oncor Matters with thePUCT");" Purchasing Electricity from Renewable Sources -We expect to remain a leader in the ERCOT market in providingelectricity from renewable sources by purchasing wind power. Our total wind power portfolio is currently more than900 MW. We also purchase additional renewable energy credits (RECs) to support discretionary sales of renewablepower to our customers;" Promoting the Use ofSolarPower- TXU Energy provides qualified customers, through its TXU Energy SolarLeasesMprogram, the ability to finance the addition of solar panels to their homes. TXU Energy also purchases surplus renewabledistributed generation from qualified customers. In addition, TXU Energy's Solar Academy works with Texas schooldistricts to teach and demonstrate the benefits of solar power;" Investing in Technology-- We continue to evaluate the development and commercialization of cleaner power facilitytechnologies, including technologies that support sequestration and/or reduction of CO2; incremental renewable sourcesof electricity, including wind and solar power; energy storage, including advanced battery and compressed air storage,as well as related technologies that seek to lower emissions intensity. Additionally, we continue to explore and participatein opportunities to accelerate the adoption of electric cars and plug-in hybrid electric vehicles that have the potentialto reduce overall GHG emissions and are furthering the advance of such vehicles by supporting, and helping developinfrastructure for, networks of charging stations for electric vehicles;14 Table of ContentsEvaluating the Development of a New Nuclear Generation Facility -As discussed under "Nuclear GenerationDevelopment" above, we have filed applications with the NRC for combined construction and operating licenses fortwo new 1,700 MW nuclear power plants (3,400 MW total) of new nuclear generation capacity (the lowest GHGemission source of baseload generation currently available) at our Comanche Peak nuclear generation facility. Inaddition, we have (i) filed a loan guarantee application with the DOE for financing of the proposed units and (ii) formeda joint venture with Mitsubishi Heavy Industries Ltd. (MHI) to further develop the units using MHI's US-AdvancedPressurized Water Reactor technology, andOffsetting GHG Emissions by Planting Trees -We are engaged in a number of tree planting programs that offset GHGemissions, resulting in the planting of over 1.7 million trees in 2012. The majority of these trees were planted as partof our mining reclamation efforts but also include TXU Energy's Urban Tree Farm program, which has planted morethan 180,000 trees since its inception in 2002.Sulfur Dioxide, Nitrogen Oxide and Mercury Air EmissionsCross-State Air Pollution Rule -In 2005, the EPA issued a final rule (the Clean Air Interstate Rule or CAIR) intended toimplement the provisions of the Clean Air Act Section 11 0(a)(2)(D)(i)(I) (CAA Section 110) requiring states to reduce emissionsof sulfur dioxide (SO2) and nitrogen oxides (NOx) that significantly contribute to other states failing to attain ormaintain compliancewith the EPA's National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone. In 2008, the US Courtof Appeals for the District of Columbia Circuit (D.C. Circuit Court) invalidated CAIR, but allowed the rule to continue until theEPA issued a final replacement rule.In July 2011, the EPA issued the final replacement rule for CAIR (as finally issued, the Cross-State Air Pollution Rule(CSAPR)). The CSAPR included Texas in its annual SO2 and NOx emissions reduction programs, as well as the seasonal NOxemissions reduction program. These programs would have required significant additional reductions of SO2 and NOx emissionsfrom fossil-fueled generation units in covered states (including Texas) and instituted a limited "cap and trade" system as anadditional compliance tool to achieve reductions the EPA contends are necessary to implement CAA Section 110. In September2011, we filed a petition for review in the D.C. Circuit Court challenging the CSAPR as it applies to Texas.In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR,including emissions budgets for the State of Texas. In June 2012, the EPA finalized the proposed rule (Second Revised Rule). Intotal, the emissions budgets established by the Final Revisions along with the Second Revised Rule would require our fossil-fueledgeneration units to reduce (i) their annual SO2 and NOx emissions by approximately 120,600 tons (56 percent) and 9,000 tons (22percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NOx emissions by approximately 3,300 tons (18percent) compared to 2010 levels. We could comply with these emissions limits either through physical reductions or through thepurchase of emissions credits from third parties, but the volume of SO2 credits that may be purchased from sources outside ofTexas would be subject to limitations starting in 2014. In April 2012, we filed in the D.C. Circuit Court a petition for review ofthe Final Revisions on the ground, among others, that the rules do not include all of the budget corrections we requested from theEPA. The parties to these proceedings have agreed that the case should be held in abeyance pending the conclusion of the CSAPRrehearing proceeding discussed immediately below. Since the CSAPR rehearing proceeding has concluded, the parties will conferregarding how the case should proceed, if at all.In August 2012, a three judge panel of the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for furtherproceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule do not impose any immediate requirementson us, the State of Texas, or other affected parties. The D.C. Circuit Court's order stated that the EPA was expected to continueadministering the CAIR pending the EPA's further consideration of the rule. In October 2012, the EPA and certain other partiesthat supported the CSAPR filed petitions with the D.C. Circuit Court seeking review by the full court of the panel's decision tovacate and remand the CSAPR. In January 2013, the D.C. Circuit Court denied these requests for rehearing, concluding theCSAPR rehearing proceeding. The EPA and the other parties to the proceedings have approximately 90 days to appeal the D.C.Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeals will be filed.Given the uncertainty regarding the CSAPR's (including the Final Revisions, the Second Revised Rule or any replacementrules) requirements and the timing of its implementation, we are unable to predict its effects on our results of operations, liquidityor financial condition. See Note 3 to Financial Statements for discussion of accounting actions taken as a result of the CSAPR.15 Table of ContentsMercury andAir Toxics Standard- In December 2011, the EPA finalized a rule called the Mercury and Air Toxics Standard(MATS). MATS regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases. Anyadditional control equipment retrofits on our lignite/coal-fueled generation units required to comply with MATS as finalized wouldneed to be installed within three to four years from the April 2012 effective date of the rule. In April 2012, we filed a petition forreview of MATS in the D.C. Circuit Court. Certain states and industry participants have also filed petitions for review in the D.C.Circuit Court. We cannot predict the timing or outcome of these petitions. In November 2012, the EPA proposed revised standardsfor new coal-fired generation units and other minor changes to MATS, including changes to the work practice standards affectingall units. We cannot predict the outcome of the final rule.Regional Haze -SO2 and NOx reductions required under the proposed regional haze/visibility rule (or so-called BARTrule) only apply to units built between 1962 and 1977. The reductions are required either on a unit-by-unit basis or by stateparticipation in an EPA-approved regional trading program such as the CAIR. In February 2009, the TCEQ submitted a StateImplementation Plan (SIP) concerning regional haze to the EPA, which we believe would not have a material impact on ourgeneration facilities. In December 2011, the EPA proposed a limited disapproval of the SIP due to its reliance on the CAIR anda Federal Implementation Plan for Texas providing that the inclusion in the CSAPR programs meets the regional haze requirementsfor S02 and NOx reductions. In June 2012, the EPA finalized the limited disapproval of the Texas regional haze SIP, but did notfinalize a Federal Implementation Plan for Texas. We cannot predict whether or when the EPAwill finalize a Federal ImplementationPlan for Texas regarding regional haze or its impact on our results of operations, liquidity or financial condition. In August 2012,we filed a petition for review in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the EPA's limiteddisapproval of the Texas regional haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court'sdecision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and otherstates and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of Federal ImplementationPlans regarding regional haze. The parties to these cases have mutually agreed that the cases should be held in abeyance pendingcompletion of the CSAPR rehearing proceeding described above. Because the CSAPR rehearing proceeding is completed, weanticipate that these cases will no longer be held in abeyance. We cannot predict when or how the Fifth Circuit Court or the D.C.Circuit Court will rule on these petitions.State Implementation Plan -The Clean Air Act requires each state to monitor air quality for compliance with federal healthstandards. The EPA is required to periodically review, and if appropriate, revise all national ambient air quality standards. Thestandards for ozone are not being achieved in several areas of Texas. The TCEQ adopted SIP rules in May 2007 to deal with eight-hour ozone standards, which required NOx emission reductions from certain of our peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposedto further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation fromozone-related damage; however, in September 2011, the White House directed the EPA to withdraw this reconsideration. Sincethe EPA has not designated nonattainment areas and projects that SIP rules to address attainment of the 2008 standards will notbe required until June 2015, we cannot yet predict the impact of this action on our generation facilities. In January 2010, the EPAadded a new one-hour NOx National Ambient Air Quality standard that may require actions within Texas to reduce emissions.The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required noearlier than January 2021. In June 2010, the EPA adopted a new one-hour SO2 national ambient air quality standard that mayrequire action within Texas to reduce SO2 emissions. Based on current monitoring, Texas has recommended to the EPA that noarea in Texas is in nonattainment with this one-hour SO2 standard. The EPA had indicated that it will not make final area designationsuntil June 2013. We cannot predict the impact of the new standards on our business, results of operations or financial conditionuntil the TCEQ adopts (if required) an implementation plan with respect to the standards.In September 2010, the EPA disapproved a portion of the State Implementation Plan pursuant to which the TCEQ implementsits program to achieve the requirements of the Clean Air Act. The EPA disapproved the Texas standard permit for pollution controlprojects. We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. Wechallenged the EPA's disapproval by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ's adoption of the standardpermit conditions for pollution control projects was consistent with the Clean Air Act. In March 2012, the Fifth Circuit Courtvacated the EPA's disapproval of the Texas standard permit for pollution control projects and remanded the matter to the EPA forreconsideration. We cannot predict the timing or outcome of the EPA's reconsideration.16 Table of ContentsIn November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacingthat exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generationfacility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicabilityof the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and receivedthe generation facility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the Fifth CircuitCourt arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issuedis consistent with the Clean Air Act. In July 2012, the Fifth Circuit Court denied our challenge and ruled that the EPA's actionswere in accordance with the Clean Air Act. In October 2012, the Fifth Circuit Court panel withdrew its original opinion and issueda new expanded opinion that again upheld the EPA's disapproval. In November 2012, we filed a petition with the Fifth CircuitCourt asking for review by the full Fifth Circuit Court of the panel's new expanded opinion. Other parties to the proceedings alsofiled a petition with the Fifth Circuit Court asking the panel to reconsider its decision. We cannot predict the timing or outcomeof this matter.AcidRain Program -The EPA has promulgated Acid Rain Program rules that require fossil-fueled plants to have sufficientS02 emission allowances and meet certain NOx emission standards. We believe our generation plants meet these S02 allowancerequirements and NOx emission rates.Installation of Substantial Emissions Control Equipment -Each of our lignite/coal-fueled generation facilities is currentlyequipped with substantial emissions control equipment. All of our lignite/coal-fueled generation facilities are equipped withactivated carbon injection systems to reduce mercury emissions. Flue gas desulfurization systems designed primarily to reduceSO2 emissions are installed at Oak Grove Units I and 2, Sandow Units 4 and 5, Martin Lake Units 1, 2, and 3, and MonticelloUnit 3. Selective catalytic reduction systems designed to reduce NOx emissions are installed at Oak Grove Units I and 2 andSandow Unit 4. Selective non-catalytic reduction systems designed to reduce NOx emissions are installed at Sandow Unit 5,Monticello Units 1, 2, and 3, and Big Brown Units I and 2. Fabric filter systems designed primarily to reduce particulate matteremissions are installed at Oak Grove Units I and 2, Sandow Unit 5, Monticello Units I and 2, and Big Brown Units I and 2.Electrostatic precipitator systems designed primarily to reduce particulate matter emissions are installed at Sandow Unit 4, MartinLake Units 1,2, and 3, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Sandow Unit 5 uses a fluidized bed combustionprocess that facilitates control ofNOx and SO2.Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitatorsystems also assist in reducing mercury and other emissions.We believe that we hold all required emissions permits for facilities in operation. If the TCEQ adopts implementation plansthat require us to install additional emissions controls, or if the EPA adopts more stringent requirements through any of the numberof potential rulemaking activities in which it is or may be engaged, we could incur material capital expenditures, higher operatingcosts and potential production curtailments, resulting in material effects on our results of operations, liquidity and financialcondition.WaterThe TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. We believeour facilities are presently in material compliance with applicable state and federal requirements relating to discharge of pollutantsinto water. We believe we hold all required waste water discharge permits from the TCEQ for facilities in operation and haveapplied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirementsnecessary to obtain any required permits or renewals.In 2010, we obtained a renewed and amended permit for discharge of waste water from our Oak Grove generation facility.Opponents to that permit renewal have initiated a challenge in Travis County, Texas District Court. We and the State of Texasdefended the issuance of the permit. In October 2012, the Texas District Court ruled in favor of the issuance of the permit.Opponents have filed an appeal directed at the State of Texas. If the permit is ultimately rejected by the courts, and we are requiredto undertake additional permitting activity and install additional temperature-control equipment, we could incur material capitalexpenditures, which could result in material effects on our results of operations, liquidity and financial condition. (See Note 9 toFinancial Statements.)There are also federal rules pertaining to the Spill Prevention, Control and Countermeasure (SPCC) plans for oil-filledelectrical equipment and bulk storage facilities for oil that affect certain of our facilities. We have implemented SPCC plans asrequired for those substations, work centers and distribution systems and are currently in compliance with these rules.17 Table of ContentsDiversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQand the EPA. We believe we possess all necessary permits from the TCEQ for these activities at our current facilities. CleanWater Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were publishedby the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actionsthat might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuitbrought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it wassuspending the regulations pending further rulemaking. The US Supreme Court issued a decision in April 2009 reversing thefederal court's decision, in part, and finding that the EPA permissibly used cost-benefit analysis in the Section 316(b) regulations.Pursuant to a settlement agreement, the EPA issued for comment proposed new Section 316(b) regulations in March 2011 andmust adopt the final regulations by June 2013. In the absence of regulations, the EPA has instructed the states implementing theSection 316(b) program, including Texas, to use their best professional judgment in reviewing applications and issuing permitsunder Section 316(b). Although the proposed rule does not mandate a certain control technology, it does require site-specificassessments of technology feasibility on a case-by-case basis at the state level. Compliance with this rule would be requiredbeginning eight years following promulgation. We cannot predict the substance of the final regulations or the impact they mayhave on our results of operations, liquidity or financial condition.Radioactive WasteWe currently, and expect. to continue to, ship low-level waste material to a disposal facility outside of Texas. Under thefederal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its ownor jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The Stateof Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congressand signed by the President in 1998, and the State of Texas has enacted legislation allowing a private entity to be licensed to acceptlow-level radioactive waste for disposal. The first disposal facility in Texas for such purposes began operations in 2012, and weexpect to ship some forms of waste material to the facility in 2013. Should existing off-site disposal become unavailable, the low-level waste material can be stored on-site. (See discussion under "Luminant -Nuclear Generation Operations" above.)The nuclear industry is developing ways to store used nuclear fuel on site at nuclear generation facilities, primarily throughthe use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation inthe US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site usednuclear fuel storage capability is sufficient for the foreseeable future.Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled GenerationTreatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas SolidWaste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and theToxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 andthe Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable toour facilities. We believe we are in material compliance with all applicable solid waste rules and regulations. In addition, wehave registered solid waste disposal sites and have obtained or applied for permits required by such regulations.In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured, releasing a significantquantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of our impoundments, whichare significantly smaller than the TVA's and are inspected on a regular basis. We routinely sample groundwater monitoring wellsto ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, in May 2010, the EPAreleased a proposed rule that considers regulating coal combustion residuals as either a hazardous waste or a non-hazardous waste.We are unable to predict the requirements of a final rule; however, the potential cost of compliance could be material.The EPA issued a notice in December 2009 that it had identified several industries, including the electric power industry,which should be subject to financial responsibility requirements under the Comprehensive Environmental Response, Compensationand Liability Act (CERCLA) consistent with the risk associated with their production, transportation, treatment, storage or disposalof hazardous substances. The EPA indicated in its notice that it would develop regulations that define the scope of those financialresponsibility requirements. We do not know the scope of these requirements, nor are we able to estimate the potential cost, whichcould be material, of complying with any such new requirements.18 Table of ContentsEnvironmental Capital ExpendituresCapital expenditures for our environmental projects totaled $270 million in 2012 and are expected to total approximately$100 million in 2013 for environmental control equipment to comply with regulatory requirements. Based on analysis and testingof options to comply with the MATS rule, as well as estimates related to other EPA regulations, including expenditures previouslyincurred related to the CSAPR, between 2011 and the end of the decade we estimate that we will incur more than $1 billion incapital expenditures for environmental control equipment, though the ultimate total will depend on the evolution of pending orfuture regulatory requirements. Based on regulations currently in effect, we estimate that we will incur approximately $500 millionof environmental capital expenditures between 2013 and 2017, including amounts required to maintain installed environmentalcontrol equipment. Our current plan includes the ongoing use of lignite coal as part of the fuel mix at all of our coal facilities, invarying proportions that reflect the economically available fuel supply as well as the configuration of environmental controlequipment for each unit.19 Table of ContentsItem IA. RISK FACTORSSome important factors, in addition to others specifically addressed in Item 7, "Management's Discussion and Analysis ofFinancial Condition and Results of Operations," that could have a material impact on our operations, liquidity, financial resultsand financial condition, or could cause our actual results or outcomes to differ materially from any projected outcome containedin any forward-looking statement in this report, include:Risks Related to Substantial IndebtednessOur substantial leverage could adversely affect our ability to fund our operations, limit our ability to react to changes in theeconomy or our industry (including changes to environmental regulations), limit our ability to raise additional capital andadversely impact our ability to meet obligations under our various debt agreements.We are highly leveraged. At December 31, 2012, our consolidated principal amount of debt (short-term borrowings andlong-term debt, including amounts due currently) totaled $40.1 billion (see Note 8 to Financial Statements), which does not include$6.3 billion principal amount of debt ofOncor. Our substantial indebtedness has, or could have, important consequences, including:" making it more difficult for us to make payments on our debt, including our maturities of $3.8 billion of TCEH TermLoan Facilities in October 2014;" requiring a substantial portion of our cash flow to be dedicated to the payment of principal and interest on our debt,thereby limiting our liquidity and reducing our ability to use our cash flow to fund operations, capital expenditures,future business opportunities and execution of our growth strategy;" increasing our vulnerability to adverse economic, industry or competitive conditions or developments, including changesto environmental regulations;" limiting our ability to make strategic acquisitions or causing us to make non-strategic divestitures;* limiting our ability to develop new (or maintain our current) generation facilities;* limiting our ability to obtain additional financing for working capital (including collateral posting), capital expenditures,project development, debt service requirements, acquisitions and general corporate or other purposes, or to refinanceexisting debt, and increasing the costs of any such financing or refinancing;* limiting our ability to find counterparties for our hedging and asset management activities in the wholesale commoditymarket, and* limiting our ability to adjust to changing market and industry conditions (including changes to environmental regulations)and placing us at a disadvantage compared to competitors who are less leveraged and who, therefore, may be able tooperate at a lower overall cost (including debt service) and take advantage of opportunities that we cannot.We may not be able to repay or refinance our debt as or before it becomes due, or obtain additional financing, particularly ifwholesale electricity prices in ERCOT do not significantly increase and/or if environmental regulations are adopted that resultin significant capital requirements, and the costs of any refinancing may be significant.We may not be able to repay or refinance our debt as or before it becomes due, including our maturities of $3.8 billion ofTCEH Term Loan Facilities in October 2014, or we may only be able to refinance such amounts on terms that will increase ourcost of borrowing or on terms that may be more onerous. Our ability to successfully implement any future refinancing of our debtwill depend on, among other things, our financial condition and operating performance, which is subject to prevailing economicand competitive conditions, and to certain financial, business and other factors beyond our control, including, without limitation,wholesale electricity prices in ERCOT (which are primarily driven by the price of natural gas and ERCOT market heat rates),environmental regulations and general conditions in the credit markets. Refinancing may also be difficult because of generaleconomic conditions, including the slow economic recovery, the possibility of rising interest rates and uncertainty with respect toUS fiscal policy. Because our credit ratings are significantly below investment grade, we may be more heavily exposed to theserefinancing risks than other borrowers. In addition, the timing of additional financings may require us to pursue such financingsat inopportune times, and we may be able to incur new financing only at significant cost.20 Table of ContentsAt December 31, 2012, a substantial amount of our long-term debt matures in the next few years, including approximately$90 million, $4.0 billion and $3.3 billion principal amount of debt maturing in 2013, 2014 and 2015, respectively. A substantialamount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities. In April 2011 and January 2013, wesecured extensions of a significant portion of the commitments and loans under the TCEH Senior Secured Facilities. However,even after taking these extensions into account, we still have $3.8 billion principal amount of loans under the TCEH Term LoanFacilities that were not extended and will mature in October 2014. In addition, notwithstanding the extensions, the commitmentsand loans could mature earlier as described in the next paragraph. Moreover, while we were able to extend a significant portionof the commitments and loans under the TCEH Senior Secured Facilities, the extensions were only for three years and the cost ofthese extensions was significant. As a result, we have a substantial principal amount of debt that matures in 2016 (approximately$1.9 billion) and 2017 (approximately $16.7 billion, including $947 million under the TCEH Letter of Credit Facility that is heldin restricted cash).The extended commitments and loans under the TCEH Senior Secured Facilities include a "springing maturity" provisionpursuant to which in the event that (a) more than $500 million aggregate principal amount of the TCEH 10.25% Notes or morethan $150 million aggregate principal amount of the TCEH Toggle Notes (in each case, other than notes held by EFH Corp. or itscontrolled affiliates at March 31, 2011 to the extent held at the determination date), as applicable, remain outstanding as of 91days prior to the maturity date of the applicable notes and (b) TCEH's consolidated total debt to consolidated EBITDA ratio (asdefined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at such applicable determination date, then the maturitydate of the extended commitments and loans will automatically change to 90 days prior to the maturity date of the applicablenotes. As a result of this "springing maturity" provision, we may lose the benefit of the extension of the commitments and loansunder the TCEH Senior Secured Facilities if we are unable to refinance the requisite portion of the TCEH 10.25% Notes and TCEHToggle Notes (collectively, the TCEH Senior Notes) by the applicable deadline. The TCEH 10.25% Notes mature on November1, 2015, and the TCEH Toggle Notes mature on November 1, 2016. If holders of the TCEH Senior Notes are unwilling to extendthe maturities of their notes, then, to avoid the "springing maturity" of the extended commitments and loans, we may be requiredto repay a substantial portion of the TCEH Senior Notes at prices above market or at par. There is no assurance that we will beable to make such payments, whether through cash on hand or additional financings. At December 31, 2012, $3.125 billion and$1.749 billion aggregate principal amount of the TCEH 10.25% Notes and the TCEH Toggle Notes, respectively, were outstanding,excluding amounts held by affiliates.Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas. Accordingly, thecontribution to earnings and the value of our nuclear and lignite/coal-fueled generation assets are dependent in significant partupon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008 (from $11.12 perMMBtu in mid-2008 to $4.03 per MMBtu at December 31, 2012 for calendar year 2014). In recent years, natural gas supply hasoutpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weakness associated withthe economic downturn. Many industry experts expect this supply/demand imbalance to continue for a number of years, therebydepressing natural gas prices for a long-term period. These market conditions are challenging to our liquidity and the long-termprofitability of EFH Corp. and its competitive businesses. Specifically, low natural gas prices and their effect in ERCOT onwholesale electricity prices could have a material impact on TCEH's overall profitability for periods in which TCEH does nothave significant hedge positions. At December 31, 2012, we have hedged approximately 96% and 41% of our wholesale naturalgas price exposure related to expected generation output for 2013 and 2014, respectively, based on currently governing CAIRregulation, and we do not have any significant amounts of hedges in place for periods after 2014. Consequently, a continuation,or further decline, of current forward natural gas prices could result in further declines in the values of TCEH's nuclear and lignite/coal-fueled generation assets and limit or hinder TCEH's ability to hedge its wholesale electricity revenues at sufficient price levelsto support its significant interest payments and debt maturities, which could adversely impact its ability to obtain additional liquidityand refinance and/or extend the maturities of its outstanding debt.21 Table of ContentsAspects of our current financial condition may also be challenging to our efforts to obtain additional financing (or refinanceor extend our existing financing) in the future. For example, our liabilities and those of EFCH exceed our and EFCH's assets asshown on our and EFCH's respective balance sheet prepared in accordance with US GAAP at December 31, 2012. Our reportedassets include $4.952 billion of goodwill at December 31, 2012. In 2012 and 2010, we recorded $1.2 billion and $4.1 billion,respectively, noncash goodwill impairment charges reflecting the estimated effect of lower wholesale electricity prices on theenterprise value of TCEH, driven by the sustained decline in forward natural gas prices, as indicated by our cash flow projectionsand declines in market values of securities of comparable companies. The enterprise value of TCEH will continue to depend on,among other things, wholesale electricity prices in the ERCOT market. Further, third party analyses ofTCEH's business performedin connection with goodwill impairment testing in accordance with US GAAP, which have indicated that the principal amount ofTCEH's outstanding debt exceeds its enterprise value, may make it more difficult for us to successfully access the capital marketsto obtain liquidity and/or implement any refinancing or extensions of our debt or obtain additional financing. Our ability to obtainfuture financing for our competitive businesses is also limited by the value of our unencumbered assets. Substantially all of ourcompetitive businesses' assets are encumbered (in most cases by both first and second liens), and we have no material assets thatcould be used as additional collateral in future financing transactions.EFH Corp.'s (or any applicable subsidiary's) credit ratings and any actual orperceived changes in their creditworthiness couldnegatively affect EFH Corp.'s (or the subsidiary's) ability to access capital and could require EFH Corp. or its subsidiaries topost collateral or repay certain indebtedness.EFH Corp.'s (or any applicable subsidiary's) credit ratings could be lowered, suspended or withdrawn entirely at any timeby the rating agencies, if in each rating agency's judgment, circumstances warrant. Downgrades in EFH Corp.'s or any of itssubsidiaries' long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and fundingsources to decrease and could trigger liquidity demands pursuant to the terms of new commodity contracts, leases or otheragreements. Future transactions by EFH Corp. or any of its subsidiaries, including the issuance of additional debt or theconsummation of additional transactions under our liability management program, could result in temporary or permanentdowngrades of EFH Corp.'s or its subsidiaries' credit ratings.Most of EFH Corp.'s large customers, suppliers and counterparties require an expected level of creditworthiness in orderfor them to enter into transactions. Because of EFH Corp.'s (and its applicable subsidiaries') existing credit ratings, the cost tooperate its businesses is likely higher because counterparties in some instances could require the posting of collateral in the formof cash or cash-related instruments. If our creditworthiness or perceptions of our creditworthiness deteriorate further, counterpartiescould decline to do business with EFH Corp. (or its applicable subsidiary).Despite our current high debt level, we may still be able to incur substantially more debt. This could further exacerbate therisks associated with our substantial debt.We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on the incurrenceof additional debt, these restrictions are subject to a number of significant qualifications and exceptions. Under certaincircumstances, the amount of debt, including secured debt, that could be incurred in the future in compliance with these restrictionscould be substantial. If new debt is added to our existing debt levels, the related risks that we and holders of our existing debtnow face could intensify.EFH Corp. and its subsidiaries (other than Oncor Holdings and its subsidiaries) may pursue various transactions and initiativesto address their highly leveraged balance sheets and significant cash interest requirements.Future transactions and initiatives that we may pursue may have significant effects on our business, capital structure,ownership, liquidity, credit ratings and/or results of operations. For example, in addition to the exchanges, repurchases andextensions of our debt beginning in 2009 reflected in Item 7, "Management's Discussion and Analysis of Financial Condition andResults of Operations -Significant Activities and Events and Items Influencing Future Performance -Liability ManagementProgram," EFH Corp. and its subsidiaries (other than Oncor Holdings and its subsidiaries) continue to consider and evaluatepossible transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements andmay from time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives.These transactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to andextensions of debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debt of EFCHand TCEH into equity of EFH Corp., EFCH, TCEH and/or any of their subsidiaries, and could have significant effects on thebusiness, capital structure, ownership, liquidity, credit ratings and/or results of operations of EFH Corp., EFIH, EFCH and TCEH,including significantly deleveraging TCEH. There can be no guarantee that any of such transactions or initiatives would besuccessful or produce the desired outcome, which could ultimately affect us or our debtholders in a material manner, includingdebtholders not recovering the full principal amount of TCEH debt.22 Table of ContentsOur debt agreements contain covenants and restrictions that limit flexibility in operating our businesses, and a breach of anyof these covenants or restrictions could result in an event of default under one or more of our debt agreements at differententities within our capital structure, including as a result of cross acceleration or default provisions.Our debt agreements contain various covenants and other restrictions that, among other things, limit flexibility in operatingour businesses. A breach of any of these covenants or restrictions could result in a significant portion of our debt becoming dueand payable. Our ability to comply with certain of our covenants and restrictions can be affected by events beyond our control.These covenants and other restrictions limit our ability to, among other things:* incur additional debt or issue preferred shares;* pay dividends on, repurchase or make distributions in respect of capital stock or make other restricted payments;* make investments;* sell or transfer assets;* create liens on assets to secure debt;* consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;* enter into transactions with affiliates;* designate subsidiaries as unrestricted subsidiaries, and* repay, repurchase or modify certain subordinated and other material debt.There are a number of important limitations and exceptions to these covenants and other restrictions. See Note 8 to FinancialStatements for a description of these covenants and other restrictions.Under the TCEH Senior Secured Facilities, TCEH is required to maintain a consolidated secured debt to consolidatedEBITDA ratio below specified levels. TCEH's ability to maintain the consolidated secured debt to consolidated EBITDA ratiobelow such levels can be affected by events beyond its control, including, without limitation, wholesale electricity prices (whichare primarily derived by the price of natural gas and ERCOT market heat rates) and environmental regulations, and there can beno assurance that TCEH will comply with this ratio. At December 31, 2012, TCEH's consolidated secured debt to consolidatedEBITDA ratio was 5.9 to 1.00, which compares to the maximum consolidated secured debt to consolidated EBITDA ratio of 8.00to 1.00 currently permitted under the TCEH Senior Secured Facilities. The secured debt portion of the ratio excludes (a) up to$1.5 billion of debt ($906 million excluded at December 31, 2012) secured by a first-priority lien (including the TCEH SeniorSecured Notes) if the proceeds of such debt are used to repay term loans or deposit letter of credit loans under the TCEH SeniorSecured Facilities and (b) debt secured by a lien ranking junior to the TCEH Senior Secured Facilities, including the TCEH SeniorSecured Second Lien Notes. In addition, under the TCEH Senior Secured Facilities, TCEH is required to timely deliver to thelenders audited annual financial statements that are not qualified as to the status of TCEH and its consolidated subsidiaries as agoing concern. See Note 1 to Financial Statements for discussion of TCEH's liquidity and the $3.8 billion of TCEH Term LoanFacilities that matures in October 2014.A breach of any of these covenants or restrictions could result in an event of default under one or more of our debt agreementsat different entities within our capital structure, including as a result of cross acceleration or default provisions. Upon the occurrenceof an event of default under one of these debt agreements, our lenders or noteholders could elect to declare all amounts outstandingunder that debt agreement to be immediately due and payable and/or terminate all commitments to extend further credit. Suchactions by those lenders or noteholders could cause cross defaults or accelerations under our other debt. If we were unable torepay those amounts, the lenders or noteholders could proceed against any collateral granted to them to secure such debt. In thecase of a default under debt that is guaranteed, holders of such debt could also seek to enforce the guarantees. If lenders ornoteholders accelerate the repayment of all borrowings, we would likely not have sufficient assets and funds to repay thoseborrowings. Such occurrence could result in EFH Corp. and/or its applicable subsidiary going into bankruptcy, liquidation orinsolvency.23 Table of ContentsThe Oncor "ring-fencing" measures contain restrictions that limit flexibility in operating our business.As described in Note I to Financial Statements, EFH Corp. and Oncor have implemented a number of "ring-fencing" measuresto enhance the credit quality of Oncor Holdings and its subsidiaries, including Oncor. Those measures, many of which were agreedto and required by the PUCT's Order on Rehearing in Docket No. 34077, include, among other things:" Oncor Holdings' and Oncor's board of directors being comprised of a majority of directors that are independent fromthe Texas Holdings Group, EFH Corp. and its other subsidiaries;" Oncor being treated as an unrestricted subsidiary with respect to EFH Corp.'s and EFIH's debt;" Oncor not being restricted from incurring its own debt;" Oncor not guaranteeing or pledging any of its assets to secure the debt of any member of the Texas Holdings Group,and" restrictions on distributions by Oncor, and the right of the independent members of Oncor's board of directors and thelargest non-majority member of Oncor to block the payment of distributions to Oncor Holdings (i.e., such distributionsnot being available to EFH Corp. under certain circumstances).Lenders and holders ofour debt have in the past alleged, and might allege in the future, that we are not operating in compliancewith covenants in our debt agreements or make allegations against our directors and officers of breach offiduciary duty. Inaddition, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the pastclaimed, and might claim in the future, that a credit event has occurred under such credit derivative securities. In each case,even if the claims have no merit, these claims could cause the trading price of our debt securities to decline or adversely affectour ability to raise additional capital and/or refinance our existing debt.Lenders or holders of our debt have in the past alleged, and might allege in the future, that we are not operating in compliancewith the covenants in our debt agreements, that a default under our debt agreements has occurred or that our or our subsidiaries'boards of directors or similar bodies or officers are not properly discharging their fiduciary duties, or make other allegationsregarding our business, including for the purpose, and potentially having the effect, of causing a default under our debt or otheragreements, accelerating the maturity of such debt, protecting claims of debt issued at a certain entity or entities in our capitalstructure at the expense of debt claims elsewhere in our capital structure and/or obtaining economic benefits from us. These claimshave included, and may include in the future, among other things, claims that the TCEH Demand Notes were fraudulent transfersand should be repaid to TCEH, that authorization of the TCEH Demand Notes violated the fiduciary duties of EFCH's and TCEH'sboards of directors, that the TCEH Demand Notes were in violation of the terms of our debt agreements or that the interest rateon the TCEH Demand Notes was too low.Further, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the pastclaimed, and may claim in the future, that a credit event has occurred under such credit derivative securities based on our financialcondition. Even if these claims are without merit, they could nevertheless cause the trading price of our debt to decline andadversely affect our ability to raise additional capital and/or refinance our existing debt.24 Table of ContentsWe may not be able to generate sufficient cash to service our debt and may beforced to take other actions to satisfy the obligationsunder our debt agreements, which may not be successfuLOur ability to make scheduled payments on our debt obligations depends on our financial condition and operatingperformance, which is subject to prevailing economic and competitive conditions and to certain financial, business and otherfactors beyond our control, including, without limitation, wholesale electricity prices (which are primarily driven by the price ofnatural gas and ERCOT market heat rates) and environmental regulations. We may not be able to maintain a level of cash flowssufficient to pay the principal, premium, if any, and interest on our debt, including the $3.8 billion principal amount of TCEHTerm Loan Facilities maturing in October 2014.If cash flows and capital resources are insufficient to fund our debt obligations, we could face substantial liquidity problemsand might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additionalcapital or restructure or refinance debt. These alternative measures may not be successful, may not be completed on economicallyattractive terms or may not be adequate for us to meet our debt obligations when due. Additionally, our debt agreements limit theuse of the proceeds from many dispositions of assets or operations. As a result, we may not be permitted to use the proceeds fromthese dispositions to satisfy our debt obligations.Further, if we suffer or appear to suffer, from a lack of available liquidity, the evaluation of our creditworthiness bycounterparties and rating agencies and the willingness of third parties to do business with us could be adversely impacted. Inparticular, such concerns by existing and potential counterparties could significantly limit TCEH's wholesale market activities,including its natural gas price hedging program.Under the terms of the indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior Secured Second LienNotes and the terms of the TCEH Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp.EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. At December 31,2012, TCEH and its subsidiaries held approximately 79% of EFH Corp.'s reported consolidated assets, and for the year endedDecember 31,2012, TCEH and its subsidiaries represented all of EFH Corp.'s reported consolidated revenues. Accordingly, TCEHand its subsidiaries constitute an important funding source for EFH Corp. to satisfy its obligations. However, under the terms ofthe indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes and the terms ofthe TCEN Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp., except in the form of certainloans to cover certain of EFH Corp.'s obligations (and dividends and distributions in certain other limited circumstances if permittedby applicable state law). Further, the indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior SecuredSecond Lien Notes and the terms of the TCEH Senior Secured Facilities do not permit such intercompany loans to service EFHCorp.'s debt unless required for EFH Corp. to pay principal, premium and interest when due on debt incurred by EFH Corp. tofinance the Merger or that was in existence prior to the Merger, or any debt incurred by EFH Corp. to replace, refund or refinancesuch debt. Such loans are also permitted in order to service other debt, subject to limitations on the amount of the loans. Inaddition, TCEH is prohibited from making certain loans to EFH Corp. if certain events of default under the indentures governingthe TCEH Senior Notes, Senior Secured Notes or Senior Secured Second Lien Notes or the terms of the TCEH Senior SecuredFacilities have occurred and are continuing. As of the date hereof, none of these events of default has occurred or is continuing.In addition, the TCEH Senior Secured Facilities contain provisions related to the TCEH Demand Notes, which are guaranteedby EFCH and EFIH on a senior unsecured basis and are demand notes, which means that TCEH can require payment of all or aportion of these notes at any time. These provisions include the following:" TCEH may only make loans to EFH Corp. for debt principal and interest payments;" borrowings outstanding under the TCEH Demand Notes will not exceed $2 billion in the aggregate at any time; and" the sum of(a) the outstanding senior secured indebtedness (including guarantees) issued by EFH Corp. or any subsidiaryof EFH Corp. (including EFIH) secured by a second-priority lien on the equity interests that EFIH owns in OncorHoldings (EFIH Second-Priority Debt) and (b) the aggregate outstanding amount of the TCEH Demand Notes will notexceed, at any time, the maximum amount of EFIH Second-Priority Debt permitted by the indenture governing the EFHCorp. Senior Secured Notes as in effect on April 7, 2011.25 Table of ContentsIf EFH Corp. reborrows amounts from TCEH under the TCEH Demand Notes in the future, a failure by EFH Corp. to repaythe TCEH Demand Notes when required, including as a result of any claims made by a creditor ofTCEH that these loans constitutedfraudulent transfers or breaches of fiduciary duty, could result in defaults under EFH Corp.'s other debt, including debt that EFCHand EFIH guarantee. It would also likely result in EFCH's and EFIH's guarantees of the TCEH Demand Notes being called, whichcould cause defaults under EFCH's and EFIH's other debt.Under the terms of the indentures governing certain of the EFIH Notes, EFIH is restricted from making certain payments toEFH Corp.EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. At December 31,2012, EFIH held approximately 17% of EFH Corp.'s reported consolidated assets, which assets consist primarily of EFIH'sinvestment in Oncor Holdings. Under the terms of the indentures governing certain of the EFIH Notes, EFIH is restricted frommaking certain payments, including dividends and loans, to EFH Corp., except in limited circumstances.EFH Corp. and EFIH have a very limited ability to control activities at Oncor due to structural and operational "ring-fencing"measures.EFH Corp. and EFIH depend upon Oncor for a significant amount of their cash flows and rely on such cash flows in orderto satisfy their obligations. However, EFH Corp. and EFIH have a very limited ability to control the activities of Oncor. As partof the "ring-fencing" measures implemented by EFH Corp. and Oncor, including certain measures required by the PUCT's Orderon Rehearing in Docket No. 34077, a majority of the members of Oncor's board of directors are required to meet the New YorkStock Exchange requirements for independence in all material respects, and the unanimous, or majority, consent of such directorsis required for Oncor to take certain actions. In addition, any new independent directors are required to be appointed by thenominating committee of Oncor Holdings' board of directors, a majority of whose members are independent directors. No memberof EFH Corp.'s or EFIH's management is a member ofOncor's board ofdirectors. Under Oncor Holdings' and Oncor's organizationaldocuments, EFH Corp. has limited indirect consent rights with respect to the activities of Oncor, including (i) new issuances ofequity securities by Oncor, (ii) material transactions with third parties involving Oncor outside of the ordinary course of business,(iii) actions that cause Oncor's assets to be subject to an increased level of jurisdiction of the FERC, (iv) any changes to the stateof formation of Oncor, (v) material changes to accounting methods not required by US GAAP, and (vi) actions that fail to enforcecertain tax sharing obligations between Oncor and EFH Corp. In addition, Oncor's organizational agreements contain restrictionson Oncor's ability to make distributions to its members, including indirectly to EFH Corp. or EFIH.Risks Related to Our StructureEFH Corp. is a holding company and its obligations are structurally subordinated to existing andfuture liabilities andpreferredstock of its subsidiaries. /EFH Corp.'s cash flows and ability to meet its obligations are largely dependent upon the earnings of its subsidiaries andthe payment of such earnings to EFH Corp. in the form of dividends, distributions, loans or otherwise, and repayment of loans oradvances from EFH Corp. These subsidiaries are separate and distinct legal entities and have no obligation (other than any existingcontractual obligations) to provide EFH Corp. with funds for its payment obligations. Any decision by a subsidiary to provideEFH Corp. with funds for its payment obligations, whether by dividends, distributions, loans or otherwise, will depend on, amongother things, the subsidiary's results of operations, financial condition, cash requirements, contractual restrictions and other factors.In addition, a subsidiary's ability to pay dividends may be limited by covenants in its existing and future debt agreements orapplicable law. Further, the distributions that may be paid by Oncor are limited as discussed below.Because EFH Corp. is a holding company, its obligations to its creditors are structurally subordinated to all existing andfuture liabilities and existing and future preferred stock of its subsidiaries that do not guarantee such obligations. Therefore, withrespect to subsidiaries that do not guarantee EFH Corp.'s obligations, EFH Corp.'s rights and the rights of its creditors to participatein the assets of any subsidiary in the event that such a subsidiary is liquidated or reorganized are subject to the prior claims of suchsubsidiary's creditors and holders of such subsidiary's preferred stock. To the extent that EFH Corp. may be a creditor withrecognized claims against any such subsidiary, EFH Corp.'s claims would still be subject to the prior claims of such subsidiary'screditors to the extent that they are secured or senior to those held by EFH Corp. Subject to restrictions contained in financingarrangements, EFH Corp.'s subsidiaries may incur additional debt and other liabilities.26 Table of ContentsOncor may or may not make any distributions to EFH Corp. or EFIH.EFH Corp. and Oncor have implemented certain structural and operational "ring-fencing" measures, including certainmeasures required by the PUCT's Order on Rehearing in Docket No. 34077, that were based on principles articulated by ratingagencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor's creditquality. These measures were put in place to mitigate Oncor's credit exposure to the Texas Holdings Group and to reduce the riskthat the assets and liabilities of Oncor would be substantively consolidated with the assets and liabilities of the Texas HoldingsGroup in the event of a bankruptcy of one or more of those entities.As part of the ring-fencing measures, a majority of the members of the board of directors of Oncor are required to be, andare, independent from EFH Corp. and EFIH. Any new independent directors ofOncor are required to be appointed by the nominatingcommittee of Oncor Holdings, which is required to be, and is, comprised of a majority of directors that are independent from EFHCorp. and EFIH. The organizational documents of Oncor give these independent directors, acting by majority vote, and, duringcertain periods, any director designated by Texas Transmission, the express right to prevent distributions from Oncor if theydetermine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, therecan be no assurance that Oncor will make any distributions to EFH Corp. or EFIH.In addition, Oncor's organizational documents prohibit Oncor from making any distribution to its owners, including EFHCorp. and EFIH, so long as and to the extent that such distribution would cause Oncor's regulatory capital structure to exceed thedebt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to40% equity.In 2009, the PUCT awarded Oncor the right to construct transmission lines and facilities associated with its CREZTransmission Plan, the cost ofwhich is estimated by Oncorto be approximately $2.0 billion (see discussion in Item 7, "Management'sDiscussion and Analysis of Financial Condition and Results of Operations- Significant Activities and Events and Items InfluencingFuture Performance -Oncor Matters with the PUCT"). With the award, Oncor has incurred additional debt. In addition, Oncormay incur additional debt in connection with other investments in infrastructure or technology. Accordingly, while Oncor isrequired to maintain a specified debt-to-equity ratio, there can be no assurance that Oncor's equity balance will be sufficient tomaintain the required debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, thereby restrictingOncor from making any distributions to EFH Corp. or EFIH. In addition, any increase in Oncor's interest expense, including asa result of any adverse action with respect to Oncor's credit ratings as discussed below, may reduce the amounts available to bedistributed to EFH Corp. or EFIH.Oncor's ring-fencing measures may not work as planned and a bankruptcy court may nevertheless subject Oncor to the claimsof Texas Holdings Group entity creditors.In 2007, EFH Corp. and Oncor implemented certain structural and operational "ring-fencing" measures, including certainmeasures required by the PUCT's Order on Rehearing in Docket No. 34077, that were based on principles articulated by ratingagencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor's creditquality. These measures were put in place to mitigate Oncor's credit exposure to the Texas Holdings Group and to minimize therisk that a court would order any of Oncor Holdings', Oncor's or Oncor's subsidiary's (collectively, the Oncor Ring-Fenced Entities)assets and liabilities to be substantively consolidated with those of any member of the Texas Holdings Group in the event that amember of the Texas Holdings Group were to become a debtor in a bankruptcy case. Substantive consolidation is an equitableremedy in bankruptcy that results in the pooling of the assets and liabilities of the debtor and one or more of its affiliates solelyfor purposes of the bankruptcy case, including for purposes of distributions to creditors and voting on and treatment under areorganization plan. Bankruptcy courts have broad equitable powers, and as a result, outcomes in bankruptcy proceedings areinherently difficult to predict. To the extent a bankruptcy court were to determine that substantive consolidation was appropriateunder the facts and circumstances, then the assets and liabilities of any Oncor Ring-Fenced Entity that were subject to the substantiveconsolidation order would be available to help satisfy the debt or contractual obligations of the Texas Holdings Group entity thatwas a debtor in bankruptcy and subject to the same substantive consolidation order. However, even if any Oncor Ring-FencedEntity were included in such a substantive consolidation order, the secured creditors of Oncor would retain their liens and prioritywith respect to Oncor's assets.If any member of the Texas Holdings Group were to become a debtor in a bankruptcy case, there can be no assurance thata court would not order an Oncor Ring-Fenced Entity's assets and liabilities to be substantively consolidated with those of suchmember of the Texas Holdings Group or that a proceeding would not result in a disruption of services Oncor receives from, orjointly with, our affiliates. See Note 1 to Financial Statements for additional information on ring-fencing measures.27 Table of ContentsIn addition, Oncor's access to capital markets and cost of debt could be directly affected by its credit ratings. Any adverseaction with respect to Oncor's credit ratings would generally cause borrowing costs to increase and the potential pool of investorsand funding sources to decrease. Oncor's credit ratings are currently substantially higher than those of the Texas Holdings Group.If credit rating agencies were to change their views of Oncor's independence from any member of the Texas Holdings Group,Oncor's credit ratings would likely decline. Despite the ring-fencing measures, rating agencies have in the past, and could in thefuture, take an adverse action with respect to Oncor's credit ratings in response to liability management or other activities by EFHCorp. or any of its subsidiaries, including the incurrence of debt by EFH Corp. and/or EFIH which is secured by a lien on theequity of Oncor Holdings held by EFIH. In the event any such adverse action takes place and causes Oncor's borrowing costs toincrease, it may not be able to recover these increased costs if they exceed Oncor's PUCT-approved cost of debt determined in itsmost recent rate case or subsequent rate cases.Risks Related to Our BusinessesTCEH's revenues and results of operations generally are negatively impacted by decreases in market prices for electricity,natural gas prices and/or market heat rates.TCEH is not guaranteed any rate of return on capital investments in its businesses. We market and trade electricity, includingelectricity from our own generation facilities and generation contracted from third parties, as part of our wholesale operations.TCEH's results of operations depend in large part upon wholesale market prices for electricity, natural gas, uranium, coal, fuel oiland transportation in its regional market and other competitive markets and upon prevailing retail electricity rates, which may beimpacted by, among other things, actions of regulatory authorities. Market prices may fluctuate substantially over relatively shortperiods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. Duringperiods of over-supply, prices might be depressed. Also, at times, there may be political pressure, or pressure from regulatoryauthorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations,bidding rules and other mechanisms to address volatility and other issues in these markets.Some of the fuel for our generation facilities is purchased under short-term contracts. Prices of fuel (including diesel, naturalgas, coal and nuclear fuel) may also be volatile, and the price we can obtain for electricity sales may not change at the same rateas changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility inthese markets may affect costs incurred in meeting obligations.Volatility in market prices for fuel and electricity may result from the following:" volatility in natural gas prices;" volatility in ERCOT market heat rates;" volatility in coal and rail transportation prices;" severe or unexpected weather conditions, including drought and limitations on access to water;" seasonality;" changes in electricity and fuel usage;* illiquidity in the wholesale power or other commodity markets;" transmission or transportation constraints, inoperability or inefficiencies;" availability of competitively-priced alternative energy sources;" changes in market structure;" changes in supply and demand for energy commodities, including nuclear fuel and related enrichment and conversionservices;" changes in the manner in which we operate our facilities, including curtailed operation due to market pricing,environmental, safety or other factors;" changes in generation efficiency;" outages or otherwise reduced output from our generation facilities or those of our competitors;" changes in the credit risk or payment practices of market participants;" changes in production and storage levels of natural gas, lignite, coal, crude oil, diesel and other refined products;* natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and* federal, state and local energy, environmental and other regulation and legislation.28 Table of ContentsAll of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets.Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas because marginal electricitydemand is generally supplied by natural gas-fueled generation facilities. Accordingly, our earnings and the value of our nuclearand lignite/coal-fueled generation assets, which provided a substantial portion of our supply volumes in 2012, are dependent insignificant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008 (from$11.12 per MMBtu in mid-2008 to $4.03 per MMBtu at December 31, 2012 for calendar year 2014). In recent years natural gassupply has outpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weaknessassociated with the economic downturn. Many industry experts expect this supply/demand imbalance to continue for a numberof years, thereby depressing natural gas prices for a long-term period.Wholesale electricity prices also have generally moved with ERCOT market heat rates, which could fall if demand forelectricity were to decrease or if more efficient generation facilities are built in ERCOT. Accordingly, our earnings and the valueof our nuclear and lignite/coal-fueled generation assets are also dependent in significant part upon market heat rates. As a result,our nuclear and lignite/coal-fueled generation assets could significantly decrease in profitability and value if ERCOT market heatrates decline.Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedgingtransactions may not work as planned or hedge counterparties may default on their obligations.We cannot fully hedge the risk associated with changes in commodity prices, most notably electricity and natural gas prices,because of the expected useful life of our generation assets and the size of our position relative to market liquidity. To the extentwe have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations,liquidity and financial position, either favorably or unfavorably.To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portionsof purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, crude oil, diesel fuel, uraniumand refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinelyutilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of riskmanagement procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place maynot always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge theexpected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, consumer behavior,market constraints or other factors could cause us to purchase power to meet unexpected demand in periods of high wholesalemarket prices or resell excess power into the wholesale market in periods of low prices. As a result of these and other factors, wecannot precisely predict the impact that risk management decisions may have on our businesses, results of operations, liquidityor financial position.With the tightening of credit markets that began in 2008 and the expansion of regulatory oversight through various financialreforms, there has been some decline in the number of market participants in the wholesale energy commodities markets, resultingin less liquidity, particularly in the ERCOT electricity market. Participation by financial institutions and other intermediaries(including investment banks) has particularly declined. Extended declines in market liquidity could materially affect our abilityto hedge our financial exposure to desired levels.To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that oweus money, energy or other commodities as a result of these activities will not perform their obligations. Should the counterpartiesto these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlyingcommitment at then-current market prices. In such event, we could incur losses in addition to amounts, if any, already paid to thecounterparties. ERCOT market participants are also exposed to risks that another ERCOT market participant may default on itsobligations to pay ERCOT for power taken, in which case such costs, to the extent not offset by posted security and other protectionsavailable to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in thefuture impact, our businesses and/or results of operations.Our businesses operate in changing market environments influenced by various state and federal legislative and regulatoryinitiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. Wewill need to continually adapt to these changes.29 Table of ContentsOur businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic EnergyAct, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act, the Energy Policy Act of 2005 and the Dodd-FrankWall Street Reform and Consumer Protection Act), changing governmental policy and regulatory actions (including those of thePUCT, the NERC, the TRE, the RRC, the TCEQ, the FERC, the EPA, the NRC and the CFTC) and the rules, guidelines andprotocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nucleargeneration facilities, construction and operation of other generation facilities, construction and operation of transmission facilities,acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments,decommissioning costs, return on invested capital for regulated businesses, market behavior rules, present or prospective wholesaleand retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricingconstraints and market behavior and other competition-related rules and regulations under PURA that are administered by thePUCT and ERCOT, and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior andother competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in,revisions to, or reinterpretations of existing laws and regulations may have a material effect on our businesses.The Texas Legislature meets every two years (the current legislative session began in January 2013); however, at any timethe governor of Texas may convene a special session of the Legislature. During any regular or special session bills may beintroduced that, if adopted, could materially affect our businesses, including our results of operations, liquidity or financialcondition.The PUCT and the RRC are subject to a "Sunset" review by the Texas Sunset Advisory Commission during the 2013 sessionof the Texas Legislature. The powers of the PUCT and the RRC may be materially changed, or the agencies maybe abolished,by the Texas Legislature following such review. If the PUCT or the RRC are not renewed or are changed materially by theTexas Legislature pursuant to Sunset review, it could have a material effect on our businesses.Sunset review is the regular assessment of the continuing need for a state agency to exist, and is grounded in the premisethat an agency will be abolished unless legislation is passed to continue its functions. On a specified time schedule, the TexasSunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agency to theTexas Legislature, which action may include modifying or even abolishing the agency. The PUCT and the RRC are subject toreview by the Sunset Commission in 2013. In 2011, the Texas Legislature extended the authority of the RRC and the PUCT until2013. In 2013, the RRC will undergo a full sunset review, and the PUCT will undergo a limited sunset review. These agencies,for the most part, govern and operate the electricity and mining markets in Texas upon which our business model is based. If theTexas Legislature materially changes or fails to renew either of these agencies, it could have a material impact on our business.There can be no assurance that future action of the Sunset Commission will not result in legislation during the 2013 LegislativeSession that could have a material effect on our results of operations, liquidity or financial condition.Our cost of compliance with existing and new environmental laws could materially affect our results of operations, liquidityand financial condition.We are subject to extensive environmental regulation by governmental authorities, including the EPA and the TCEQ. Inoperating our facilities, we are required to comply with numerous environmental laws and regulations and to obtain numerousgovernmental permits. We may incur significant additional costs beyond those currently contemplated to comply with theserequirements. If we fail to comply with these requirements, we could be subject to civil or criminal liabilities and fines. Existingenvironmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable tous or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory andenforcement developments related to air emissions, all of which could result in significant additional costs beyond those currentlycontemplated to comply with existing requirements (see Note 9 to Financial Statements).Over the past couple of years, the EPA has completed several regulatory actions establishing new requirements for controlof certain emissions from sources including electricity generation facilities. It is also currently considering several other regulatoryactions, as well as contemplating future additional regulatory actions, in each case that may affect our generation facilities or ourability to cost-effectively develop new generation facilities. There is no assurance that the currently-installed emissions controlequipment at our coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Someof the recent regulatory actions, such as the EPA's CSAPR and MATS, could require us to install significant additional controlequipment, resulting in material costs of compliance for our generation units, including capital expenditures, higher operating andfuel costs and potential production curtailments if the rules take effect. These costs could result in material effects on our resultsof operations, liquidity and financial condition.30 Table of ContentsWe may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtainingany required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approvalis retroactively disallowed, the operation of our facilities could be stopped, curtailed or modified or become subject to additionalcosts.In addition, we may be responsible for any on-site liabilities associated with the enviromnental condition of facilities thatwe have acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. Inconnection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certainenvironmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or failto meet its indemnification obligations to us.Our results of operations, liquidity and financial condition maiy be materially affected if new federal and/or state legislationor regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons orproperty resulting from greenhouse gas emissions.There is a concern nationally and internationally about global climate change and how greenhouse gas (GHG) emissions,such as carbon dioxide (CO2), contribute to global climate change. Over the last few years, several bills addressing climate changehave been introduced in the US Congress or discussed by the Obama Administration that were intended to address climate changeusing different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the development of low-carbon technology and federal renewableportfolio standards. In addition, a number of federal court cases have been filed in recent years asserting damage claims relatedto GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (includingus) that produce GHG emissions.The EPA rule known as the Prevention of Significant Deterioration (PSD) tailoring rule established thresholds for regulatingGHG emissions from stationary sources under the Clean Air Act. The rule requires any source subject to the PSD permittingprogram, due to emissions of non-GHG pollutants, that increases its GHG emissions by 75,000 tons per year (tpy) to have anoperating permit under the Title V Operating Permit Program of the Clean Air Act and install the best available control technologyin conjunction with construction activities or plant modifications. PSD permitting requirements also apply to new projects withGHG emissions of at least 100,000 tpy and modifications to existing facilities that increase GHG emissions by at least 75,000 tpy(even if no non-GHG PSD thresholds are exceeded). The EPA has also issued regulations that require certain categories of GHGemitters (including our lignite/coal-fueled generation facilities) to monitor and report their annual GHG emissions.In March 2012, the EPA released a proposal for a performance standard for greenhouse gas emissions from new electricgeneration units (EGUs). The proposal, which is currently limited to new sources, is based on the carbon dioxide emission ratefrom a natural gas-fueled combined cycle EGU. None of our existing generation units would be considered a new source underthe proposed rule. While we do not believe the proposed rule, as released, affects our existing generation units, it could affect ourability to cost-effectively develop new generation facilities. If limits or guidelines become applicable to our generation facilitiesand require us to install new control equipment or substantially alter our operations, it could have a material effect on our resultsof operations, liquidity and financial condition.We produce GHG emissions from the combustion of fossil fuels at our generation facilities. Because a substantial portionof our generation portfolio consists of lignite/coal-fueled generation facilities, our results of operations, liquidity and financialcondition could be materially affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissionsor that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowancesor credits to comply with such a program. The EPA regulation of GHGs under the Clean Air Act, or judicially imposed sanctionsor damage awards related to GHG emissions, may require us to make material expenditures to reduce our GHG emissions. Inaddition, if a significant number of our customers or others refuse to do business with us because of our GHG emissions, it couldhave a material effect on our results of operations, liquidity or financial condition.31 Table of ContentsLitigation related to environmental issues, including claims alleging that GHG emissions constitute a public nuisance bycontributing to global climate change, has increased in recent years. American Electric Power Co. v. Connecticut, Comer v. MurphyOil USA and Native Village ofKivalina v. ExxonMobil Corporation all involve nuisance claims for damages purportedly causedby the defendants' emissions of GHGs. Although we are not currently a party to any pending lawsuits alleging that GHG emissionsare a public nuisance, these lawsuits could establish precedent that might affect our business or industry generally. Other similarlawsuits have involved claims of property damage, personal injury, challenges to issued permits and citizen enforcement ofenvironmental laws and regulations. We cannot predict the ultimate outcome of the pending proceedings. If we are sued in theseor similar proceedings and are ultimately subject to an adverse ruling, we could be required to make substantial capital expendituresfor emissions control equipment, halt operations and/or pay substantial damages. Such expenditures or the cessation of operationscould adversely affect our results of operations, liquidity and financial condition.If we are required to comply with the EPA's revised Cross-State Air Pollution Rule (CSAPR), or a similar replacement, andthe Mercury and Air Toxics Standard (MATS) we will likely incur material capital expenditures and operating costs andexperience material revenue decreases due to reduced generation and wholesale electricity sales volumes.In July 2011, the EPA issued the CSAPR, a replacement for the Clean Air Interstate Rule (CAIR). In February 2012, theEPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including emissions budgetsfor the State of Texas as discussed in Items I and 2, "Business and Properties -Environmental Regulations and RelatedConsiderations -Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions." In June 2012, the EPA finalized the proposed rule(Second Revised Rule). In total, the emissions budgets established by the Final Revisions along with the Second Revised Rulewould require our fossil-fueled generation units to reduce (i) their annual SO2 and NOx emissions by approximately 120,600 tons(56 percent) and 9,000 tons (22 percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NOx emissions byapproximately 3,300 tons (18 percent), compared to 2010 levels. We could comply with these emissions limits either throughphysical reductions or through the purchase of emissions credits from third parties, but the volume of SO2 credits that may bepurchased from sources outside of Texas is subject to limitations starting in 2014. Because the CSAPR was vacated and remandedto the EPA in August 2012 by a three judge panel of the D.C. Circuit Court, the CSAPR, the Final Revisions and the SecondRevised Rule do not impose any immediate legal or compliance requirements on us, the State of Texas, or other affected parties.In October 2012, the EPA and certain other parties that supported the CSAPR filed petitions seeking review by the full court ofthe D.C. Circuit Court's ruling. In January 2013, the D.C. Circuit Court denied the request for rehearing. The EPA and the otherparties to these proceedings have approximately 90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court.We cannot predict whether, when, or in what form the CSAPR, the Final Revisions, the Second Revised Rule or any replacementswill take effect.Material capital expenditures would be required to comply with the CSAPR, as revised in June 2012, as well as with otherpending and expected environmental regulations, including the MATS, for which we and certain states and industry participantshave filed petitions for review in the D.C. Circuit Court. We cannot predict the outcome of these petitions.Prior to the publication of the final MATS rule and the vacatur and remand of the CSAPR, we estimated that expendituresof more than $1.5 billion before the end of the decade in environmental control equipment would be required to comply withregulatory requirements, including the CSAPR and MATS. We have revised our estimates ofcapital expenditures for environmentalcontrol equipment to comply with regulatory requirements, based on analysis and testing of options to comply with the MATSrule, as well as estimates related to other EPA regulations, including expenditures previously incurred related to the CSAPR.Between 2011 and the end ofthe decade, we estimate that we will incur more than $1 billion in capital expenditures for environmentalcontrol equipment, though the ultimate total will depend on the evolution of pending or future regulatory requirements. Basedon regulations currently in effect, we estimate that we will incur approximately $500 million of environmental capital expendituresbetween 2013 and 2017, including amounts required to maintain installed environmental control equipment.We cannot predict whether the EPA or any other party will appeal the D.C. Circuit Court's decision with respect to the CSAPRto the US Supreme Court or, if such appeal is granted, how the US Supreme Court will rule on any such appeal of the CSAPR.As a result, there can be no assurance that we will not be required to implement a compliance plan for the CSAPR, the FinalRevisions, the Second Revised Rule or any replacement rules in a short time frame or that such plan will not materially affect ourresults of operations, liquidity or financial condition.32 Table of ContentsLuminant's mining permits are subject to RRC review.The RRC reviews on an ongoing basis whether Luminant is compliant with RRC rules and regulations and whether it hasmet all of the requirements of its mining permits. Any revocation of a mining permit would mean that Luminant would no longerbe allowed to mine lignite at the applicable mine to serve its generation facilities. Such event would have a material effect on ourresults of operations, liquidity and financial condition.Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significantliabilities and reputation damage, and have a material effect on our results of operations, and the litigation environment inwhich we operate poses a significant risk to our businesses.We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, andenvironmental issues, and other claims for injuries and damages, among other matters. We evaluate litigation claims and legalproceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Basedon these evaluations and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, asappropriate. These evaluations and estimates are based on the information available to management at the time and involve asignificant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. Thesettlement or resolution of such claims or proceedings may have a material effect on our results of operations. We use appropriatemeans to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significantbusiness risk.We are involved in the ordinary course of business in permit applications and renewals, and we are exposed to the risk thatcertain of our operating permit applications may not be granted or that certain of our operating permits may not be renewed onsatisfactory terms. Failure to obtain and maintain the necessary permits to conduct our businesses could have a material effect onour results of operations, liquidity and financial condition.We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings,and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings.See Item 3, "Legal Proceedings -Regulatory Reviews." While we cannot predict the outcome of any regulatory investigation oradministrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring materialpenalties and/or other costs and have a material effect on our results of operations, liquidity and financial condition.Our collateral requirements for hedging arrangements could be materially impacted if the remaining rules implementing theFinancial Reform Act broaden the scope of the Act's provisions regarding the regulation of over-the-counter financialderivatives, making certain provisions applicable to end-users like us.In July 2010, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (theFinancial Reform Act) was enacted. While the legislation is broad and detailed, a few key rulemaking decisions remain to bemade by federal governmental agencies to fully implement the Financial Reform Act.Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives (Swaps) market.The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we useto hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However,under the end-user clearing exemption, entities are exempt from these clearing requirements if they (i) are not "Swap Dealers" or"Major Swap Participants" and (ii) use Swaps to hedge or mitigate commercial risk. The legislation mandates significant compliancerequirements for any entity that is determined to be a Swap Dealer or Major Swap Participant and additional reporting andrecordkeeping requirements for all entities that participate in the derivative markets. See Item 7, "Management's Discussion andAnalysis of Financial Condition and Results of Operations -Key Risks and Challenges -Financial Services Reform Legislation."The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateralrequirements are unclear as to whether an end-user or its counterparty (e.g., swap dealer) is required to post cash collateral, thereis risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. The final rule formargin requirements has not been issued. However, the legislative history of the Financial Reform Act suggests that it was notCongress' intent to require end-users to post cash collateral with respect to swaps. If we were required to post cash collateral onour swap transactions with swap dealers, our liquidity would likely be materially impacted, and our ability to enter into derivativesto hedge our commodity and interest rate risks would be significantly limited.33 Table of ContentsWe cannot predict the outcome of the final rulemakings to implement the OTC derivative market provisions of the FinancialReform Act. Based on our assessment and published guidance from the CFTC, we are not a Swap Dealer or Major Swap Participantand we will be able to take advantage of the End-User Exemption for Swaps that hedge or mitigate commercial risk; however, theremaining rulemakings related to how Swap Dealers and other market participants administer margin requirements could negativelyaffect our ability to hedge our commodity and interest rate risks. The inability to hedge these risks would likely have a materialeffect on our results of operations, liquidity and financial condition.We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generationfacility.The ownership and operation of a nuclear generation facility involves certain risks. These risks include:" unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity or other problems;" inadequacy or lapses in maintenance protocols;" the impairment of reactor operation and safety systems due to human error or force majeure;" the costs of storage, handling and disposal of nuclear materials, including availability of storage space;" the costs of procuring nuclear fuel;" the costs of securing the plant against possible terrorist or cybersecurity attacks;* limitations on the amounts and types of insurance coverage commercially available, and* uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end oftheir useful lives.The prolonged unavailability of Comanche Peak could materially affect our financial condition and results of operations.The following are among the more significant of these risks:" Operational Risk -Operations at any nuclear generation facility could degrade to the point where the facility wouldhave to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of theoperational downgrade to return the facility to operation could require significant time and expense, resulting in bothlost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-downor failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availabilityat Comanche Peak." Regulatory Risk -The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to complywith the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unlessextended, the NRC operating licenses for Comanche Peak Unit I and Unit 2 will expire in 2030 and 2033, respectively.Changes in regulations by the NRC, including potential regulation as a result of the NRC's ongoing analysis and responseto the effects of the natural disaster on nuclear generation facilities in Japan in 2010, could require a substantial increasein capital expenditures or result in increased operating or decommissioning costs." Nuclear Accident Risk-- Although the safety record of Comanche Peak and other nuclear generation facilities generallyhas been very good, accidents and other unforeseen problems have occurred both in the US and elsewhere. Theconsequences of an accident can be severe and include loss of life, injury, lasting negative health impact and propertydamage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any suchresulting liability from a nuclear accident could exceed our resources, including insurance coverage.34 Table of ContentsThe operation and maintenance of electricity generation and delivery facilities involves significant risks that could adverselyaffect our results of operations, liquidity and financial condition.The operation and maintenance of electricity generation and delivery facilities involves many risks, including, as applicable,start-up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specificfuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance belowexpected levels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increasedexpenses. A significant number of our facilities were constructed many years ago. In particular, older generating equipment andtransmission and distribution equipment, even if maintained in accordance with good engineering practices, may require significantcapital expenditures to keep operating at peak efficiency or reliability. The risk of increased maintenance and capital expendituresarises from (i) increased starting and stopping of generation equipment due to the volatility of the competitive generation marketand the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all ourgenerating facilities, (ii) any unexpected failure to generate electricity, including failure caused by equipment breakdown or forcedoutage, (iii) damage to facilities due to storms, natural disasters, wars, terrorist or cybersecurity acts and other catastrophic eventsand (iv) the passage of time and normal wear and tear. Further, our ability to successfully and timely complete capital improvementsto existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any suchefforts be unsuccessful, we could be subject to additional costs and/or losses and write downs of our investment in the project orimprovement.We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safetylaws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events(such as natural disasters or terrorist or cybersecurity attacks). The unexpected requirement of large capital expenditures couldmaterially affect our results of operations, liquidity and financial condition.If we make any major modifications to our power generation facilities, we may be required to install the best availablecontrol technology or to achieve the lowest achievable emission rates as such terms are defined under the new source reviewprovisions of the Clean Air Act. Any such modifications would likely result in us incurring substantial additional capitalexpenditures.Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses thatcould result from the risks discussed above, including the cost of replacement power. Likewise, the ability to obtain insurance,and the cost of and coverage provided by such insurance, could be affected by events outside our control.Our results of operations, liquidity and financial condition may be materially affected by the effects of extreme weatherconditions.Our results of operations may be affected by weather conditions and may fluctuate substantially on a seasonal basis as theweather changes. In addition, we could be subject to the effects of extreme weather. Extreme weather conditions could stress ourtransmission and distribution system or our generation facilities resulting in outages, increased maintenance and capitalexpenditures. Extreme weather events, including sustained cold temperatures, hurricanes, storms or other natural disasters, couldbe destructive and result in casualty losses that are not ultimately offset by insurance proceeds or in increased capital expendituresor costs, including supply chain costs.Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damageto other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weatherevent might affect the availability of generation and transmission capacity, limiting our ability to source or deliver electricity whereit is needed or limit our ability to source fuel for our plants (including due to damage to rail infrastructure). These conditions,which cannot be reliably predicted, could have an adverse consequence by requiring us to seek additional sources of electricitywhen wholesale market prices are high or to sell excess electricity when market prices are low.Our results of operations, liquidity and financial condition may be materially affected by insufficient water supplies.Supplies of water are important for our generation facilities. Water in Texas is limited and various parties have madeconflicting claims regarding the right to access and use such limited supplies of water. In addition, Texas has experienced sustaineddrought conditions that could affect the water supply for certain of our generation facilities if adequate rain does not fall in thewatershed that supplies the affected areas. If we are unable to access sufficient supplies of water, it could restrict, prevent orincrease the cost of operations at certain of our generation facilities.35 Table of ContentsThe rates of Oncor's electricity delivery business are subject to regulatory review, and may be reduced below current levels,which could adversely impact Oncor's results of operations, liquidity and financial condition.The rates charged by Oncor are regulated by the PUCT and certain cities and are subject to cost-of-service regulation andannual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Oncor'srates are regulated based on an analysis of Oncor's costs and capital structure, as reviewed and approved in a regulatory proceeding.While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital,there can be no assurance that the PUCT will judge all of Oncor's costs to have been prudently incurred, that the PUCT will notreduce the amount of invested capital included in the capital structure that Oncor's rates are based upon, or that the regulatoryprocess in which rates are determined will always result in rates that will produce full recovery of Oncor's costs, including regulatoryassets reported on Oncor's balance sheet, and the return on invested capital allowed by the PUCT. See Item 7, "Management'sDiscussion and Analysis of Financial Condition and Results of Operations- Significant Activities and Events and Items InfluencingFuture Performance -Oncor Matters with the PUCT" for discussion of recent and pending rate-related filings with the PUCT.Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significantadditional costs if unsuccessfuLAs we seek to improve our financial condition, we have taken, and intend to take steps to reduce our costs. While we havecompleted and have underway a number of initiatives to reduce costs, it will likely become increasingly difficult to identify andimplement significant new cost savings initiatives. The implementation of performance improvement initiatives identified bymanagement may not produce the desired reduction in costs and if unsuccessful, may instead result in significant additional costsas well as significant disruptions in our operations due to employee displacement and the rapid pace of changes to organizationalstructure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect onour results of operations, liquidity and financial condition.Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities and reputationdamage and disrupt business operations, which could have a material effect on our results of operations, liquidity andfinancialcondition.Much of our information technology infrastructure is connected (directly or indirectly) to the Internet. There have beennumerous attacks on government and industry information technology systems through the Internet that have resulted in materialoperational, reputation and/or financial costs. While we have controls in place designed to protect our infrastructure and have nothad any significant breaches, a breach of cyber/data security measures that impairs our information technology infrastructure coulddisrupt normal business operations and affect our ability to control our generation and transmission and distribution assets, accessretail customer information and limit communication with third parties. Any loss of confidential or proprietary data through abreach could adversely affect our reputation, expose the company to material legal/regulatory claims, impair our ability to executeon business strategies and/or materially affect our results of operations, liquidity and financial condition.As part of the continuing development of new and modified reliability standards, the FERC has approved changes to itsCritical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets."Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day per violation) for failure to complywith mandatory electric reliability standards, including standards to protect the power system against potential disruptions fromcyber and physical security breaches.Our retail operations (TXU Energy) may lose a significant number of customers due to competitive marketing activity by otherretail electric providers.Our retail operations face competition for customers. Competitors may offer lower prices and other incentives, which,despite the business' long-standing relationship with customers, may attract customers away from us. We operate in a verycompetitive retail market, as is reflected in a 21% decline in customers (based on meters) served over the last four years.In some retail electricity markets, our principal competitor may be the incumbent REP. The incumbent REP has the advantageof long-standing relationships with its customers, including well-known brand recognition.36 Table of ContentsIn addition to competition from the incumbent REP, we may face competition from a number ofother energy service providers,other energy industry participants, or nationally branded providers of consumer products and services who may develop businessesthat will compete with us. Some of these competitors or potential competitors may be larger or better capitalized than we are. Ifthere is inadequate potential margin in these retail electricity markets, it may not be profitable for us to compete in these markets.Our retail operations are subject to the risk that sensitive customer data may be compromised, which could result in an adverseimpact to our reputation and/or the results of the retail operations.Our retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitivecustomer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history,credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank accountinformation. Our retail business may need to provide sensitive customer data to vendors and service providers who require accessto this information in order to provide services, such as call center operations, to the retail business. If a significant breach occurred,the reputation of our retail business may be adversely affected, customer confidence may be diminished, or our retail businessmay be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the businessand its results of operations, liquidity and financial condition.Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provideelectricity to, and to obtain information about, its customers. Any infrastructure failure could negatively impact customersatisfaction and could have a material negative impact on the business and results of operations.Our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities, as wellas Oncor's facilities, to deliver the electricity it sells to its customers. If transmission capacity is inadequate, our ability to sell anddeliver electricity may be hindered, and we may have to forgo sales or buy more expensive wholesale electricity than is availablein the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers mayexceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interruptsor impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service.Our retail operations offer bundled services to customers, with some bundled services offered at fixed prices and for fixedterms. If our costs for these bundled services exceed the prices paid by our customers, our results of operations could bematerially affectedOur retail operations offer customers a bundle of services that include, at a minimum, electricity plus transmission, distributionand related services. The prices we charge for the bundle of services or for the various components of the bundle, any of whichmay be fixed by contract with the customer for a period of time, could fall below our underlying cost to provide the componentsof such services.The REP certification of our retail operations is subject to PUCT review.The PUCT may at any time initiate an investigation into whether our retail operations comply with PUCT Substantive Rulesand whether we have met all of the requirements for REP certification, including financial requirements. Any removal or revocationof a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers. Suchdecertification could have a material effect on our results of operations, liquidity and financial condition.Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and/orOncor's electricity delivery facilities and may significantly impact our businesses in other ways as wellResearch and development activities are ongoing to improve existing and alternative technologies to produce electricity,including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. It is possiblethat advances in these or other technologies will reduce the costs of electricity production from these technologies to a level thatwill enable these technologies to compete effectively with our traditional generation facilities. Consequently, where we havefacilities, the profitability and market value of our generation assets could be significantly reduced. Changes in technology couldalso alter the channels through which retail customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be materially reduced.37 Table of ContentsElectricity demand could be reduced by increased conservation efforts and advances in technology, which could likewisesignificantly reduce the value of our generation assets and electricity delivery facilities. Certain regulatory and legislative bodieshave introduced or are considering requirements and/or incentives to reduce energy consumption. Effective energy conservationby our customers could result in reduced energy demand or significantly slow the growth in demand. Such reduction in demandcould materially reduce our revenues. Furthermore, we may incur increased capital expenditures if we are required to increaseinvestment in conservation measures.Our revenues and results of operations may be adversely impacted by decreases in wholesale market prices of electricity dueto the development of wind generation sources.A significant amount of investment in wind generation in the ERCOT market over the past few years has increased overallwind power generation capacity. Generally, the increased capacity has led to lower wholesale electricity prices (driven by lowermarket heat rates) in the regions at or near wind power development. As a result, the profitability of our generation facilities andpower purchase contracts, including certain wind generation power purchase contracts, has been impacted and could be furtherimpacted by the effects of the wind power development, and the value could significantly decrease if wind power generation hasa material sustained effect on market heat rates.Our results of operations andfinancial condition could be negatively impacted by any development or event beyond our controlthat causes economic weakness in the ERCOT market.We derive substantially all of our revenues from operations in the ERCOT market, which covers approximately 75% of thegeographical area in the State of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market,economic weakness in the ERCOT market could lead to reduced demand for electricity in the ERCOT market. Such a reductioncould have a material negative impact on our results of operations, liquidity and financial condition.Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets and/or duringtimes when there are significant changes in commodity prices. The inability to access liquidity, particularly on favorable terms,could materially affect our results of operations, liquidity and financial condition.Our businesses are capital intensive. We rely on access to financial markets and credit facilities as a significant source ofliquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The inabilityto raise capital or access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our ability tomeet our obligations or sustain and grow our businesses and could increase capital costs. Our access to the financial markets andcredit facilities could be adversely impacted by various factors, such as:" changes in financial markets that reduce available liquidity or the ability to obtain or renew credit facilities on acceptableterms;" economic weakness in the ERCOT or general US market;" changes in interest rates;" a deterioration, or perceived deterioration, of EFH Corp.'s (and/or its subsidiaries') creditworthiness or enterprise value;" a reduction in EFH Corp.'s or its applicable subsidiaries' credit ratings;" a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilitiesthat affects the ability of such lender(s) to make loans to us;" volatility in commodity prices that increases margin or credit requirements;" a material breakdown in our risk management procedures, and" the occurrence of changes in our businesses that restrict our ability to access credit facilities.Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the sizeof our hedging program, any significant increase in the price of natural gas could result in us being required to provide cash orletter of credit collateral in substantial amounts. Any perceived reduction in our creditworthiness could result in clearing agentsor other counterparties requesting additional collateral. An event of default by one or more of our hedge counterparties couldresult in termination-related settlement payments that reduce available liquidity if we owe amounts related to commodity contractsor delays in receipts of expected settlements if the hedge counterparties owe amounts to us. These events could have a materialnegative impact on our results of operations, liquidity and financial condition.In the event that the governmental agencies that regulate the activities of our businesses determine that the creditworthinessof any such business is inadequate to support our activities, such agencies could require us to provide additional cash or letter ofcredit collateral in substantial amounts to qualify to do business.38 Table of ContentsIn the event our credit facilities are being used largely to support the hedging program as a result of a significant increasein the price of natural gas or significant reduction in creditworthiness, we may have to forego certain capital expenditures or otherinvestments in our businesses or other business opportunities.Further, a lack of available liquidity could adversely impact the evaluation of our creditworthiness by counterparties andrating agencies. In particular, such concerns by existing and potential counterparties could significantly limit TCEH's wholesalemarkets activities, including any future hedging activities.The costs ofproviding postretirement benefits and relatedfunding requirements are subject to changes in value offund assets,benefit costs, demographics and actuarial assumptions and may have a material effect on our results of operations, liquidityand financial condition.Oncor provides, and to a limited extent, we provide pension benefits based on either a traditional defined benefit formulaor a cash balance formula, and we also provide (and Oncor participates in) certain health care and life insurance benefits to eligibleemployees and their eligible dependents upon the retirement of such employees. Our costs of providing such benefits and relatedfunding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors,assumptions and estimates, including the market value of the assets funding the pension and OPEB plans. Fluctuations in financialmarket returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.The values of the investments that fund the pension and OPEB plans are subject to changes in financial market conditions.Significant decreases in the values of these investments could increase the expenses of the pension plans and the costs of the OPEBplans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements arealso subject to changing employee demographics (including but not limited to age, compensation levels and years of accreditedservice), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates usedin determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and futurebenefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased ordecreased benefit costs in future periods. See Note 13 to Financial Statements for further discussion of our pension and OPEBplans, including certain pension plan amendments approved by EFH Corp. in August 2012.As discussed in Note 3 to Financial Statements, goodwill and/or other intangible assets not subject to amortization that wehave recorded in connection with the Merger are subject to at least annual impairment evaluations. As a result, we could berequired in the future to write off some or all of this goodwill and other intangible assets, such as the goodwill impairments of$L2 billion and $4.1 billion recorded in 2012 and 2010, respectively, which may cause adverse impacts on our results ofoperations and financial condition.In accordance with accounting standards, goodwill and certain other indefinite-lived intangible assets that are not subject toamortization are reviewed annually or, if certain conditions exist, more frequently, for impairment. Factors such as the economicclimate, market conditions, including the market prices for wholesale electricity and natural gas and market heat rates, environmentalregulation, and the condition of assets are considered when evaluating these assets for impairment. The actual timing and amountsof any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Any reduction in or impairmentof the value of goodwill or other intangible assets will result in a charge against earnings, which could cause a material impact onour reported results of operations and financial condition.The loss of the services of our key management and personnel could adversely affect our ability to operate our businesses.Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete forsuch personnel with many other companies, in and outside our industry, government entities and other organizations. We maynot be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attractnew personnel or retain existing personnel could have a material effect on our businesses.39 Table of ContentsThe Sponsor Group in the aggregate controls and may have conflicts of interest with us in the future.The Sponsor Group in the aggregate indirectly owns approximately 60% of EFH Corp.'s capital stock on a fully-dilutedbasis through its investment in Texas Holdings. As a result of this ownership and the Sponsor Group's aggregate ownership ininterests of the general partner of Texas Holdings, the Sponsor Group taken as a whole has control over decisions regarding ouroperations, plans, strategies, finances and structure, including whether to enter into any corporate transaction, and will have theability to prevent any transaction that requires the approval of EFH Corp.'s shareholders. The Sponsor Group is comprised ofKohlberg Kravis Roberts & Co. L.P., TPG and GS Capital Partners, each of which acts independently of the others with respectto its investment in EFH Corp. and Texas Holdings.The interests of these entities may differ in material respects from the interests of holders of EFH Corp. and its subsidiaries'debt. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of the SponsorGroup, as equity holders or as members of the board of directors of EFH Corp., might conflict with our noteholders' and othercreditors' interests. The Sponsor Group may also have an interest in pursuing acquisitions, divestitures, financings or othertransactions that, in their judgment, could enhance their equity investments, even though such transactions might involve risks toour noteholders and other creditors. Additionally, the agreements governing the terms of EFH Corp.'s subsidiaries' debt permitsthem to distribute cash to EFH Corp. to pay advisory fees, dividends or make other restricted payments under certain circumstances,and the Sponsor Group may have an interest in them doing so.Each member of the Sponsor Group is in the business of making investments in companies and may from time to timeacquire and hold interests in businesses that compete directly or indirectly with us. Members of the Sponsor Group may alsopursue acquisition opportunities that may be complementary to our businesses and, as a result, those acquisition opportunitiesmay not be available to us. So long as the members of the Sponsor Group, or other funds controlled by or associated with themembers of the Sponsor Group, continue to indirectly own, in the aggregate, a significant amount of the outstanding shares ofEFH Corp.'s common stock, even if such amount is less than 50%, the Sponsor Group will continue to be able to strongly influenceor effectively control our decisions.Item lB. UNRESOLVED STAFF COMMENTSNone.Item 3. LEGAL PROCEEDINGSSee Items 1 and 2, "Business and Properties -Environmental Regulations and Related Considerations -Sulfur Dioxide,Nitrogen Oxide and Mercury Air Emissions" for discussion of litigation regarding the CSAPR and the Texas State ImplementationPlan as well as certain other environmental regulations.Litigation Related to Generation FacilitiesIn November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak GroveManagement Company LLC's (Oak Grove) (a wholly-owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System(TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in theTravis County, Texas District Court. Plaintiffs sought a reversal of the TCEQ's order and a remand back to the TCEQ for furtherproceedings. Oral argument was held in this administrative appeal on October 23, 2012, and the court affirmed the TCEQ'sissuance of the TPDES permit to Oak Grove. In December 2012, plaintiffs appealed the district court's decision to the Third Courtof Appeals in Austin, Texas. While we cannot predict the timing or outcome of this proceeding, we believe the renewal andamendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.40 Table of ContentsIn September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (TexarkanaDivision) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violationsof the Clean Air Act (CAA) at Luminant's Martin Lake generation facility. In May 2012, the Sierra Club filed a lawsuit in the USDistrict Court for the Western District of Texas (Waco Division) against EFH Corp. and Luminant Generation Company LLC foralleged violations of the CAA at Luminant's Big Brown generation facility. The Big Brown and Martin Lake cases are currentlyscheduled for trial in November 2013. While we are unable to estimate any possible loss or predict the outcome, we believe thatthe Sierra Club's claims are without merit, and we intend to vigorously defend these lawsuits. In addition, in December 2010 andagain in October 2011, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating CAA provisions inconnection with Luminant's Monticello generation facility. In May 2012, the Sierra Club informed us that it may sue us forallegedly violating CAA provisions in connection with Luminant's Sandow 4 generation facility. While we cannot predict whetherthe Sierra Club will actually file suit regarding Monticello or Sandow 4 or the outcome of any resulting proceedings, we believewe have complied with the requirements of the CAA at all of our generation facilities.Regulatory ReviewsIn June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of theCAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, includingNew Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generationfacilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received alarge and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently receiveda notice of violation from the EPA, which has in some cases progressed to litigation or settlement. In July 2012, the EPA sent usa notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our MartinLake and Big Brown generation facilities. While we cannot predict whether the EPA will initiate enforcement proceedings underthe notice of violation, we believe that we have complied with all requirements of the CAA at all of our generation facilities. Wecannot predict the outcome of any resulting enforcement proceedings or estimate the penalties that might be assessed in connectionwith any such proceedings. In September 2012, we filed a petition for review in the United States Court of Appeals for the FifthCircuit Court seeking judicial review of the EPA's notice of violation. Given recent legal precedent subjecting agency orders likethe notice of violation to judicial review, we filed the petition for review to preserve our ability to challenge the EPA's issuanceof the notice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December 2012, the Fifth CircuitCourt issued an order that will delay a ruling on the EPA's motion to dismiss until after the case has been fully briefed and oralargument, if any, is held. We cannot predict the outcome of these proceedings.Other MattersWe are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutionsof which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity orfinancial condition.Item 4. MINE SAFETY DISCLOSURESWe currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities.These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safetyand Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RRC andOffice of Surface Mining. The MSHA inspects US mines, including ours, on a regular basis, and if it believes a violation of theMine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompaniedby a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction ofthe severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders andproposed assessments are provided in Exhibit 95(a) to this annual report on Form 10-K.41 Table of ContentsPART II.Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS ANDISSUER PURCHASES OF EQUITY SECURITIESEFH Corp.'s common stock is privately held and has no established public trading market.See Note 10 to Financial Statements for discussion of the restrictions on EFH Corp.'s ability to pay dividends.The number of holders of EFH Corp.'s common stock at February 19, 2013 totaled 121.Item 6. SELECTED FINANCIAL DATAEFH CORP. AND SUBSIDIARIESSELECTED CONSOLIDATED FINANCIAL DATA(millions of dollars, except ratios)Operating revenuesImpairment of goodwillNet income (loss)Net (income) loss attributable to noncontrollinginterestsNet income (loss) attributable to EFH Corp.Ratio of earnings to fixed charges (a)Cash provided by (used in) operating activitiesCash provided by (used in) financing activitiesCash used in investing activitiesCapital expenditures, including nuclear fuelYear Ended December 31,2012 2011 2010 2009 2008$ 5,636 S 7,040 $ 8,235 $ 9,546 $ 11,364$ (1,200) S -$ (4,100) $ (90) $ (8,860)$ (3,360) S (1,913) $ (2,812) $ 408 $ (9,998)$ (,6 $ -( $ -( $S (3,360) $ (1,913) $ (2,81211 $$$$$(818)3,373(1,468)(877)$$$$841(1,014)(535)(684)$$$$1,106(264)(468)(944)$$$$(64) $ 160344 $ (9,838)1.241,711 $ 1,505422 $ 2,837(2,633) $ (2,934)(2,545) $ (3,015)Total assetsProperty, plant & equipment -netGoodwill and intangible assetsInvestment in unconsolidated subsidiary (Note 2)CapitalizationLong-term debt, less amounts due currentlyEFH Corp. common stock equityNoncontrolling interests in subsidiariesTotalCapitalization ratiosLong-term debt, less amounts due currentlyEFH Corp. common stock equityNoncontrolling interests in subsidiariesTotalShort-term borrowingsLong-term debt due currentlyAt December 31,2012 2011 2010 2009 2008$ 40,970 $ 44,077 $ 46,388 $ 59,662 $ 59,263$ 18,705 $ 19,427 $ 20,366 $ 30,108 $ 29,522S 6,707 $ 7,997 $ 8,552 $ 17,192 $ 17,379$ 5,850 $ 5,720 $ 5,544 $ -$ -$ 37,815 $ 35,360 $ 34,226 $ 41,440 $ 40,838(11,025) (7,852) (5,990) (3,247) (3,673)102 95 79 1,411 1,355S 26,892 $ 27,603 $ 28,315 $ 39,604 $ 38,520140.6 % 128.1 % 120.9 % 104.6 % 106.0 %(41.0)% (28.4)% (21.2)% (8.2)% (9.5)%0.4% 0.3 % 0.3 % 3.6% 3.5 %100.0 % 100.0 % 100.0 % 100.0 % 100.0 %$ 2,136 $ 774 $ 1,221 $ 1,569 $ 1,237$ 103 $ 47 $ 669 $ 417 $ 385(a) Fixed charges exceeded earnings (see Exhibit 12(a)) by $4.715 billion, $3.217 billion, $2.531 billion and $10.469 billionfor the years ended December 31, 2012, 2011, 2010 and 2008, respectively.42 Table of ContentsNote: See Note I to Financial Statements "Basis of Presentation." Results for 2010 reflect the prospective adoption of amendedguidance regarding consolidation accounting standards related to variable interest entities that resulted in the deconsolidation ofOncor Holdings as discussed in Note 2 to Financial Statements and amended guidance regarding transfers of financial assets thatresulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and thefunding under the program now reported as short-term borrowings as discussed in Note 7 to Financial Statements. Results for2012 were significantly impacted by a goodwill impairment charge as discussed in Note 3 to Financial Statements. Results for2011 were significantly impacted by an impairment charge related to emissions allowance intangible assets as discussed in Note3 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 3to Financial Statements and debt extinguishment gains as discussed in Note 6 to Financial Statements. Results for 2008 weresignificantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets andnatural gas-fueled generation facilities.See Notes to Financial Statements.Quarterly Information (Unaudited)Results of operations by quarter are summarized below. In our opinion, all adjustments (consisting of normal recurringaccruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a fullyear's operations because of seasonal and other factors. All amounts are in millions of dollars and may not add to full year amountsdue to rounding.First Second Third FourthQuarter Quarter Quarter Quarter (a)2012:Operating revenues $ 1,222 $ 1,385 $ 1,752 $ 1,278Net loss $ (304) $ (696) $ (407) $ (1,952)First Second Third FourthQuarter Quarter Quarter (b) Quarter2011:Operating revenues $ 1,672 $ 1,679 $ 2,321 $ 1,368Net loss $ (362) $ (705) $ (710) $ (136)(a) Net loss includes the effect of a goodwill impairment charge (see Note 3 to Financial Statements).(b) Net loss includes the effect of an impairment charge related to emissions allowance intangible assets (see Note 3 to FinancialStatements).43 Table of ContentsItem 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONSThe following discussion and analysis of our financial condition and results of operations for the years ended December 31,2012, 2011 and 2010 should be read in conjunction with Selected Consolidated Financial Data and our audited consolidatedfinancial statements and the notes to those statements.All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwiseindicated.BusinessEFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through itsTCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. EFCHis a holding company and a wholly-owned subsidiary of EFH Corp., and TCEH is a wholly-owned subsidiary of EFCH. TCEHis a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricitygeneration, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales.EFIH is a holding company and a wholly-owned subsidiary of EFH Corp. Oncor Holdings, a holding company and a wholly-owned subsidiary of EFIH, holds an approximately 80% equity interest in Oncor. Oncor is engaged in regulated electricitytransmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH,which sell electricity to residential, business and other consumers.Various "ring-fencing" measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 2 to FinancialStatements for a discussion of the reporting of our investment in Oncor (and Oncor Holdings) as an equity method investmenteffective January 1, 2010 and a description of the "ring-fencing" measures implemented with respect to Oncor. These measureswere put in place to further enhance Oncor's credit quality and mitigate Oncor's exposure to the Texas Holdings Group with theintent to minimize the risk that a court would order any of the assets and liabilities of the Oncor Ring-Fenced Entities to besubstantively consolidated with those of any member of the Texas Holdings Group in the event any such member were to becomea debtor in a bankruptcy case. We believe, as several major credit rating agencies have acknowledged, that the likelihood of suchsubstantive consolidation of the Oncor Ring-Fenced Entities' assets and liabilities is remote in consideration of the ring-fencingmeasures and applicable law.Operating SegmentsWe have aligned and report our business activities as two operating segments: the Competitive Electric segment and theRegulated Delivery segment. The Competitive Electric segment consists largely of TCEH. The Regulated Delivery segmentconsists largely of our investment in Oncor. See Notes I and 2 to Financial Statements for discussion of the deconsolidation ofOncor and its parent, Oncor Holdings, effective in 2010.See Note 16 to Financial Statements for further information regarding reportable business segments.Significant Activities and Events and Items Influencing Future PerformanceNatural Gas Price Hedging Program and Other Hedging Activities -Because wholesale electricity prices in ERCOThave generally moved with natural gas prices, TCEH has a natural gas price hedging program designed to mitigate the effect ofnatural gas price changes on future electricity revenues. Under the program, we have entered into market transactions involvingnatural gas-related financial instruments, and at December 31, 2012, have effectively sold forward approximately 360 millionMMBtu of natural gas (equivalent to the natural gas exposure of approximately 42,000 GWh at an assumed 8.5 market heat rate)at weighted average annual hedge prices as shown in the table below. Volumes and hedge values associated with the natural gasprice hedging program are inclusive of offsetting purchases entered into to take into account new wholesale and retail electricitysales contracts and avoid over-hedging. This activity results in both commodity contract asset and liability balances pending thematurity and settlement of the offsetting transactions.44 jable of ContentsTaking together forward wholesale and retail electricity sales with the natural gas positions in the hedging program, we haveeffectively hedged an estimated 96% and 41% of the price exposure, on a natural gas equivalent basis, related to TCEH's expectedgeneration output for 2013 and 2014, respectively (assuming an 8.5 market heat rate). The natural gas positions were entered intowith the continuing expectation that wholesale electricity prices in ERCOT will generally move with prices of natural gas, whichwe expect to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOTmarket. If the relationship changes in the future, the cash flows targeted under the natural gas price hedging program may not beachieved.The company has entered into related put and call transactions (referred to as collars), primarily for 2014, that effectivelyhedge natural gas prices within a range. These transactions represented 42% of the positions in the natural gas price hedgingprogram at December 31, 2012, with the approximate weighted average strike prices under the collars being a floor of $7.80 perMM[Btu and a ceiling of $11.75 per MMBtu.The following table summarizes the natural gas positions in the hedging program at December 31, 2012:Measure 2013 2014 TotalNatural gas hedge volumes (a) mmn MVIBtu -211 -146 -357Weighted average hedge price (b) $/MMBtu -6.89 -7.80 -Average market price (c) $/MMBtu -3.54 -4.03Realization of hedge gains (d) S billions -$1.0 -$0.6 -$1.6(a) Where collars are reflected, the volumes are based on the notional position of the derivatives to represent protection againstdownward price movements. The notional volumes for collars are approximately 150 million MMBtu, which correspondsto a delta position of approximately 146 million MMBtu in 2014.(b) Weighted average hedge prices are based on prices of positions in the natural gas price hedging program (excluding offsettingpurchases to avoid over-hedging). Where collars are reflected, sales price represents the collar floor price.(c) Based on NYMEX Henry Hub prices.(d) Based on cumulative unrealized mark-to-market gain at December 31, 2012.Changes in the fair value of the instruments in the natural gas price hedging program are recorded as unrealized gains andlosses in net gain from commodity hedging and trading activities in the statement of income, which has and could continue toresult in significant volatility in reported net income. Based on the size of the natural gas price hedging program at December 31,2012, a $1 .00/M Btu change in natural gas prices across the hedged period would result in the recognition of up to approximately$360 million in pretax unrealized mark-to-market gains or losses.The natural gas price hedging program has resulted in reported net gains (losses) as follows:Year Ended December 31,2012 2011 2010Realized net gain $ 1,833 $ 1,265 $ 1,151Unrealized net gain (loss) including reversals of previously recordedamounts related to positions settled (1,540) (19) 1,165Total S 293 $ 1,246 $ 2,316The cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging program totaled$1.584 billion and $3.124 billion at December 31, 2012 and 2011, respectively. The decline was driven by settlement of maturingpositions.Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains orlosses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in the future. If naturalgas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negativeeffect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices ofthe hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricityprices and will in this context be viewed as having resulted in an opportunity cost.45 Table of ContentsThe significant cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging programreflects the sustained decline in forward market natural gas prices as presented in "Key Risks and Challenges" below. Forwardnatural gas prices have generally trended downward over the past several years. While the natural gas price hedging program isdesigned to mitigate the effect on earnings of low wholesale electricity prices, depressed forward natural gas prices are challengingto our liquidity and the long-term profitability of EFH Corp.'s competitive businesses. Specifically, low natural gas prices andtheir effect in ERCOT on wholesale electricity prices could have a material impact on our liquidity and TCEH's overall profitabilityfor periods in which TCEH does not have significant hedge positions. See Note I to Financial Statements.Also see Note 3 to Financial Statements for discussion regarding goodwill impairment charges recorded in 2012 and 2010.TCEH Interest Rate Swap Transactions -TCEH employs interest rate swaps to hedge exposure to its variable rate debt.As reflected in the table below, at December 31,2012, TCEH has entered into the following series of interest rate swap transactionsthat effectively fix the interest rates at between 5.5% and 9.3%.Fixed Rates Expiration Dates Notional Amount5.5% -9.3% February 2013 through October 2014 $18.46 billion (a)6.8% -9.0% October 2015 through October 2017 $12.60 billion (b)(a) Swaps related to an aggregate $2.6 billion principal amount of debt expired in 2012. Per the terms of the transactions, thenotional amount of swaps entered into in 2011 grew by $2.405 billion, substantially offsetting the expired swaps.(b) These swaps are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes$3 billion that expires in October 2015 with the remainder expiring in October 2017.We may enter into additional interest rate hedges from time to time.TCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achievedthrough the interest rate swaps. Basis swaps in effect at December 31, 2012 totaled $11.967 billion notional amount, a decreaseof $5.783 billion from December 31, 2011 reflecting both new and expired swaps. The basis swaps relate to debt outstandingthrough 2014.The interest rate swaps have resulted in net losses reported in interest expense and related charges as follows:Year Ended December 31,2012 2011 2010Realized net loss $ (670) $ (684) $ (673)Unrealized net gain (loss) 166 (812) (207)Total $ (504) $ (1,496) $ (880)The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.065 billion and$2.231 billion at December 31, 2012 and 2011, respectively, of which $65 million and $76 million (both pretax), respectively,were reported in accumulated other comprehensive income. These fair values can change materially as market conditions change,which could result in significant volatility in reported net income. For example, at December 31, 2012, a one percent change ininterest rates would result in an increase or decrease of approximately $675 million in our cumulative unrealized mark-to-marketnet liability.First-Lien Security for Natural Gas Hedging Program and Interest Rate Swaps -Approximately 85% of the positionsin the natural gas price hedging program and all of the TCEH interest rate swaps are secured by a first-lien interest in the assetsof TCEH on a pari passu basis with the TCEH Senior Secured Facilities. Certain entities are counterparties to both our naturalgas hedge program positions and our interest rate swaps and have entered into master agreements that provide for netting andsetoff of amounts related to these positions. At December 31, 2012, our net liability positions related to these counterpartiestogether with liability positions related to entities that are counterparties to only our interest rate swaps totaled approximately $1.2billion. This amount is not expected to change materially through 2013 assuming market values do not change significantly.46 Table of ContentsPension Plan Actions -In August 2012, EFH Corp. approved certain amendments to its pension plan (see Note 13 toFinancial Statements). These actions were completed in the fourth quarter 2012, and the amendments resulted in:* splitting off assets and liabilities under the plan associated with employees of Oncor and all retirees and terminated vestedparticipants of EFH Corp. and its subsidiaries (including discontinued businesses) to a new plan sponsored andadministered by Oncor (the Oncor Plan);* splitting off assets and liabilities under the plan associated with active employees of EF1- Corp.'s competitive businesses,other than collective bargaining unit (union) employees, to a Terminating Plan, freezing benefits and vesting all accruedplan benefits for these participants;* the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities under the TerminatingPlan, and* maintaining assets and liabilities under the plan associated with union employees of EFH Corp.'s competitive businessesunder the current plan.Settlement of the Terminating Plan obligations and the full funding of the EFH Corp. competitive operations portion ofliabilities (including discontinued businesses) under the Oncor Plan resulted in an aggregate cash contribution by EFH Corp.'scompetitive operations of $259 million in the fourth quarter 2012.EFH Corp.'s competitive operations recorded charges totaling $285 million in the fourth quarter 2012, including $92 millionrelated to the settlement of the Terminating Plan and $193 million related to the competitive business obligations (includingdiscontinued businesses) that are being assumed under the Oncor Plan. These amounts represent the previously unrecognizedactuarial losses reported in accumulated other comprehensive income (loss).Impairment of Goodwill -In 2012 and 2010, we recorded $1.2 billion and $4.1 billion, respectively, noncash goodwillimpairment charges (which were not deductible for income tax purposes) related to the Competitive Electric segment. The write-offs reflected the estimated effect of lower wholesale power prices on the enterprise value of the Competitive Electric segment,driven by the sustained decline in forward natural gas prices as discussed above. Recorded goodwill related to the CompetitiveElectric segment totaled $4.95 billion at December 31, 2012.The noncash impairment charge did not cause EFH Corp. or its subsidiaries to be in default under any of their respectivedebt covenants or impact counterparty trading agreements or have a material impact on liquidity.See Note 3 to Financial Statements and "Application ofCritical Accounting Policies" below for more information on goodwillimpairment testing and charges.47 Table of ContentsLiability Management Program -At December 31, 2012, EFH Corp. and its consolidated subsidiaries had $38 billionprincipal amount of long-term debt outstanding. In October 2009, we implemented a liability management program designed toreduce debt, capture debt discount and extend debt maturities through debt exchanges, repurchases and extensions. Activitiesunder the liability management program do not include debt issued by Oncor or its subsidiaries.Amendments to the TCEH Senior Secured Facilities completed in April 2011 and January 2013 resulted in the extension of$16.4 billion in loan maturities under the TCEH Term Loan Facilities and the TCEH Letter of Credit Facility from October 2014to October 2017 and $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October2016.Other liability management activities since October 2009 (including transactions in early 2013) include debt exchange,issuance and repurchase activities as follows:Security (except where noted, debt amounts are principal amounts)EFH Corp. 10.875% Notes due 2017EFH Corp. Toggle Notes due 2017EFH Corp. 5.55% Series P Senior Notes due 2014EFH Corp. 6.50% Series Q Senior Notes due 2024EFH Corp. 6.55% Series R Senior Notes due 2034TCEH 10.25% Notes due 2015TCEH Toggle Notes due 2016TCEH Senior Secured Facilities due 2013 and 2014EFH Corp. and EFIH 9.75% Notes due 2019EFH Corp 10% Notes due 2020EFIH 11% Notes due 2021EFIH 10% Notes due 2020EFFIH Toggle Notes due 2018TCEH 15% Notes due 2021TCEH 11.5% Notes due 2020 (b)Cash paid, including use of proceeds from debt issuances in 2010 (c)TotalDebt Debt Issued/Acquired (a) Cash Paid$ 1,967 $3,126 539105494591,8757511,623252 2561,058 561-- 406-3,482-1,392-1,221-1,604-1,06212,570 $ 10,037(a) Includes an aggregate $2.228 billion principal amount of these securities held by EFH Corp. and EFIH, including $564million of EFH Corp. debt held by EFH Corp. All other debt acquired has been canceled.(b) Excludes from the $1.750 billion principal amount $12 million in debt discount and $134 million in proceeds used fortransaction costs related to the issuance of these notes and the amendment and extension of the TCEH Senior SecuredFacilities. All other proceeds were used to repay borrowings under the TCEH Senior Secured Facilities, and the remainingtransaction costs were funded with cash on hand.(c) Includes $100 million of the proceeds from the January 2010 issuance of $500 million principal amount of EFH Corp. 10%Notes due 2020 and $290 million of the proceeds from the October 2010 issuance of $350 million principal amount of TCEH15% Senior Secured Second Lien Notes due 2021. The total $390 million of proceeds was used to repurchase debt.In 2012, EFIH issued $2.253 billion principal amount of debt, the proceeds from which funded $1.630 billion in dividendsto EFH Corp., with the remaining proceeds held as cash on hand. EFH Corp. used a portion of the dividends and cash on handto repay the balance of the TCEH Demand Notes in January 2013. In 2012 and early 2013, EFIH issued $2.695 billion principalamount of debt in exchange for $3.027 billion principal amount of EFH Corp. debt and $139 million principal amount of EFIHdebt. See Note 8 to Financial Statements for discussion ofthese and other debt-related transactions. Since inception, the transactionsin the liability management program have resulted in the capture of $2.5 billion of debt discount and the extension of approximately$25.7 billion of debt maturities to 2017-2021.48 Table of ContentsEFH Corp. and its subsidiaries (other than Oncor Holdings and its subsidiaries) continue to consider and evaluate possibletransactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and mayfrom time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives. Thesetransactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to and extensionsof debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debt of EFCH and TCEHinto equity of EFH Corp., EFCH, TCEH and/or any of their subsidiaries.In evaluating whether to undertake any liability management transaction, we will take into account liquidity requirements,prospects for future access to capital, contractual restrictions, tax consequences, the market price and maturity dates of ouroutstanding debt, potential transaction costs and other factors. Any liability management transaction, including any refinancingor extension, may occur on a stand-alone basis or in connection with, or immediately following, other liability managementtransactions.Also see "Key Risks and Challenges -Substantial Leverage, Uncertain Financial Markets and Liquidity Risk" and Notes 1and 8 to Financial Statements.Global Climate Change and Other EnvironmentalMatters-- See Items 1 and 2 "Business and Properties -EnvironmentalRegulations and Related Considerations" for discussion of global climate change, recent and anticipated EPA actions and variousother environmental matters and their effects on the company.Wholesale Market Design -Nodal Market -In accordance with a rule adopted by the PUCT in 2003, ERCOT developeda new wholesale market, using a stakeholder process, designed to assign congestion costs to the market participants causing thecongestion. The nodal market design was implemented December 1, 2010. Under this new market design, ERCOT:" establishes nodes, which are metered locations across the ERCOT grid, for purposes ofmore granular price determination;" operates a voluntary "day-ahead electricity market" for forward sales and purchases of electricity and other relatedtransactions, in addition to the existing "real-time market" that primarily functions to balance power consumption andgeneration;* establishes hub trading prices, which represent the average of certain node prices within four major geographic regions,at which participants can hedge or trade power under bilateral contracts;" establishes pricing for load-serving entities based on weighted-average node prices within new geographical load zones,and" provides congestion revenue rights, which are instruments auctioned by ERCOT that allow market participants to hedgeprice differences between settlement points.ERCOT previously had a zonal wholesale market structure consisting of four geographic zones. The new location-basedcongestion-management market is referred to as a "nodal" market because wholesale pricing differs across the various nodes onthe transmission grid instead of across the geographic zones. There are over 550 nodes in the ERCOT market. The nodal marketdesign was implemented in conjunction with transmission improvements designed to reduce current congestion. We are certifiedto participate in both the "day-ahead" and "real-time markets." Additionally, all of our operational generation assets and ourqualified scheduling entities are certified and operate in the nodal market. Since the opening of the nodal market, the amount ofletters of credit posted with ERCOT to support our market participation has fluctuated between $110 million and $420 millionbased upon weekly settlement activity, and at December 31, 2012, totaled $190 million.As discussed above, the nodal market design includes the establishment of a "day-ahead market" and hub trading prices tofacilitate hedging and trading of electricity by participants. Under the previous zonal market, volumes under our nontradingbilateral purchase and sales contracts, including contracts intended as hedges, were scheduled as physical power with ERCOTand, therefore, reported gross as wholesale revenues or purchased power costs. In conjunction with the transition to the nodalmarket, unless the volumes represent physical deliveries to retail and wholesale customers or purchases from counterparties, thesecontracts are reported on a net basis in the income statement in net gain from commodity hedging and trading activities. As aresult of these changes, reported wholesale revenues and purchased power costs (and the associated volumes) in 2012 and 2011were materially less than amounts reported in prior periods.49 Table of Contents.Recent PUCT/ERCOTActions -In response to ERCOT's publication of reports (known as the Capacity, Demand, andReserves report and the Seasonal Assessment of Resource Adequacy report) showing declining reserve margins in the ERCOTmarket, the PUCT and the ERCOT Board of Directors took action to implement or approve in 2012 several changes to ERCOTprotocols designed to establish minimum offer floors for wholesale power offers during deployment of certain reliability-relatedservices, including non-spinning reserve, responsive reserve, reliability unit commitment, and other services. In addition, in Juneand October 2012 the PUCT approved rules that, among other things, increased the system-wide offer cap that applies to wholesalepower offers in ERCOT from its previous level of $3,000 per MWh to $4,500 per MWh effective August 1, 2012, and increasedthe cap to $5,000, $7,000, and $9,000 per MWh in the summers of 2013, 2014, and 2015, respectively, for the stated purpose ofsending appropriate price signals to encourage development of generation resources in ERCOT. Also in June 2012, the BrattleGroup, an independent consultant engaged by ERCOT to assess the incentives for generation investment in the ERCOT market,issued a report on potential next steps for addressing generation resource adequacy. The Brattle report discusses a range of potentialsolutions that could promote resource adequacy in the ERCOT market, ranging from enhancing the current energy-only structurein the ERCOT market to creating a capacity market structure, whereby generators receive capacity payments to ensure availablegeneration in the market and provide a return on the generator's investment, similar to those used in certain other competitivemarkets in the US. The Brattle report concluded that, even if the wholesale energy offer cap were increased to $9,000 per MWh,the expected corresponding reserve margin that would be obtained in the current energy-only market design would be approximately10%. ERCOT's current target reserve margin is 13.75%. Discussions are ongoing among ERCOT, the PUCT, market participantsand other stakeholders regarding the range of solutions presented in the Brattle report and the actions necessary to continueproviding reliable electricity supply in ERCOT.SeasonalSuspension of Certain Generation Operations-- In October 2012, ERCOT approved our filing of notice of intentto suspend operations at two of the three generation units at our Monticello generation facility due to low wholesale power pricesand other market conditions. Beginning December 1, 2012, we suspended operations for approximately six months, with bothunits expected to return to service during the peak demand months in the summer of 2013. Our mines that support the Monticellogeneration facility will continue year round operations. Based on cash flow projections and related analysis, no asset impairmentwas recorded as a result of the suspension. At current wholesale market prices of electricity, we do not expect the suspension ofoperations to significantly impact our results of operations, liquidity or financial condition.Natural Gas-Fueled Generation Development -In December 2012, Luminant filed a permit application with the TCEQto build two natural gas combustion turbines totaling 420 MW at its existing DeCordova generation facility. While current marketconditions do not provide adequate economic returns for the development or construction of new generation, we believe additionalgeneration resources will be needed to support continued electricity demand growth and reliability in the ERCOT market. See"Recent PUCT/ERCOT Actions" above for discussion of actions by the PUCT and ERCOT to encourage development of newgeneration resources.Settlement ofMake-Whole Agreements with Oncor- See Note 15 to Financial Statements for discussion of the settlementin the third quarter 2012 of our interest and tax-related reimbursement agreements with Oncor associated with Oncor's bankruptcy-remote financing subsidiary's securitization bonds.Oncor TechnologyInitiatives- Oncor continues to invest in technology initiatives that include development ofa modernizedgrid through the replacement of existing meters with advanced digital metering equipment and development of advanced digitalcommunication, data management, real-time monitoring and outage detection capabilities. This modernized grid is producingelectricity service reliability improvements and providing for additional products and services from REPs that enable businessesand consumers to better manage their electricity usage and costs.Oncor completed the deployment of advanced meters to all residential and most non-residential retail electricity customersin its service area in 2012. The advanced meters can be read remotely, rather than by a meter reader physically visiting the locationof each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amountof electricity they are consuming and adjust their electricity consumption habits. Oncor reports 15-minute interval, billing-qualityelectricity consumption data from the meters to ERCOT for market settlement purposes. The data makes it possible for REPs tosupport new programs and pricing options.At December 31, 2012, Oncor had installed 3,263,000 advanced digital meters, including 961,000 in 2012, completing itsplanned deployment of advanced meters to all residential and most nonresidential retail electricity consumers in its service area.Cumulative capital expenditures for the deployment of the advanced meter system totaled $660 million through December 31,2012, including $142 million invested in 2012.50 Table of ContentsSunset Review -Sunset review is the regular assessment of the continuing need for a state agency to exist, and is groundedin the premise that an agency will be abolished unless legislation is passed to continue its functions. On a specified time schedule,the Texas Sunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agencyto the Texas Legislature, which action may include modifying or even abolishing the agency. The PUCT and the RRC are subjectto review by the Sunset Commission in 2013. In 2011, the Texas Legislature extended the authority of the RRC and the PUCTuntil 2013. In 2013, the RRC will undergo a full sunset review, and the PUCT will undergo a limited sunset review. We cannotpredict the outcome of the sunset review process.Oncor Matters with the PUCT -Competitive Renewable Energy Zones (CREZs) -In 2009, the PUCT awarded OncorCREZ construction projects (PUCT Docket Nos. 35665 and 37902) requiring 14 related Certificate of Convenience and Necessity(CCN) amendment proceedings before the PUCT for 17 projects. All 17 projects and 14 CCN amendments have been approvedby the PUCT. The projects involve the construction of transmission lines and stations to support the transmission of electricityfrom renewable energy sources, principally wind generation facilities, in the western part of Texas to population centers in theeastern part of Texas. In addition to these projects, ERCOT completed a study in December 2010 that will result in Oncor andother transmission service providers building additional facilities to provide further voltage support to the transmission grid as aresult of CREZ. Oncor currently estimates, based on these additional voltage support facilities and the approved routes and stationsfor its awarded CREZ projects, that CREZ construction costs will total approximately $2.0 billion. CREZ-related costs couldchange based on finalization of costs for the additional voltage support facilities and final detailed designs of subsequent projectroutes. At December 31, 2012, Oncor's cumulative CREZ-related capital expenditures totaled $1.460 billion, including $561million in 2012. Oncor expects that all necessary permitting actions and other requirements and all line and station constructionactivities for Oncor's CREZ construction projects will be completed by the end of 2013. Additional voltage support projects areexpected to be completed by early 2014, with the exception of one series capacitor project that is scheduled to be completed inDecember 2015.2011 Rate Review Filing (PUCT Docket No. 38929) -In January 2011, Oncor filed for a rate review with the PUCT and203 original jurisdiction cities based on a test year ended June 30, 2010. Oncor filed a stipulation in May 2011 that incorporateda Memorandum of Settlement with the parties to the review along with other documentation (stipulation) for the purpose ofobtaining final approval of the settlement. The terms of the stipulation include an approximate $137 million base rate increaseand additional provisions to address franchise fees (discussed below) and other expenses. The stipulation resulted in an impactof less than 1% on an average retail residential monthly bill of 1,300 kWh. Approximately $93 million of the increase becameeffective in July 2011, and the remainder became effective January 1, 2012. Under the stipulation, amortization of Oncor'sregulatory assets increased by approximately $24 million ($14 million of which will be recognized as income tax expense) annuallybeginning January 1, 2012. The stipulation did not change Oncor's authorized regulatory capital structure of 60% debt and 40%equity or its authorized return on equity of 10.25%. In August 2011, the PUCT issued a final order approving the rate reviewsettlement terms contained in a "modified" stipulation, which removed a payment to certain cities of franchise fees as discussedimmediately below.In response to concerns raised by PUCT Commissioners at a July 2011 PUCT open meeting regarding the stipulation, Oncorfiled a modified stipulation that removed from the stipulation a one-time payment to certain cities served by Oncor for retrospectivefranchise fees. Instead, pursuant to the terms of a separate agreement with certain cities served by Oncor, Oncor paid $22 millionin retrospective franchise fees to cities that accepted the terms of the separate agreement. The payments are subject to refund fromthe cities or recovery from customers after final resolution of proceedings related to the appeals from Oncor's June 2008 ratereview filing discussed below. No other significant terms of the stipulation were revised.Appeals of 2008 Rate Review Filing -In November 2009, Oncor and four other parties appealed to a state district courtvarious portions of the PUCT's final order in Oncor's 2008 rate review filing. In January 2011, the district court reversed thePUCT with respect to two issues: the PUCT's disallowance of certain franchise fees and the PUCT's decision that PURA no longerrequires imposition of a rate discount for state colleges and universities. Oncor filed an appeal with the Texas Third Court ofAppeals (Austin Court of Appeals) in February 2011 with respect to the issues it appealed to the district court and did not prevailupon, as well as the district court's decision to reverse the PUCT with respect to discounts for state colleges and universities. Allbriefing in the appeal has been completed. Oral argument before the Austin Court of Appeals was completed in April 2012. Oncoris unable to predict the final outcome of the litigation.51 Table of ContentsTransmission Cost Recovery and Rates (PUCTDocket Nos. 41002, 40451, 39940, 39456, 41166, 40603, 40142 and39644)-In order to reflect increases or decreases in its wholesale transmission costs, including fees paid to other transmission serviceproviders, Oncor is allowed to file an update to the transmission cost recovery factor (TCRF) component of its retail delivery ratescharged to REPs twice a year. In November 2012, Oncor filed an application to update the TCRF, which has been approved bythe PUCT and will become effective March 1, 2013. This application was designed to reduce Oncor's billings for the period fromMarch 2013 through August 2013 by $47 million. In June 2012, Oncor filed an application to update the TCRF, which becameeffective in September 2012. This application was designed to increase Oncor's billings for the period from September 2012through February 2013 by $129 million.In November 2011, Oncor filed an application to update the TCRF, which was approved by the PUCT in January 2012 andbecame effective in March 2012. This application was designed to reduce Oncor's billings for the period from March 2012 throughAugust 2012 by $41 million, reflecting over-recoveries due to hot weather in the summer of 2011. In June 2011, Oncor filed anapplication to update the TCRF, which became effective in September 2011. This application was designed to increase Oncor'sbillings for the period from September 2011 through February 2012 by $24 million.In order to reflect changes in its invested transmission capital, PUCT rules allow Oncor to update its transmission cost ofservice (TCOS) rates by filing up to two interim TCOS rate adjustments per year. The TCOS rate is charged directly to third-party wholesale transmission providers benefiting from Oncor's transmission system and through the TCRF component of Oncor'sdelivery rates to REPs with retail customers in Oncor's service territory. In January 2013, Oncor filed an application for an interimupdate of its TCOS rate. Oncor expects PUCT approval and implementation of the new rate by March 2013. The update isexpected to increase Oncor's annualized revenues by approximately $27 million with approximately $17 million of this increaserecoverable through transmission costs charged to wholesale customers and $10 million recoverable from REPs through the TCRFcomponent of Oncor's delivery rates.In July 2012, Oncor filed an application for an interim update of its TCOS rate. The new rate was approved by the PUCTand became effective in August 2012. Oncor's annualized revenues increased by an estimated $30 million with approximately$19 million of this increase recoverable through transmission costs charged to wholesale customers and $11 million recoverablefrom REPs through the TCRF component of Oncor's delivery rates. In January 2012, Oncor filed an application for an interimupdate of its TCOS rate. The new rate was approved by the PUCT and became effective in March 2012. Oncor's annualizedrevenues increased by an estimated $2 million with approximately 65% of this increase recoverable through transmission costscharged to wholesale customers and the remaining 35% recoverable from REPs through the TCRF component of Oncor's deliveryrates.In August 2011, Oncor filed an application for an interim update of its wholesale transmission rate, and the PUCT approvedthe new rate effective October 27, 2011. Oncor's annualized revenues increased by an estimated $35 million with $22 million ofthis increase recoverable through transmission rates charged to wholesale customers and the remaining $13 million recoverablefrom REPs through the TCRF component of Oncor's delivery rates.Application for 2013 Energy Efficiency Cost Recovery Factor (PUCT Docket No. 40361) -PUCT rules require Oncor tomake an annual EECRF filing by the first business day in May for implementation at the beginning of the next calendar year. InMay 2012, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF)for 2013. The requested 2013 EECRF was $73 million as compared to $54 million established for 2012 and $51 million for 2011,and would result in a monthly charge for residential customers of $1.23 as compared to the 2012 residential charge of $0.99 permonth effective December 31,2012. In August 2012, the PUCT issued a final order approving the 2013 EECRF, which is designedto recover $62 million of Oncor's costs for the 2013 program year, a $9 million performance bonus based on Oncor's 2011 resultsand a $2 million increase for under-recovery of 2011 costs.Summary -We cannot predict future regulatory or legislative actions or any changes in economic and securities marketconditions. Such actions or changes could significantly affect our results of operations, liquidity or financial condition.52 Table of ContentsKEY RISKS AND CHALLENGESFollowing is a discussion of key risks and challenges facing management and the initiatives currently underway to managesuch challenges. These matters involve risks that could have a material effect on our results of operations, liquidity or financialcondition. Also see Item IA, "Risk Factors."Substantial Leverage, Uncertain Financial Markets and Liquidity RiskOur substantial leverage, resulting in large part from debt incurred to finance the Merger, and the covenants contained in ourdebt agreements require significant cash flows to be dedicated to interest and principal payments and could adversely affect ourability to raise additional capital to fund operations and limit our ability to react to changes in the economy, our industry (includingenvironmental regulations) or our business. Principal amounts of short-term borrowings and long-term debt, including amountsdue currently, totaled $40.1 billion at December 31, 2012, and cash interest payments in 2012 totaled $3.2 billion.Significant amounts of our long-term debt mature in the next few years, including approximate principal amounts of $90million in 2013, $4.0 billion in 2014 and $3.3 billion in 2015. A substantial amount of our debt is comprised of debt incurredunder the TCEH Senior Secured Facilities. In April 2011, we secured an extension of the maturity date of approximately $16.4billion principal amount of debt under these facilities to 2017, and in April 2011 and January 2013, we secured the extension ofthe entire $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016.Notwithstanding the extension, the maturity could be reset to an earlier date under a "springing maturity" provision if, as of adefined date, certain amounts of TCEH unsecured debt maturing prior to 2017 are not refinanced and TCEH's debt to AdjustedEBITDA ratio exceeds 6.00 to 1.00. In addition, the agreement covering the TCEH Senior Secured Facilities includes a secureddebt to Adjusted EBITDA financial maintenance covenant and a covenant requiring TCEH to timely deliver to the lenders auditedannual financial statements that are not qualified as to the status of TCEH and its consolidated subsidiaries as a going concern(see "Financial Condition -Liquidity and Capital Resources -Financial Covenants, Credit Rating Provisions and Cross DefaultProvisions" and Notes I and 8 to Financial Statements).In consideration of our substantial leverage, there can be no assurance that counterparties to our credit facility and hedgingarrangements will perform as expected and meet their obligations to us. Failure of such counterparties to meet their obligationsor substantial changes in financial markets, the economy, regulatory requirements, our industry or our operations could result inconstraints in our liquidity. While traditional counterparties with physical assets to hedge, as well as financial institutions andother parties, continue to participate in the markets, low natural gas and wholesale electricity prices, continued market and regulatoryuncertainty and our liquidity and upcoming debt maturities have limited our hedging and trading activities, particularly for longer-dated transactions, which could impact our ability to hedge our commodity price and interest rate exposure to desired levels atreasonable costs. See discussion ofcredit risk in Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," discussionof available liquidity and liquidity effects of the natural gas price hedging program in "Financial Condition -Liquidity and CapitalResources" and discussion of potential impacts of legislative rulemakings on the OTC derivatives market below in "FinancialServices Reform Legislation."In addition, because our operations are capital intensive, we expect to rely over the long-term upon access to financial marketsas a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our availablecredit facilities. Our ability to economically access the capital or credit markets could be restricted at a time when we would like,or need, to access those markets. Lack of such access could have an impact on our flexibility to react to changing economic andbusiness conditions.Further, a continuation, or further decline, of current forward natural gas prices could result in further declines in the valuesof TCEH's nuclear and lignite/coal-fueled generation assets and limit or hinder TCEH's ability to hedge its wholesale electricityrevenues at sufficient price levels to support its significant interest payments and debt maturities, which could adversely impactTCEH's ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt. See discussionabove under "Significant Activities and Events and Items Influencing Future Performance -Natural Gas Price Hedging Programand Other Hedging Activities."53 Table of ContentsAt December 31, 2012, TCEH had $1.2 billion of cash and cash equivalents and $183 million of available capacity underits letter of credit facility. In January 2013, TCEH's liquidity increased by approximately $700 million as a result of the settlementof the TCEH Demand Notes by EFH Corp. Based on the current forecast of cash from operating activities, which reflects currentforward market electricity prices, projected capital expenditures and other cash flows, we expect that TCEH will have sufficientliquidity to meets its obligations until October2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures.TCEH's ability to satisfy this obligation is dependent upon the implementation of one or more of the actions described immediatelybelow.EFH Corp. and its subsidiaries (other than Oncor Holdings and its subsidiaries) continue to consider and evaluate possibletransactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and mayfrom time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives.Progress to date includes the debt extensions, exchanges, issuances and repurchases completed in 2009 through early 2013, whichresulted in the capture of $2.5 billion of debt discount and the extension of approximately $25.7 billion of debt maturities to2017-2021. Future transactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendmentsto and extensions of debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debtof EFCH and TCEH into equity of EFH Corp., EFCH, TCEH and/or any of their subsidiaries. These actions could result in holdersof TCEH debt instruments not recovering the full principal amount of those obligations. We have also hedged a substantial portionof variable rate debt exposure through 2017 using interest rate swaps. See "Significant Activities and Events and Items InfluencingFuture Performance -Liability Management Program" and Note 8 to Financial Statements.Natural Gas Price and Market Heat Rate ExposureWholesale electricity prices in the ERCOT market have historically moved with the price of natural gas because marginaldemand for electricity supply is generally met with natural gas-fueled generation facilities. The price of natural gas has fluctuateddue to changes in industrial demand, supply availability and other economic and market factors, and such prices have historicallybeen volatile. As shown in the table below, forward natural gas prices have generally trended downward in recent years, reflectingdiscovery and increased drilling of shale gas deposits combined with lingering demand weakness associated with the economicdownturn.Forward Market Prices for Calendar Year ($/MMBtu) (a)Date 2013 2014 2015 2016December 31, 2008 $ 7.15 $ 7.15 $ 7.21 $ 7.30March 31, 2009 $ 7.11 $ 7.18 $ 7.25 $ 7.33June 30, 2009 $ 7.30 $ 7.43 $ 7.57 $ 7.71September 30, 2009 $ 7.06 $ 7.17 $ 7.31 $ 7.43December 31,2009 $ 6.67 $ 6.84 $ 7.05 $ 7.24March 31, 2010 $ 6.07 $ 6.36 $ 6.68 $ 7.00June 30, 2010 $ 5.89 $ 6.10 $ 6.37 $ 6.68September 30, 2010 $ 5.29 $ 5.42 $ 5.60 $ 5.76December 31, 2010 $ 5.33 $ 5.49 $ 5.64 $ 5.79March 31, 2011 $ 5.41 $ 5.73 $ 6.08 $ 6.41June 30, 2011 $ 5.16 $ 5.42 $ 5.70 $ 5.98September 30, 2011 $ 4.80 $ 5.13 $ 5.39 $ 5.61December 31, 2011 $ 3.94 $ 4.34 $ 4.60 $ 4.85March 31, 2012 $ 3.47 $ 3.96 $ 4.26 $ 4.51June 30, 2012 $ 3.58 $ 3.95 $ 4.13 $ 4.29September 30, 2012 $ 3.84 $ 4.18 $ 4.37 $ 4.55December 31, 2012 $ 3.54 $ 4.03 $ 4.23 $ 4.42(a) Based on NYMEX Henry Hub prices.In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the costof generating electricity from our nuclear and lignite/coal-fueled facilities. All other factors being equal, these nuclear and lignite/coal-fueled generation assets, which provided the substantial majority of supply volumes in 2012, increase or decrease in valueas natural gas prices and market heat rates rise or fall, respectively, because of the effect on wholesale electricity prices in ERCOT,54 Table of ContentsThe wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Marketheat rate movements also affect wholesale electricity prices. Market heat rate can be affected by a number of factors includinggeneration resource availability and the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) ingenerating electricity. While market heat rates have generally increased as natural gas prices have declined, wholesale electricityprices have declined due to the greater effect of falling natural gas prices.Our market heat rate exposure is impacted by changes in the availability, such as additions and retirements of generationfacilities, and mix of generation assets in ERCOT. For example, increased wind generation capacity could result in lower marketheat rates. We expect that decreases in market heat rates would decrease the value of our generation assets because lower marketheat rates generally result in lower wholesale electricity prices, and vice versa.With the exposure to variability of natural gas prices and market heat rates in ERCOT, retail sales price management andhedging activities are critical to the profitability of the business and maintaining consistent cash flow levels.Our approach to managing electricity price risk focuses on the following:" employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts intended to partially hedge gross margins;" continuing focus on cost management to better withstand gross margin volatility;" following a retail pricing strategy that appropriately reflects the magnitude and costs of commodity price, liquidity riskand retail load variability, and* improving retail customer service to attract and retain high-value customers.As discussed above in "Significant Activities and Events and Items Influencing Future Performance," we have implementeda natural gas price hedging program to mitigate the risk of lower wholesale electricity prices due to declines in natural gas prices.While current and forward natural gas prices are currently depressed, we continue to seek opportunities to manage our wholesalepower price exposure through hedging activities, including forward wholesale and retail electricity sales. At December 31, 2012,we have no significant hedges beyond 2014.We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term heat rate hedgingtransactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricitysales contracts where practical considering pricing, credit, liquidity and related factors.The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas andcertain other commodity prices and market heat rates on realized pretax earnings for the periods presented. The estimates relatedto price sensitivity are based on TCEH's unhedged position and forward prices at December 31,2012, which for natural gas reflectsestimates of electricity generation less amounts hedged through the natural gas price hedging program and amounts under existingwholesale and retail sales contracts. On a rolling basis, generally twelve-months, the substantial majority of retail sales undermonth-to-month arrangements are deemed to be under contract.Balance 2013 (a) 2014 2015$1.00/MMBtu change in natural gas price (b) $ -18 $ -270 $ -4800.1/MMBtuIMWh change in market heat rate (c) $ -5 $ -25 $ -35$1.00/gallon change in diesel fuel price $ -13 $ -45 $ -50(a) Balance of 2013 is from February 1, 2013 through December 31, 2013.(b) Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally beingon the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gasposition is assumed to be generated).(c) Based on Houston Ship Channel natural gas prices at December 31, 2012.On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based onour desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts ofoverall generation and consumption (which is also subject to volatility resulting from customer chum, weather, economic andother factors) in our businesses. Portfolio balancing may include the execution of incremental transactions, including heat ratehedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricityat fixed prices. As a result, commodity price exposures and their effect on earnings could materially change from time to time.55 Table of ContentsNew and Changing Environmental RegulationsWe are subject to various environmental laws and regulations related to S02, NOx and mercury as well as other emissionsthat impact air and water quality. We believe we are in compliance with all current laws and regulations, but regulatory authoritieshave recently adopted or proposed new rules, such as the EPA's CSAPR and MATS, which could require material capitalexpenditures if the rules take effect, and authorities continue to evaluateexisting requirements and consider proposals for furtherrules changes. If we make any major modifications to our power generation facilities, we may be required to install the bestavailable control technology or to achieve the lowest achievable emission rates as such terms are defined under the new sourcereview provisions of the Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures.(See Note 9 to Financial Statements for discussion of "Litigation Related to Generation Facilities," "Regulatory Reviews" and"Environmental Contingencies." and Items I and 2 "Business and Properties -Environmental Regulations and RelatedConsiderations.")We also continue to closely monitor any potential legislative, regulatory and judicial changes pertaining to global climatechange. In view of the fact that a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities,our results of operations, liquidity or financial condition could be materially affected by the enactment of any legislation, regulationor judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities thatproduce GHG emissions, or that establishes federal renewable energy portfolio standards. For example, federal, state or regionallegislation or regulation addressing global climate change could result in us either incurring material costs to reduce our GHGemissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program.See further discussion under Items I and 2, "Business and Properties -Environmental Regulations and Related Considerations."Competitive Retail Markets and Customer RetentionCompetitive retail activity in Texas has resulted in retail customer chum. Our total retail customer counts declined 4% in201.2, 9% in 2011 and 6% in 2010. Based upon 2012 results discussed below in "Results of Operations -Competitive ElectricSegment," a 1% decline in residential customers would result in a decline in annual revenues of approximately $29 million. Inresponding to the competitive landscape in the ERCOT marketplace, we are focusing on the following key initiatives:" Maintaining competitive pricing initiatives on residential service plans;" Profitably growing the retail customer base by actively competing for new and existing customers in areas in Texas opento competition. The customer retention strategy remains focused on continuing to implement initiatives to deliver world-class customer service and improve the overall customer experience;* Establishing TXU Energy as the most innovative retailer in the Texas market by continuing to develop tailored productofferings to meet customer needs. Over the past five years, TXU Energy has invested $100 million in retail initiativesaimed at helping consumers conserve energy and demand-side management initiatives that are intended to moderateconsumption and reduce peak demand for electricity, and* Focusing business market initiatives largely on programs targeted to retain the existing highest-value customers and torecapture customers who have switched REPs. Initiatives include maintaining and continuously refining a disciplinedcontracting and pricing approach and economic segmentation of the business market to enhance targeted sales andmarketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improvedcustomer service, aided by an enhanced customer management system, new product price/service offerings and amultichannel approach for the small business market.56 Table of ContentsFinancial Services Reform LegislationIn July 2010, the US Congress enacted financial reform legislation known as the Dodd-Frank Wall Street Reform andConsumer Protection Act (the Financial Reform Act). The primary purposes of the Financial Reform Act are, among other things:to address systemic risk in the financial system; to establish a Bureau of Consumer Financial Protection with broad powers toenforce consumer protection laws and promulgate rules against unfair, deceptive or abusive practices; to enhance regulation ofthe derivatives markets, including the requirement for central clearing of over-the-counter derivative instruments and additionalcapital and margin requirements for certain derivative market participants and to implement a number of new corporate governancerequirements for companies with listed or, in some cases, publicly-traded securities. While the legislation is broad and detailed,a few key rulemaking decisions remain to be made by federal governmental agencies to fully implement the Financial ReformAct.Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives (Swaps) market.The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we useto hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However,under the end-user clearing exemption, entities are exempt from these clearing requirements if they (i) are not "Swap Dealers" or"Major Swap Participants" and (ii) use Swaps to hedge or mitigate commercial risk. Existing swaps are grandfathered from theclearing requirements. The legislation mandates significant compliance requirements for any entity that is determined to be aSwap Dealer or Major Swap Participant and additional reporting and recordkeeping requirements for all entities that participatein the derivative markets.In May 2012, the US Commodity Futures Trading Commission (CFTC) published its final rule defining the terms SwapDealer and Major Swap Participant. Additionally, in July 2012, the CFTC approved the final rules defining the term Swap andthe end-user clearing exemption. The definition of the term Swap and the Swap Dealer/Major Swap Participant rule becameeffective in October 2012. Accordingly, we are required to assess our activity to determine if we will be required to register as aSwap Dealer or Major Swap Participant. Based on our assessment, we are not a Swap Dealer or Major Swap Participant. InOctober 2012, the CFTC issued various no-action letters granting temporary relief from enforcement from certain aspects of thedefinition of Swap and the Swap Dealer/Major Swap Participant rule.In September 2012, the District Court for the District of Columbia issued an order that vacated and remanded to the CFTCits Position Limit Rule (PLR), which would have been effective in October 2012. The PLR provided for specific position limitsrelated to 28 Core Referenced Futures Contracts, including the NYMEX Henry Hub Natural Gas Futures Contract, the NYMEXLight Sweet Crude Oil Futures Contract and the NYMEX New York Harbor No. 2 Heating Oil Futures Contract. If the PLR hadbeen approved by the court, we would have been required to comply with the portion of the PLR applicable to the contracts notedabove, which would result in increased monitoring and reporting requirements. We cannot predict when, or in what form, theCFTC will change the PLR.The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateralrequirements are unclear as to whether an end-user or its counterparty (e.g., swap dealer) is required to post cash collateral, thereis a risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. The final rulefor margin requirements has not been issued. However, the legislative history of the Financial Reform Act suggests that it wasnot Congress' intent to require end-users to post cash collateral with respect to swaps. If we were required to post cash collateralon our swap transactions with swap dealers, our liquidity would likely be materially impacted, and our ability to enter into OTCderivatives to hedge our commodity and interest rate risks would be significantly limited.We cannot predict the outcome of the final rulemakings to implement the OTC derivative market provisions of the FinancialReform Act. Based on our assessment and published guidance from the CFTC, we believe our historical practices related to ouruse of Swaps does not qualify us as a Swap Dealer or Major Swap Participant, and we believe we will be able to take advantageof the End-User Exemption for Swaps that hedge or mitigate commercial risk; however, the remaining rulemakings related to howSwap Dealers and other market participants administer margin requirements could negatively affect our ability to hedge ourcommodity and interest rate risks. Accordingly, we (and other market participants) continue to closely monitor the rulemakingsand any other potential legislative and regulatory changes and work with regulators and legislators. We have provided theminformation on our operations, the types of transactions in which we engage, our concerns regarding potential regulatory impacts,market characteristics and related matters.57 Table of ContentsExposures Related to NuclearAsset OutagesOur nuclear assets are comprised of two generation units at the Comanche Peak plant site, each with an installed nameplatecapacity of 1,150 MW. These units represent approximately 15% of our total generation capacity. The nuclear generation unitsrepresent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, theunfavorable impact to pretax earnings is estimated (based upon forward electricity market prices for 2013 at December 31, 2012)to be approximately $1.5 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilitiesinsurance in Note 9 to Financial Statements.The inherent complexities and related regulations associated with operating nuclear generation facilities result inenvironmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review andregulation by the NRC, including potential regulation as a result of the NRC's ongoing analysis and response to the effects of thenatural disaster on nuclear generation facilities in Japan in 2010, covering, among other things, operations, maintenance, emergencyplanning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increasedcapital or operating costs, and it may require extended outages, modify, suspend or revoke operating licenses and impose finesfor failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outageat another nuclear generation facility could result in the NRC taking action to shut down the Comanche Peak units as a precautionarymeasure.We participate in industry groups and with regulators to remain current on the latest developments in nuclear safety, operationand maintenance and on emerging threats and mitigating techniques. These groups include, but are not limited to, the NRC andthe Institute of Nuclear Power Operations (INPO). We also apply the knowledge gained by continuing to invest in technology,processes and services to improve our operations and detect, mitigate and protect our nuclear generation assets. The ComanchePeak plant has not experienced an extended unplanned outage, and management continues to focus on the safe, reliable and efficientoperations at the plant.Oncor's Capital Availability and CostOur investment in Oncor, which represents approximately 80% of its membership interests, is a significant value driver ofour overall business. Oncor's access to capital markets and cost of debt could be directly affected by its credit ratings. Any adverseaction with respect to Oncor's credit ratings would generally cause borrowing costs to increase and the potential pool of investorsand funding sources to decrease and could result in reduced distributions from Oncor. Oncor's credit ratings are currentlysubstantially higher than those of the Texas Holdings Group. If credit rating agencies were to change their views of Oncor'sindependence from any member of the Texas Holdings Group, Oncor's credit ratings would likely decline. We believe these risksare substantially mitigated by the significant ring-fencing measures implemented by EFH Corp. and Oncor as described in Note1 to Financial Statements.Declining Reserve Margins in ERCOTPlanning reserve margin represents the percentage by which estimated system generation capacity exceeds anticipated peakload. As reflected in the table below, ERCOT is projecting reserve margins in the ERCOT market in 2013 will be below ERCOT'sminimum reserve planning criterion of 13.75% and will continue to decline. Weather extremes, unplanned generation facilityoutages and variability in wind generation all exacerbate the risks of inadequate reserve margins.2013 2014 2015 2016Firm load forecast (MW) 65,952 67,592 69,679 71,613Resources forecast (MW) 74,633 74,943 76,974 77,703Reserve margin (a) 13.2% 10.9% 10.5% 8.5%(a) Source: ERCOT's "Report on the Capacity, Demand, and Reserves in the ERCOT Region -December 2012." Reservemargin (planning) = (Resources forecast -Firm load forecast) / Firm load forecast.58 Table of ContentsWe and the ERCOT market broadly experienced the effects of weather extremes and reduced generation availability in 2011.Severe cold weather in North Texas caused some generation units to go off-line, including certain of our generation units, resultingin electricity outages and reduced customer satisfaction, as well as loss of revenues and higher costs in our competitive businessas we worked to bring our units back on line. The unusually hot 2011 summer in Texas drove higher electricity demand thatresulted in wholesale electricity price spikes and requests to consumers to conserve energy during peak load periods, whileincreasing stress on generation and other electricity grid assets. Unplanned generation unit outages during periods of high electricitydemand, combined with inadequate reserve margins, increase the risk of spikes in wholesale power prices and could have significantadverse effects on our results of operations, liquidity and financial condition. Other weather events such as drought that oftenaccompanies hot weather extremes reduces cooling water levels at our generation facilities and can ultimately result in reducedoutput. Heavy rains present other challenges as flooding in other states can halt rail transportation of coal, and local flooding canreduce our lignite mining capabilities, resulting in fuel shortages and reduced generation.While there can be no assurance that we can fully mitigate the risks of severe weather events and unanticipated generationunit outages, we have emergency preparedness, business continuity and regulatory compliance policies and procedures that arecontinuously reviewed and updated to address these risks. Further, we have initiatives in place to improve monitoring of generationequipment maintenance and readiness to increase system reliability and help ensure generation availability. With the learningsfrom the winter and summer events of 2011, we have implemented new procedures and continuously evaluate plans to assure thehighest possible delivery of generation during critical periods, delivering demand side management responses and assuring weutilize our smart grid and advanced meter technology to implement ERCOT mandated rotating outages to noncritical customers.We continue to work with ERCOT and other market participants to develop policies and protocols that provide appropriate pricingsignals that encourage the development of new generation to meet growing demand in the ERCOT market. See "SignificantActivities and Events and Items Influencing Future Performance -Recent PUCT/ERCOT Actions."Cyber Security and Infrastructure Protection RiskAbreach ofcyber/data security measures that impairs our information technology infrastructure could disrupt normal businessoperations and affect our ability to control our generation and transmission assets, access retail customer information and limitcommunication with third parties. Any loss of confidential or proprietary data through a breach could materially affect ourreputation, expose the company to legal claims or impair our ability to execute on business strategies.We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques. Thesegroups include, but are not limited to, the US Cyber Emergency Response Team, the National Electric Sector Cyber SecurityOrganization, the NRC and NERC. We also apply the knowledge gained by continuing to invest in technology, processes andservices to detect, mitigate and protect our cyber assets. These investments include upgrades to network architecture, regularintrusion detection monitoring and compliance with emerging industry regulation.59 Table of ContentsAPPLICATION OF CRITICAL ACCOUNTING POLICIESOur significant accounting policies are discussed in Note 1 to Financial Statements. We follow accounting principlesgenerally accepted in the US. Application of these accounting policies in the preparation of our consolidated financial statementsrequires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities atthe balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain criticalaccounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported usingdifferent assumptions or estimation methodologies.Impairment of Goodwill and Other Long-Lived AssetsWe evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accountingstandards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that theircarrying amount may not be recoverable. One of those indications is a current expectation that "more likely than not" a long-livedasset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. For our nuclear andlignite/coal-fueled generation assets, another possible indication would be an expectation of continuing long-term declines innatural gas prices and/or market heat rates. We evaluate investments in unconsolidated subsidiaries for impairment when factorsindicate that a decrease in the value of the investment has occurred that is not temporary. Indications of a loss in value mightinclude a series of operating losses of the investee or a fair value of the investment that is less than its carrying amount. Thedetermination of the existence of these and other indications of impairment involves judgments that are subjective in nature andmay require the use of estimates in forecasting future results and cash flows related to an asset, group of assets or investment inunconsolidated subsidiary. Further, the unique nature of our property, plant and equipment, which includes a fleet of generationassets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use of significantjudgments in determining the existence of impairment indications and the grouping of assets for impairment testing.Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (wehave selected December 1) or whenever events or changes in circumstances indicate an impairment may exist, such as the triggersto evaluate impairments to long-lived assets discussed above. As required by accounting guidance related to goodwill and otherintangible assets, we have allocated goodwill to our reporting units, which are our two segments: Competitive Electric and RegulatedDelivery, and goodwill impairment testing is performed at the reporting unit level. (See Notes I and 2 to Financial Statementsfor discussion of the deconsolidation of Oncor Holdings at January 1, 2010, which resulted in a reduction in reported goodwillfor the amount related to the Regulated Delivery segment, and see above for discussion of impairment testing for equity-methodinvestments such as Oncor Holdings.) Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carryingvalue exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to theestimated fair values of the reporting unit's operating assets (including identifiable intangible assets) and liabilities at the assessmentdate, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recordedgoodwill amount over the implied goodwill amount is written off as an impairment charge.The determination of enterprise value involves a number of assumptions and estimates. We use a combination of fair valueinputs to estimate enterprise values of our reporting units: internal discounted cash flow analyses (income approach), andcomparable publicly traded company values (market approach). The income approach involves estimates of future performancethat reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects ofenvironmental rules, generation plant performance and retail sales volume trends, as well as determination of a terminal valueusing the Gordon Growth Model. Another key variable in the income approach is the discount rate, or weighted average cost ofcapital, applied to the forecasted cash flows. The determination of the discount rate takes into consideration the capital structure,debt ratings and current debt yields of comparable public companies as well as an estimate of return on equity that reflects historicalmarket returns and current market volatility for the industry. Enterprise value estimates based on comparable company valuesinvolve using trading multiples of EBITDA of those selected public companies to derive appropriate multiples to apply to theEBITDA of the reporting units. This approach requires an estimate, using historical acquisition data, of an appropriate controlpremium to apply to the reporting unit values calculated from such multiples. Critical judgments include the selection of comparablecompanies and the weighting of the value metrics in developing the best estimate of enterprise value.60 Table of ContentsSince the Merger, we have recorded goodwill impairment charges totaling $13.390 billion, including $1.2 billion recordedin 2012, $4.1 billion recorded in 2010 and $8.090 billion (excluding $860 million related to the Regulated Delivery segment)recorded largely in 2008. The total impairment charges represent approximately 75% of the goodwill balance resulting frompurchase accounting for the Merger. The impairments in 2012 and 2010 reflected the estimated effect of lower wholesale powerprices in ERCOT on the enterprise value of the Competitive Electric segment, driven by the sustained decline in forward naturalgas prices. The impairment in 2008 primarily arose from the dislocation in the capital markets that increased interest rate spreadsand the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securitiesof comparable companies in the second half of 2008.See Note 3 to Financial Statements for additional discussion.Derivative Instruments and Mark-to-Market AccountingWe enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivativeinstruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Underaccounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-marketaccounting, and the determination of market values for these instruments is based on numerous assumptions and estimationtechniques.Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements asmarket prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net incomewith an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on thetype of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value forderivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery pointand commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. Forilliquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into accountavailable market information and other inputs that might not be readily observable in the market. We estimate fair value asdescribed in Note I I to Financial Statements and discussed under "Fair Value Measurements" below.Accounting standards related to derivative instruments and hedging activities allow for "normal" purchase or sale electionsand hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in netincome and thus reduce the volatility of net income that can result from fluctuations in fair values. "Normal" purchases and salesare contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normalcourse of business and are not subject to mark-to-market accounting if the election as normal is made. Hedge accountingdesignations are made with the intent to match the accounting recognition of the contract's financial performance to that of thetransaction the contract is intended to hedge.Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in othercomprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, itmirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectivenessof the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in othercomprehensive income are reclassified to net income in the period that the hedged transactions are recognized in net income.Although at December 31, 2012, we do not have any derivatives designated as cash flow or fair value hedges, we continuallyassess potential hedge elections and could designate positions as cash flow hedges in the future. In March 2007, the instrumentsmaking up a significant portion of the natural gas price hedging program that were previously designated as cash flow hedgeswere dedesignated as allowed under accounting standards related to derivative instruments and hedging activities, and subsequentchanges in their fair value have been marked-to-market in net income. In addition, in August 2008, interest rate swap transactionsin effect at that time were dedesignated as cash flow hedges in accordance with accounting standards, and subsequent changes intheir fair value have been marked-to-market in net income. See further discussion of the natural gas price hedging program andinterest rate swap transactions under "Significant Activities and Events and Items Influencing Future Performance."61 Table of ContentsThe following tables provide the effects on both the statements of consolidated income (loss) and comprehensive income(loss) of accounting for those derivative instruments (both commodity-related and interest rate swaps) that we have determinedto be subject to fair value measurement under accounting standards related to derivative instruments.Amounts recognized in net income (loss) (after-tax):Unrealized net gains on positions marked-to-market in net incomeUnrealized net losses representing reversals of previously recognized fair values ofpositions settled in the periodUnrealized gain on termination of a long-term power sales contractReclassifications of net losses on cash flow hedge positions from othercomprehensive incomeTotal net gain (loss) recognizedAmounts recognized in other comprehensive income (loss) (after-tax):Reclassifications of net losses on cash flow hedge positions to net incomeYear Ended December 31,2012 2011 2010$ 292 $ 205 $ 1,257(1,162)(696)(606)75(7) (19) (59)$ (877) $ (510) $ 667$ 7 $ 19 $ 59The effect of mark-to-market and hedge accounting for derivatives on the balance sheet is as follows:December 31,Commodity contract assets $Commodity contract liabilities $Interest rate swap assets $Interest rate swap liabilities $Net accumulated other comprehensive loss included in shareholders' equity (amounts after tax) $2012 20112,047 $ 4,435(383) $ (1,245)134 $ 142(2,217) $(43) $(2,397)(50)We report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements wehave with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the balancesheet. See Note 12 to Financial Statements.Fair Value MeasurementsWe determine value under the fair value hierarchy established in accounting standards. We utilize several valuation techniquesto measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other marketinformation for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. Thesetechniques include, but are not limited to, the use of broker quotes and statistical relationships between different price curves andare intended to maximize the use of observable inputs and minimize the use of unobservable inputs. In applying the marketapproach, we use a mid-market valuation convention (the mid-point between bid and ask prices) as a practical expedient.Under the fair value hierarchy, Level I and Level 2 valuations generally apply to our commodity-related contracts for naturalgas, electricity and fuel, including coal and uranium, derivative instruments entered into for hedging purposes, securities associatedwith the nuclear decommissioning trust, and interest rate swaps intended to fix and/or lower interest payments on long-term debt.Level I valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date.Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information ofsimilar securities, adjusted for observable differences. Level 2 inputs include:" quoted prices for similar assets or liabilities in active markets;" quoted prices for identical or similar assets or liabilities in markets that are not active;* inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curvesobservable at commonly quoted intervals, and* inputs that are derived principally from or corroborated by observable market data by correlation or other means.62 Table of ContentsExamples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assetsor liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example,certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets;however, an active market might exist for such derivatives for a different time period at the same location. We utilize correlationtechniques to compare prices for inputs at both time periods to provide a basis to value those derivatives that do not have activemarkets. (See Note 11 to Financial Statements for additional discussion of how broker quotes are utilized.)Our Level 3 valuations generally apply to congestion revenue rights, certain coal contracts, options to purchase or sellelectricity, and electricity purchase and sales agreements for which the valuations include unobservable inputs, including the hourlyshaping of the price curve. Level 3 valuations use largely unobservable inputs, with little or no supporting market activity, andassets and liabilities are classified as Level 3 if such inputs are significant to the fair value determination. We use the mostmeaningful information available from the market, combined with our own internally developed valuation methodologies, todevelop our best estimate of fair value. The determination of fair value for Level 3 assets and liabilities requires significantmanagement judgment and estimation.Valuations of Level 3 assets and liabilities are sensitive to the assumptions used for the significant inputs. Where marketdata is available, the inputs used for valuation reflect that information as of our valuation date. In periods of extreme volatility,lessened liquidity or in illiquid markets, there may be more variability in market pricing or a lack of market data to use in thevaluation process. An illiquid market is one in which little or no observable activity has occurred or one that lacks willing buyers.Valuation risk is mitigated through the performance of stress testing of the significant inputs to understand the impact that varyingassumptions may have on the valuation and other review processes performed to ensure appropriate valuation.As part of our valuation of assets subject to fair value accounting, counterparty credit risk is taken into consideration bymeasuring the extent of netting arrangements in place with the counterparty along with credit enhancements and the estimatedcredit rating of the counterparty. Our valuation of liabilities subject to fair value accounting takes into consideration the market'sview of our credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancementsposted by us. We consider the credit risk adjustment to be a Level 3 input since judgment is used to assign credit ratings, recoveryrate factors and default rate factors.Level 3 assets totaled $83 million and $124 million at December 31, 2012 and 2011, respectively, and representedapproximately 3% and 2%, respectively, of the assets measured at fair value, or less than 1% of total assets in both years. Level3 liabilities totaled $54 million and $71 million at December 31, 2012 and 2011, respectively, and represented approximately 2%of the liabilities measured at fair value, or less than 1% of total liabilities in both years.Valuations of several of our Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing modelinputs such as volatility factors and credit risk adjustments. At December 31, 2012 and 2011, a 10% change in electricity price(per MWh) assumptions across unobservable inputs would cause an approximate $8 million and $5 million change, respectively,in net Level 3 assets. A 10% change in coal price assumptions across unobservable inputs would cause an approximate $8 millionand $21 million change, respectively, in net Level 3 assets. See Note II to Financial Statements for additional information aboutfair value measurements, including information on unobservable inputs and related valuation sensitivities and a table presentingthe changes in Level 3 assets and liabilities for the years ended December 31, 2012, 2011 and 2010.Variable Interest EntitiesA variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level ofcontrol over the entity or results in economic risks to us. Determining whether or not to consolidate a VIE requires interpretationof accounting rules and their application to existing business relationships and underlying agreements. Amended accounting rulesrelated to VIEs became effective January 1,2010 and resulted in the deconsolidation ofOncor Holdings, which holds an approximate80% interest in Oncor. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure,decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related partyrelationships among the interest holders of the VIE and the rights granted to the interest holders of the VIE to determine whetherwe have the right or obligation to absorb profit and loss from the VIE and the power to direct the significant activities of the VIE.See Note 2 to Financial Statements for our analysis of the Oncor relationship and information regarding our consolidated variableinterest entities.63 Table of ContentsRevenue RecognitionOur revenue includes an estimate for unbilled revenue that represents estimated daily kWh consumption after the meter readdate to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using meteredconsumption as well as historical kWh usage information adjusted for weather and other measurable factors affecting consumption.Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because ofseasonal changes in demand. Accrued unbilled revenues totaled $260 million, $269 million and $297 million at December 31,2012, 2011 and 2010, respectively.Accounting for ContingenciesOur financial results may be affected by judgments and estimates related to loss contingencies. A significant contingencythat we account for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expenseis based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices,regulatory rulings, general economic conditions, effects of hurricanes and other natural disasters and customers' behaviors. Changesin customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of theestimation process. Historical results alone are not always indicative of future results, causing management to consider potentialchanges in customer behavior and make judgments about the collectability of accounts receivable. Bad debt expense, the substantialmajority ofwhich relates to our competitive retail operations, totaled $26 million, $56 million and $108 million for the years endedDecember 31, 2012, 2011 and 2010, respectively.Litigation contingencies also may require significant judgment in estimating amounts to accrue. We accrue liabilities forlitigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable. Nosignificant amounts have been accrued for such contingencies during the three-year period ended December 31, 2012. See Note9 to Financial Statements for discussion of significant litigation.Accounting for Income TaxesEFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. Oncoris a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group.EFH Corp. and its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) are boundby a Federal and State Income Tax Allocation Agreement, which provides, among other things, that each of EFCH, EFIH, TCEHand other subsidiaries under the agreement is required to make payments to EFH Corp. in an amount calculated to approximatethe amount of tax liability such entity would have owed if it filed a separate corporate tax return. EFH Corp., Oncor Holdingsand Oncor are parties to a separate tax sharing agreement, which governs the computation of federal income tax liability betweenEFH Corp., on one hand, and Oncor Holdings and Oncor, on the other hand, and similarly provides, among other things, that eachof Oncor Holdings and Oncor will make payments to EFH Corp. in an amount calculated to approximate the amount of tax liabilitysuch entity would have owed if it filed a separate corporate tax return.Our income tax expense and related balance sheet amounts involve significant management estimates and judgments.Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgmentsof the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realizationof deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual incometaxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, ourforecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxingauthorities. Our income tax returns are regularly subject to examination by applicable tax authorities. In management's opinion,the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that maybe owed as a result of any examination.64 Table of ContentsIn 2010, we reduced our liability for uncertain tax positions by $162 million to reflect the state of negotiations with the IRSon certain disputed tax issues. This reduction consisted of a $225 million reversal of accrued interest ($146 million after-tax),partially offset by a $63 million reclassification to net deferred tax liabilities. Upon conclusion of all issues contested with theIRS from its 1997 through 2002 audit of our federal income tax returns, which is expected to occur in the first half of 2013, weexpect to reduce the liability for uncertain tax positions by approximately $700 million with an offsetting decrease in deferred taxassets that arose largely from previous payments of alternative minimum taxes. Any cash income tax liability related to theconclusion of the 1997 through 2002 audit is expected to be immaterial. The IRS audit for the years 2003 through 2006 wasconcluded in June 2011. A significant number of proposed adjustments are in appeals with the IRS. The results of the audit didnot affect management's assessment of issues for purposes of determining the liability for uncertain tax positions. See Notes 1,4 and 5 to Financial Statements for discussion of income tax matters.Depreciation and AmortizationDepreciation expense related to generation facilities is based on the estimates of fair value and economic useful lives asdetermined in the application of purchase accounting for the Merger. The accuracy of these estimates directly affects the amountof depreciation expense. If future events indicate that the estimated lives are no longer appropriate, depreciation expense will berecalculated prospectively from the date of such determination based on the new estimates of useful lives.The estimated remaining lives range from 20 to 57 years for the lignite/coal- and nuclear-fueled generation units.Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives basedon the expected realization of economic effects. See Note 3 to Financial Statements for additional information.65 Table of ContentsRESULTS OF OPERATIONSConsolidated Financial Results -Year Ended December 31, 2012 Compared to Year Ended December 31, 2011See comparison of results of the Competitive Electric segment for discussion of variances in: operating revenues; fuel,purchased power costs and delivery fees; net gain from commodity hedging and trading activities; operating costs; depreciationand amortization; SG&A expenses and franchise and revenue-based taxes.In 2012, a $1.2 billion impairment of goodwill was recorded in the Competitive Electric segment as discussed in Note 3 toFinancial Statements.See Note 6 to Financial Statements for details of other income and deductions.Interest expense and related charges decreased $786 million, or 18%, to $3.508 billion in 2012. The decrease was drivenby a $984 million favorable change in unrealized mark-to-market net gains/losses on interest rate swaps, reflecting a mark-to-market gain of $172 million in 2012 compared to a mark-to-market loss of $812 million in 2011, partially offset by $242 millionin higher interest accrued/paid reflecting issuances of EFIH Notes and amendment and extension of the TCEH Senior SecuredFacilities completed in April 2011 (see Note 8 to Financial Statements).Income tax benefit totaled $1.232 billion and $1.134 billion in 2012 and 2011, respectively. The effective rate of 33.6% in2012, excluding the $1.2 billion nondeductible goodwill impairment charge, was comparable to the 34.0% rate in 2011. See Note5 to Financial Statements for reconciliation of these comparable effective rates to the US federal statutory rate.Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) decreased $16 million to $270 million in2012. Oncor's results reflected unusual charges of $57 million (pretax) in 2012 related to settlement of a management incentivepay plan and $7 million (pretax) in 2011 related to an inventory write-off. Other drivers of the change in Oncor's results werehigher tariffs, reflecting the 2011 rate case and other filings with the PUCT, partially offset by the effect of milder weather onrevenues and higher depreciation, operation and maintenance and interest expense. See Note 2 to Financial Statements.Net loss increased $1.447 billion to $3.360 billion in 2012." Net loss in the Competitive Electric segment increased $1.238 billion to $3.063 billion." Earnings from the Regulated Delivery segment decreased $16 million to $270 million as discussed above." After-tax net expenses from Corporate and Other activities totaled $567 million and $374 million in 2012 and 2011,respectively. The amounts in 2012 and 2011 include recurring interest expense on outstanding debt, as well as corporategeneral and administrative expenses. The $193 million increase reflected a $93 million pension charge, or $144 millionpretax, which represents the Corporate and Other portion of the $285 million total charge ($141 million balance reportedin the Competitive Electric segment) related to pension plan actions discussed in Note 13 to Financial Statements. Theincrease also reflected $72 million in higher net interest expense reflecting debt issuances at EFIH and P1K interestpayments on EFH Corp. Toggle Notes, partially offset by lower intercompany borrowings, reflecting the repayment aportion of the TCEH Demand Notes (see Notes 8 and 15 to Financial Statements).66 Table of ContentsConsolidated Financial Results -Year Ended December 31, 2011 Compared to Year Ended December 31, 2010See comparison of results of the Competitive Electric segment for discussion of variances in: operating revenues; fuel,purchased power costs and delivery fees; net gain from commodity hedging and trading activities; operating costs; depreciationand amortization; SG&A expenses and franchise and revenue-based taxes.In 2010, a $4.1 billion impairment of goodwill was recorded in the Competitive Electric segment as discussed in Note 3 toFinancial Statements.See Note 6 to Financial Statements for details of other income and deductions.Interest expense and related charges increased $740 million, or 21%, to $4.294 billion in 2011. Interest paid/accrued increased$346 million to $3.027 billion driven by higher average rates reflecting debt exchanges and amendments. The balance of theincrease reflected $605 million in higher unrealized mark-to-market net losses related to interest rate swaps, $58 million in higheramortization of debt issuance and amendment costs and discounts and $29 million in lower capitalized interest, partially offset bya $227 million decrease in interest accrued or paid with additional toggle notes due to debt exchanges and repurchases and $60million in lower amortization of interest rate swap losses at dedesignation of hedge accounting.Income tax benefit totaled $1.134 billion on a pretax loss in 2011 compared to income tax expense totaling $389 million ona pretax gain in 2010, excluding the $4.1 billion nondeductible goodwill impairment charge. The effective rate was 34.0% and27.8% in 2011 and 2010, respectively, excluding the goodwill impairment charge. The increase in the rate was driven by a $146million reversal in 2010 of previously accrued interest related to uncertain tax positions due to expected resolution of mattersrelated to the 1997 through 2002 tax audit.Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) increased $9 million to $286 million in2011 reflecting higher earnings at Oncor due to higher revenue rates and the effects of warmer weather, partially offset by higherdepreciation and operation and maintenance expense.Net loss decreased $899 million to $1.913 billion in 2011." Net loss in the Competitive Electric segment decreased $1.638 billion to $1.825 billion." Earnings from the Regulated Delivery segment increased $9 million to $286 million as discussed above." After-tax net expenses from Corporate and Other activities totaled $374 million in 2011 compared to net income of $374million in 2010. The amounts in 2011 and 2010 include recurring interest expense on outstanding debt, as well as corporategeneral and administrative expenses. The $748 million change reflected a $693 million (after tax) decrease in debtextinguishment gains (reported in other income) and the $121 million Corporate and Other portion of the 2010 reversalof previously accrued interest on uncertain tax positions discussed above, partially offset by an $86 million (after tax)decrease in interest expense and related charges driven by the effects of the liability management program.Non-GAAP Earnings MeasuresIn communications with investors, we use a non-GAAP earnings measure that reflects adjustments to earnings reported inaccordance with US GAAP in order to review and analyze underlying operating performance. These adjustments, which aregenerally noncash, consist of unrealized mark-to-market gains and losses, impairment charges, debt extinguishment gains andother charges, credits or gains that are unusual or nonrecurring. All such items and related amounts are disclosed in our annualreport on Form 10-K and quarterly reports on Form I0-Q. Our communications with investors also reference "Adjusted EBITDA,"which is a non-GAAP measure used in calculation of ratios in covenants of certain of our debt securities (see "Financial Condition-Liquidity and Capital Resources -Financial Covenants, Credit Rating Provisions and Cross Default Provisions" below).67 Table of ContentsCompetitive Electric SegmentFinancial ResultsOperating revenuesFuel, purchased power costs and delivery feesNet gain from commodity hedging and trading activitiesOperating costsDepreciation and amortizationSelling, general and administrative expensesFranchise and revenue-based taxesImpairment of goodwillOther incomeOther deductionsInterest incomeInterest expense and related chargesLoss before income taxesIncome tax (expense) benefitNet lossYear Ended December 31,2012 2011 2010$ 5,636 S 7,040 $ 8,235(2,816) (3,396) (4,371)389 1,011 2,161(888) (924) (837)(1,344) (1,471) (1,380)(659) (728) (722)(80) (96) (106)(1,200) -(4,100)14 45 903(223) (526) (21)46 87 91(2,892) (3,830) (2,957)(4,017) (2,788) (3,104)954 963 (359)$ (3,063) $ (1,825) $ (3,463)68 Table of ContentsCompetitive Electric SegmentSales Volume and Customer Count DataYear Ended December 31, 2012 20112012 2011 2010 % Change % ChangeSales volumes:Retail electricity sales volumes -(GWh):ResidentialSmall business (a)Large business and other customersTotal retail electricityWholesale electricity sales volumes (b)Total sales volumesAverage volume (kWh) per residential customer (c)Weather (North Texas average) -percent of normal (d):Cooling degree daysHeating degree daysCustomer counts:Retail electricity customers (end of period and in thousands) (e):ResidentialSmall business (a)Large business and other customersTotal retail electricity customers23,283 27,337 28,2085,914 7,059 8,04210,373 12,828 15,33939,570 47,224 51,58934,524 34,496 51,35974,094 81,720 102,94814,617 16,100 15,532(14.8)(16.2)(19.1)(16.2)0.1(9.3)(9.2)(3.1)(12.2)(16.4)(8.5)(32.8)(20.6)3.721.9(5.9)(8.2)(14.7)(5.0)(8.9)114.7% 132.7% 108.9% (13.6)82.0% 109.7% 116.6% (25.3)1,560 1,625 1,771176 185 21717 19 201,753 1,829 2,008(4.0)(4.9)(10.5)(4.2)(a) Customers with demand of less than 1 MW annually.(b) Includes net amounts related to sales and purchases of balancing energy in the "real-time market."(c) Calculated using average number of customers for the period.(d) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data fromreporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department ofCommerce). Normal is defined as the average over the 10-year period from 2000 to 2010.(e) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number ofmeters does not reflect the number of individual customers.69 Table of ContentsCompetitive Electric SegmentRevenue and Commodity Hedging and Trading ActivitiesYear Ended December 31, 2012 20112012 2011 2010 % Change % ChangeOperating revenues:Retail electricity revenues:ResidentialSmall business (a)Large business and other customersTotal retail electricity revenuesWholesale electricity revenues (b)(c)Amortization of intangibles (d)Other operating revenuesTotal operating revenues$ 2,918 $ 3,377 $ 3,663738 896 1,052717 997 1,2114,373 5,270 5,9261,005 1,482 2,00521 18 16237 270 288$ 5,636 $ 7,040 $ 8,235(13.6)(17.6)(28.1)(17.0)(32.2)16.7(12.2)(19.9)101.1(61.5)(7.8)(14.8)(17.7)(11.1)(26.1)12.5(6.3)(14.5)(3.7)(53.2)Net gain from commodity hedging and trading activities:Realized net gains on settled positionsUnrealized net gains (losses)Total$ 1,953 $971 $ 1,008(1,564) 40 1,153$ 389 S 1,011 $ 2,161(a) Customers with demand of less than 1 MW annually.(b) Upon settlement of physical derivative commodity contracts, such as certain electricity sales and purchase agreements andcoal purchase contracts, that we mark-to-market in net income, wholesale electricity revenues and fuel and purchased powercosts are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result,these line item amounts include a noncash component, which we deem "unrealized." (The offsetting differences betweencontract and market prices are reported in net gain from commodity hedging and trading activities.) These amounts are asfollows:Reported in revenuesReported in fuel and purchased power costsNet gainYear Ended December 31,2012 2011 2010$ (1)$ -$ (28)39 18 96$ 38 $ 18 S 68(c) Includes net amounts related to sales and purchases of balancing energy in the "real-time market."(d) Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting frompurchase accounting.70 Table of ContentsCompetitive Electric SegmentProduction, Purchased Power and Delivery Cost DataFuel, purchased power costs and delivery fees ($ millions):Fuel for nuclear facilitiesFuel for lignite/coal facilities (a)Total nuclear and lignite/coal facilities (a)Fuel for natural gas facilities and purchased power costs (a)(b)Amortization of intangibles (c)Other costsFuel and purchased power costsDelivery fees (d)TotalFuel and purchased power costs (which excludes generationfacilities operating costs) per MWh:Nuclear facilitiesLignite/coal facilities (a) (e)Natural gas facilities and purchased power (a) (f)Delivery fees per MWhProduction and purchased power volumes (GWh):Nuclear facilitiesLignite/coal facilities (g)Total nuclear- and lignite/coal facilitiesNatural gas-facilitiesPurchased power (h)Total energy supply volumesCapacity factors:Nuclear facilitiesLignite/coal facilities (g)TotalYear Ended December 31,2012 2011 2010$ 175 $ 160 $ 159816 992 915991 1,152 1,074323 426 1,49748 111 161194 309 1871,556 1,998 2,9191,260 1,398 1,452$ 2,816 $ 3,396 $ 4,3712012 2011% Change % Change$ 8.78 $ 8.30$ 20.54 $ 19.79$ 7.89$ 19.289.4(17.7)(14.0)(24.2)(56.8)(37.2)(22.1)(9.9)(17.1)5.83.8(15.4)7.63.2(15.2)(10.7)5.018.6(9.3)2.9(16.2)(11.4)0.68.47.3(71.5)(31.1)65.2(31.6)(3.7)(22.3)5.22.621.65.2(4.6)6.23.3(25.2)(88.5)(20.6)(4.6)1.6(0.5)$ 45.06$ 31.75$ 53.26 $ 43.81$ 29.52 $ 28.0619,897 19,283 20,20849,298 58,165 54,77569,195 77,448 '74,9831,295 1,233 1,6483,604 3,039 :26,31774,094 81,720 102,94898.5%70.0%76.4%95.7%83.5%86.2%100.3%82.2%86.6%(a) 2011 and 2010 reflect reclassifications of start-up fuel to lignite/coal from natural gas facilities to conform to current periodpresentation.(b) See note (b) to the "Revenue and Commodity Hedging and Trading Activities" table on previous page.(c) Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contractsand power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.(d) Includes delivery fee charges from Oncor.(e) Includes depreciation and amortization of lignite mining assets (except for incremental depreciation in 2011 due to theCSAPR as discussed in Note 3 to Financial Statements), which is reported in the depreciation and amortization expense lineitem, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (b) to the "Revenue andCommodity Hedging and Trading Activities" table on previous page.(f) Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (d) immediatelyabove.(g) Includes the estimated effects of economic backdown of lignite/coal-fueled units totaling 9,550 GWh, 4,290 GWh and 3,536GWh in 2012, 2011 and 2010, respectively.(h) Includes amounts related to line loss and power imbalances.71 Table of ContentsCompetitive Electric Segment -Financial Results -Year Ended December 31, 2012 Compared to Year Ended December 31,2011Effects of Change in Wholesale Electricity Market- As discussed above under "Significant Activities and Events and ItemsInfluencing Future Performance," the nodal wholesale market design implemented by ERCOT in December 2010 resulted inoperational changes that facilitate hedging and trading of power. As part of ERCOT's transition to a nodal wholesale market,volumes under nontrading bilateral purchase and sales contracts are no longer scheduled as physical power with ERCOT. As aresult of these changes in market operations, reported wholesale revenues and purchased power costs in 2012 and 2011 werematerially less than amounts reported in prior periods. Effective with the nodal market implementation, if volumes delivered toour retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we recordadditional wholesale revenues. Conversely, if volumes delivered to our retail and wholesale customers exceed our generationvolumes, we record additional purchased power costs. The resulting additional wholesale revenues or purchased power costs areoffset in net gain from commodity hedging and trading activities.Operating revenues decreased $1.404 billion, or 20%, to $5.636 billion in 2012.Retail electricity revenues decreased $897 million, or 17%, to $4.373 billion reflecting an $854 million decline due to lowersales volumes and $43 million in lower average prices. Sales volumes fell 16% reflecting declines in both the residential andbusiness markets. Residential market volumes were lower due to much milder weather and a 4% decrease in customer countsdriven by competitive activity. Business market volumes were lower due to a change in customer mix and lower customer countsdriven by competitive activity. Overall average retail pricing declined 1% driven by business markets.Wholesale electricity revenues decreased $477 million, or 32%, to $1.005 billion in 2012 driven by lower average prices,which reflected much milder weather, including the effects on prices of very hot weather in the summer of 2011, as well as lowernatural gas prices.Fuel, purchased power costs and delivery fees decreased $580 million, or 17%, to $2.816 billion in 2012. Lignite/coal fuelcosts decreased $176 million driven by an increase in economic backdown and planned and unplanned generation unit outages.Purchased power and other costs (including ancillary services) decreased $124 million reflecting lower wholesale electricity pricesand natural gas prices. Delivery fees declined $138 million reflecting lower retail volumes. Natural gas fuel costs decreased $63million reflecting lower prices. Amortization of intangibles decreased $63 million reflecting lower amortization of emissionallowances due to an impairment recorded in the third quarter 2011 and expiration ofcontracts fair-valued under purchase accountingat the Merger date.A 15% decrease in lignite/coal-fueled production was driven by increased economic backdown and generation unit plannedand unplanned outages, while nuclear-fueled production increased 3% reflecting one refueling outage in 2012 and two in 2011.Following is an analysis of amounts reported as net gain from commodity hedging and trading activities, which totaled $389million and $1.011 billion in net gains for the years ended December 31, 2012 and 2011, respectively, and is largely reflective ofthe natural gas price hedging program discussed above under "Significant Activities and Events and Items Influencing FuturePerformance -Natural Gas Price Hedging Program and Other Hedging Activities":Year Ended December 31, 2012Net Realized Net UnrealizedGains Losses TotalHedging positions $ 1,885 S (1,542) $ 343Trading positions 68 (22) 46Total $ 1,953 $ (1,564) $ 389Year Ended December 31, 2011Net Realized Net UnrealizedGains Gains TotalHedging positions $ 912 S 21 $ 933Trading positions 59 19 78Total $ 971 S 40 $ 1,01172 Table of ContentsWhile unrealized losses were recorded in both 2012 and 2011 to reverse previously recorded unrealized gains on positionssettled in the periods, the effect of greater declines in natural gas prices in 2011 on a larger hedge position resulted in net unrealizedgains in 2011.Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues andpurchased power costs, as required by accounting rules, totaled $38 million and $18 million in net gains in 2012 and 2011,respectively (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).Operating costs decreased $36 million, or 4%, to $888 million in 2012. The decrease reflected $17 million in lower nucleargeneration maintenance costs reflecting one refueling outage in 2012 and two in 2011, $10 million in lower costs related to newsystems implementation and process improvements at generation facilities and $5 million in lower lignite-fueled generationmaintenance costs reflecting timing and scope of work.Depreciation and amortization decreased $127 million, or 9%, to $1.344 billion in 2012. The decrease reflected increaseduseful lives and retirements of certain generation assets and accelerated mine asset depreciation in 2011 due to then planned mineclosures needed to comply with the CSAPR.SG&A expenses decreased $69 million, or 9%, to $659 million in 2012. The decrease reflected $30 million in lower baddebt expense due to improved collection and customer care processes, customer mix and lower revenues, $25 million in lowerretail marketing and related expense and $21 million in lower employee compensation and benefits costs.In 2012, a $1.2 billion impairment of goodwill was recorded as discussed in Note 3 to Financial Statements.Other income totaled $14 million in 2012 and $45 million in 2011. Other income in 2012 included a $6 million fee receivedto novate certain hedge transactions between counterparties. Other income in 2011 included $21 million related to the settlementof bankruptcy claims against a counterparty, $7 million for a property damage claim and $6 million from a franchise tax refundrelated to prior years. See Note 6 to Financial Statements.Other deductions totaled $223 million in 2012 and $526 million in 2011. Other deductions in 2012 included a $141 millioncharge related to pension plan actions discussed in Note 13 to Financial Statements, which represents the Competitive ElectricSegment portion of the $285 million total charge (balance reported in Corporate and Other), a $35 million impairment charge towritedown equipment remaining from cancelled generation projects and a $24 million impairment of mineral interest assets as aresult of lower natural gas drilling activity and prices. Other deductions in 2011 resulting from the issuance of the CSAPR includeda $418 million impairment charge for excess SO2 emission allowances due to emission allowance limitations under the CSAPRand a $9 million impairment of mining assets. Other deductions in 2011 also included $86 million in third party fees related tothe amendment and extension of the TCEH Senior Secured Facilities. See Note 6 to Financial Statements.Interest income decreased $41 million, or47%, to $46 million. The decrease was driven by lower intercompany debt balances.Interest expense and related charges decreased $938 million, or 24%, to $2.892 billion in 2012. The decrease was drivenby a $978 million favorable change in unrealized mark-to-market net gains/losses on interest rate swaps, reflecting a mark-to-market gain of $166 million in 2012 compared to a mark-to-market loss of $812 million in 2011.Income tax benefit totaled $954 million and $963 million on pretax losses in 2012 and 2011, respectively. The effectiverate was 33.9% in 2012, excluding the $1.2 billion nondeductible goodwill impairment charge, and 34.5% in 2011. The decreasein the effective rate was driven by the absence of the domestic production deduction due to an expected loss for federal incometax purposes in 2012 compared to income in 2011.After-tax loss for the segment increased $1.238 billion to $3.063 billion in 2012 reflecting the $1.2 billion goodwill impairmentcharge, lower revenues net of fuel, purchased power and delivery fees as well as lower results from commodity hedging and tradingactivities, partially offset by a favorable change in unrealized mark-to-market net gains/losses on interest rate swaps and theemission allowances impairment in 2011.73 Table of ContentsCompetitive Electric Segment -Financial Results -Year Ended December 31, 2011 Compared to Year Ended December 31,2010Operating revenues decreased $1.195 billion, or 15%, to $7.040 billion in 2011.Retail electricity revenues decreased $656 million, or 11%, to $5.270 billion and reflected the following:" An 8% decrease in sales volumes reduced revenues by $501 million and was driven by declines in the large and smallbusiness and residential markets. Business market volumes decreased 15% reflecting reduced contract signings drivenby competitive activity. Residential market volumes decreased 3% reflecting an 8% decline in customer count drivenby competitive activity, partially offset by a 4% increase in average consumption driven by warmer summer weather." Lower average pricing reduced revenues by $155 million reflecting declining prices in all customer segments. Loweraverage pricing is reflective of competitive activity in a lower wholesale power price environment and a change inbusiness customer mix.Wholesale electricity revenues decreased $523 million, or 26%, to $1.482 billion in 2011. The decrease is primarilyattributable to the nodal market change described above, partially offset by higher production from the new lignite-fueled generationunits and lower retail sales volumes.Fuel, purchased power costs and delivery fees decreased $975 million, or 22%, to $3.396 billion in 2011. Purchased powercosts decreased $1.029 billion driven by the effect of the nodal market described above. Delivery fees declined $54 millionreflecting lower retail sales volumes, partially offset by higher rates. Amortization of intangible assets decreased $50 millionreflecting expiration of contracts fair-valued at the Merger date under purchase accounting. These decreases were partially offsetby $77 million in higher coal/lignite costs driven by higher costs related to purchased coal and increased generation.A 6% increase in lignite/coal-fueled production was driven by increased production from the newly constructed generationfacilities, while nuclear-fueled production decreased 5% primarily due to planned outages in 2011.Following is an analysis ofamounts reported as net gain from commodity hedging and trading activities, which totaled $1.011billion and $2.161 billion in net gains for the years ended December 31, 2011 and 2010, respectively, which reflected the naturalgas price hedging program discussed above under "Significant Activities and Events and Items Influencing Future Performance-Natural Gas Price Hedging Program and Other Hedging Activities":Hedging positionsTrading positionsTotalHedging positionsTrading positionsTotalYear Ended December 31, 2011Net Realized Net UnrealizedGains Gains Total$ 912 $ 21 $ 93359 19 78S 971 $ 40 $ 1,011Year Ended December 31, 2010Net Realized Net UnrealizedGains Gains (Losses) Total$ 961 $ 1,157 $ 2,11847 (4) 43S 1,008 $ 1,153 $ 2,161Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues andpurchased power costs, as required by accounting rules, totaled $18 million in net gains in 2011 and $68 million in net gains in2010.74 Table of ContentsOperating costs increased $87 million, or 10%, to $924 million in 2011. The increase reflected $48 million in higher nucleargeneration maintenance costs reflecting two planned refueling outages in 2011 as compared to one planned refueling outage in2010 and $27 million in higher costs at legacy lignite/coal-fueled generation units reflecting spending for environmental controlsystems including the CSAPR, and supply chain technology and equipment reliability process improvements. The increase alsoreflected $20 million in incremental expense related to a new generation unit placed in service in May 2010. The operating costincreases were partially offset by $9 million in lower maintenance costs at natural gas-fueled generation facilities reflecting theretirement of nine units in 2010.Depreciation and amortization increased $91 million, or 7%, to $1.471 billion in 2011. The increase reflected $44 millionof accelerated depreciation in 2011 resulting from the revised estimated useful lives for mine assets due to the then planned mineclosures needed to comply with the CSAPR (see Note 3 to Financial Statements for discussion of the effects of the CSAPR), $37million in increased depreciation primarily related to lignite/coal-fueled generation facilities reflecting equipment additions andreplacements and $36 million in incremental depreciation related to the new lignite-fueled generation unit discussed above. Theseincreases were partially offset by $24 million in decreased amortization of intangible assets largely related to the retail customerrelationship and reflecting expected customer attrition (see Note 3 to Financial Statements).SG&A expenses increased $6 million, or 1%, to $728 million in 2011. The increase was driven by $39 million in higheremployee compensation and benefit costs and $16 million in higher information technology and other services costs, partiallyoffset by $52 million in lower retail bad debt expense due to improved collection initiatives and customer mix.In 2010, a $4.1 billion impairment of goodwill was recorded as discussed in Note 3 to Financial Statements.Other income totaled $45 million in 2011 and $903 million in 2010. Other income in 2011 included $21 million related tothe settlement of bankruptcy claims against a counterparty, $7 million for a property damage claim and $6 million from a franchisetax refund related to prior years. Other income in 2010 included debt extinguishment gains of $687 million, a $116 million gainon termination of a power sales contract, a $44 million gain on the sale of land and related water rights and a $37 million gainassociated with the sale of interests in a natural gas gathering pipeline business.Other deductions totaled $526 million in 2011 and $21 million in 2010. Other deductions in 2011 resulting from the issuanceof the CSAPR included a $418 million impairment charge for excess S02 emissions allowances due to emissions allowancelimitations under the CSAPR and a $9 million impairment of mining assets. Other deductions in 2011 also included $86 millionin third party fees related to the amendment and extension of the TCEH Senior Secured Facilities. See Notes 3, 6 and 8 to FinancialStatements.Interest expense and related charges increased $873 million, or 30%, to $3.830 billion in 2011. Interest paid/accrued increased$276 million to $2.531 billion driven by higher average rates reflecting debt exchanges and amendments. The balance of theincrease reflected $605 million in higher unrealized mark-to-market net losses related to interest rate swaps, $64 million in higheramortization of debt issuance and amendment costs and discounts and $29 million in lower capitalized interest, partially offset by$60 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting and a $51 million decrease ininterest accrued or paid with additional toggle notes due to debt exchanges and repurchases.Income tax benefit totaled $963 million on a pretax loss in 2011 compared to income tax expense totaling $359 million ona pretax gain in 2010 before the nondeductible goodwill impairment charge. The effective rate was 34.5% and 36.0% in 2011 and2010, respectively, excluding the goodwill impairment charge. The decrease in the rate was driven by lower state taxes due tolower taxable margins, partially offset by the effect of ongoing tax deductions (principally lignite depletion) on a pretax loss in2011 compared to pretax income in 2010.After-tax loss for the segment decreased $1.638 billion to $1.825 billion in 2011 reflectingthe $4.1 billion goodwill impairmentcharge in 2010, partially offset in 2011 by lower gains from commodity hedging and trading activities, higher interest expensedriven by unrealized mark-to-market net losses related to interest rate swaps, charges and expenses resulting from the issuance ofthe CSAPR and debt extinguishment gains in 2010.75 Table of ContentsCompetitive Electric Segment -Energy-Related Commodity Contracts and Mark-to-Market ActivitiesThe table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31,2012, 2011 and 2010. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.521billion in unrealized net losses in 2012 and $58 million and $1.219 billion in unrealized net gains in 2011 and 2010, respectively,arising from mark-to-market accounting for positions in the commodity contract portfolio. The portfolio consists primarily ofeconomic hedges but also includes trading positions.Commodity contract net asset at beginning of periodSettlements of positions (a)Changes in fair value of positions in the portfolio (b)Other activity (c)Commodity contract net asset at end of periodYear Ended December 31,2012 2011 2010$ 3,190 $ 3,097 $ 1,718(1,800) (1,081) (943)279 1,139 2,162(5) 35 160$ 1,664 $ 3,190 $ 3,097(a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and lossesrecognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amountsrelated to positions entered into and settled in the same month.(b) Represents unrealized net gains recognized, reflecting net gains related to positions in the natural gas price hedging program(see discussion above under "Significant Activities and Events and Items Influencing Future Performance -Natural GasPrice Hedging Program and Other Hedging Activities"), partially offset by net losses related to other hedging positions.Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into andsettled in the same month.(c) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt orpayment of cash or other consideration, generally related to options purchased/sold. The 2010 amount includes a $116million noncash gain on termination of a long-term power sales contract.Maturity Table -The following table presents the net commodity contract asset arising from recognition of fair values atDecember 31, 2012, scheduled by the source of fair value and contractual settlement dates of the underlying positions.Source of fair valuePrices actively quotedPrices provided by other external sourcesPrices based on modelsTotalPercentage of total fair valueMaturity dates of unrealized commodity contract net asset at December 31, 2012Less than Excess of1 year 1-3 years 4-5 years 5 years Total$ (25) $ (3) $ -$ -$ (28)1,089 574 --1,66334 (5) -- -29$ 1,098 $ 566 $ -$ -$ 1,66466% 34% ---% -% 100%The "prices actively quoted" category reflects only exchange-traded contracts for which active quotes are readily available.The "prices provided by other external sources" category represents forward commodity positions valued using prices for whichover-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT's North Hub extendthrough 2014 and over-the-counter quotes for natural gas generally extend through 2016, depending upon delivery point. The"prices based on models" category reflects non-exchange-traded options valued using option pricing models. In addition, thiscategory contains other contractual arrangements that may have both forward and option components, as well as other contractsthat are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 11 to FinancialStatements for fair value disclosures and discussion of fair value measurements.76 Table of ContentsFINANCIAL CONDITIONLiquidity and Capital ResourcesOperating Cash FlowsYear Ended December 31, 2012 Compared to Year Ended December 31, 2011 -Cash used in operating activities totaled$818 million in 2012 compared to cash provided by operating activities of $841 million in 2011. The change of S 1.659 billionreflected net changes in margin deposits totaling $1.0 billion. The change in margin deposits largely relates to the natural gashedging program; in 2012 more margin deposits were returned to counterparties due to settlement of maturing positions than werereceived from counterparties due to decreases in natural gas prices, while activity in 2011 reflected the opposite. The change incash flows also reflected cash contributions of $259 million related to pension plan actions (see Note 13 to Financial Statements),$188 million in higher cash interest payments and an increase of $175 million in working capital used reflecting timing of accountspayable and accrued expense payments.Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 -Cash provided by operating activitiesdecreased $265 million to $841 million in 2011. The change included the effect of amended accounting standards related to theaccounts receivable securitization program (see Note 7 to Financial Statements), under which the $383 million of funding underthe program at the January 1, 2010 adoption was reported as a use of operating cash flows and a source of financing cash flows.Excluding this accounting effect, cash provided by operating activities declined $648 million, which reflected lower cash earningsdue to the low wholesale power price environment, lower generation and higher fuel and operating costs at our legacy generationfacilities and an approximately $300 million increase in interest payments, partially offset by the contribution from the new lignite-fueled generation units (see Results of Operations). A $408 million increase in net margin deposits received from counterpartieswas substantially offset by a $249 million decrease in net cash received from Oncor in the form of income tax payments anddistributions. A $109 million income tax refund was paid to Oncor in 2011 for overpayments in 2010 related to federal taxes.Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statementof income by $179 million, $244 million and $282 million for the years ended December 31, 2012, 2011 and 2010, respectively.The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent withindustry practice, and amortization of intangible net assets arising from purchase accounting that is reported in various otherincome statement line items including operating revenues and fuel and purchased power costs and delivery fees.Financing Cash FlowsYear Ended December 31, 2012 Compared to Year Ended December 31, 2011 -Cash provided by financing activitiestotaled $3.373 billion in 2012 compared to cash used in financing activities totaling $1.014 billion in 2011. Activity in 2012reflected the issuance of $2.253 billion of EFIH senior notes, the proceeds from which were used to repay $950 million in borrowingsunder the TCEH Revolving Credit Facility and fund a $680 million escrow account, reported as restricted cash, that was used torepay TCEH Demand Notes in January 2013, and an increase in borrowings of $1.384 billion under the TCEH Revolving CreditFacility (see Note 8 to Financial Statements). Activity in 2012 also included a $159 million payment to settle transition bondreimbursement agreements with Oncor (see Note 15 to Financial Statements). Activity in 2011 reflected the amendment andextension of the TCEH Senior Secured Facilities and repayments of certain debt securities discussed immediately below.Year Ended December 31, 2011 Compared to Year Ended December 31, 2010- Cash used in financing activities totaled$1.014 billion and $264 million in 2011 and 2010, respectively. Activity in 2011 reflected the amendment and extension of theTCEH Senior Secured Facilities, including approximately $800 million in transaction costs, and repayment of certain debt securities,including $415 million of pollution control revenue bonds, as discussed in Note 8 to Financial Statements. Activity in 2010reflected the net repayment of debt as part of the liability management program, partially offset by a $96 million source of financingcash flows, reflecting a $383 million effect of an accounting change related to the accounts receivable securitization program asdiscussed above, net of a $287 million reduction of borrowings under the program.See Note 8 to Financial Statements for further detail of short-term borrowings and long-term debt.77 Table of ContentsInvesting Cash FlowsYear Ended December 31, 2012 Compared to Year Ended December 31, 2011 -Cash used in investing activities totaled$1.468 billion and $535 million in 2012 and 2011, respectively. Capital expenditures (excluding nuclear fuel purchases) increased$112 million to $664 million in 2012 reflecting increased environmental-related spending. Nuclear fuel purchases increased $81million to $213 million due to advance purchases necessary to fabricate fuel assemblies in time for the two nuclear unit refuelingoutages planned for 2014. Activity in 2012 also included a $680 million increase in restricted cash related to an escrow accountto repay the TCEH Demand Notes as discussed above. Activity in 2011 also included a $188 million reduction in restricted cashrelated to the TCEH Letter of Credit Facility facilitated by the amendment and extension of the TCEH Senior Secured Facilities.Capital expenditures, including nuclear fuel, in 2012 totaled $877 million and consisted of:* $339 million for major maintenance, primarily in existing generation operations;* $270 million for environmental expenditures related to generation units;* $213 million for nuclear fuel purchases, and* $55 million for information technology, nuclear generation development and other corporate investments.Cash capital expenditures for 2012 are net of $19 million of reimbursements from the DOE related to dry cask storage. Weexpect to be reimbursed for our allowable costs of constructing dry cask storage for spent nuclear fuel through 2013 in accordancewith a settlement agreement with the DOE.Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 -Cash used in investing activities totaled$535 million and $468 million in 2011 and 2010, respectively. Investing activities in 2010 reflected the return of a $400 millioncash investment posted with a derivative counterparty in 2009. Capital expenditures (excluding nuclear fuel purchases) decreased$286 million to $552 million in 2011 driven by a decrease in spending related to the construction of new generation facilities andtiming and scope of maintenance projects. Nuclear fuel purchases increased $26 million to $132 million in 2011 reflecting therefueling of both nuclear-fueled generation units in 2011. Activity in 2011 also included the $188 million reduction in restrictedcash discussed above.Capital expenditures, including nuclear fuel, in 2011 totaled $684 million and consisted of:* $338 million for major maintenance, primarily in existing generation operations;* $142 million for environmental expenditures related to generation units;* $132 million for nuclear fuel purchases, and* $72 million for information technology, nuclear generation development and other corporate investments.Cash capital expenditures in 2011 are net of $24 million of reimbursements from the DOE related to dry cask storage.78 Table of ContentsDebt Financing Activity -Activities related to short-term borrowings and long-term debt during the year endedDecember 31, 2012 are as follows (all amounts presented are principal, and repayments and repurchases include amounts relatedto capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):TCEH (a)EFCHEFIH (b)EFH Corp. (c)Total long-termTotal short-term -TCEH (d)TotalRepaymentsandBorrowings Repurchases$ 196 $ (30)(10)3,55754 (1,770)3,807 (1,810)1,384$ 5,191 $ (1,810)(a) Borrowings represent $181 million of noncash principal increases of TCEH Toggle Notes issued in May and November2012 in payment of accrued interest and $15 million of sale/leaseback and other lease transactions for mining equipment.Repayments represent $16 million of payments of principal at scheduled maturity dates and $14 million of payments ofcapital lease liabilities.(b) Borrowings include $1.304 billion of EFIH debt issued in exchanges for EFH Corp. debt in December 2012.(c) Borrowings represent $54 million of noncash principal increases of EFH Corp. Toggle Notes issued in May and November2012 in payment of accrued interest. Repayments include $1.761 billion of noncash retirements related to December 2012debt exchanges.(d) Short-term amount represents net borrowings under the TCEH Revolving Credit Facility.See Note 8 to Financial Statements for further detail of long-term debt and other financing arrangements.Available Liquidity- The following table summarizes changes in available liquidity for the year ended December 31, 2012.Cash and cash equivalents -EFH Corp. (parent entity)Cash and cash equivalents -EFIH (a)Cash and cash equivalents -TCEHTCEH Revolving Credit FacilityTCEH Letter of Credit FacilityTotal liquidityAvailable LiquidityDecember 31, 2012 December 31, 2011 Change$ 314 $ 660 $ (346)1,104 46 1,0581,175 120 1,055-1,384 (1,384)183 169 14$ 2,776 $ 2,379 $ 397(a) Includes $680 million in cash held in escrow that was used in January 2013 to settle the TCEH Demand Notes (see Note 8to Financial Statements).The increase in available liquidity of $397 million since December 31, 2011 was driven by proceeds from the issuance of$2.25 billion of EFIH Notes (see Note 8 to Financial Statements), partially offset by use of cash of $1.7 billion for the year endedDecember 31, 2012 reflecting cash used for capital expenditures, including nuclear fuel purchases, and cash used in operatingactivities. See discussion of cash flows above.79 Table of ContentsDebt Capacity -We believe that we (excluding the Oncor Ring-Fenced Entities) are permitted under our applicable debtagreements to issue additional debt (in each case, subject to certain exceptions and conditions set forth in our applicable debtdocuments) as follows:* EFH Corp. and EFIH collectively are permitted to issue up to approximately $250 million ofadditional aggregate principalamount of debt secured by EFIH's equity interest in Oncor Holdings, of which $15 million can be on a first-priority basisand the remainder on a second-priority basis;* EFIH is permitted under its debt agreements to issue up to approximately $375 million of additional principal amountof senior unsecured debt (subject to certain exceptions and conditions set forth in its debt agreements). Such unsecureddebt may be incurred for, among other things, exchanges for EFH Corp. unsecured debt;" TCEH is permitted to issue approximately $2.3 billion of additional aggregate principal amount of debt secured bysubstantially all of the assets of TCEH and certain of its subsidiaries (of which $410 million can be on a first-prioritybasis and the remainder on a second-priority basis), and" TCEH is permitted to issue an unlimited amount of additional first-priority debt in order to refinance the first-prioritydebt outstanding under the TCEH Senior Secured Facilities.These amounts are estimates based on our current interpretation of the covenants set forth in our debt agreements and do nottake into account exceptions in the debt agreements that may allow for the incurrence of additional secured or unsecured debt,including, but not limited to, acquisition debt, refinancing debt, capital leases and hedging obligations. Moreover, such amountscould change from time to time as a result of, among other things, the termination of any debt agreement (or specific terms therein)or amendments to the debt agreements that result from negotiations with new or existing lenders. In addition, covenants includedin agreements governing additional future debt may impose greater restrictions on our incurrence of secured or unsecured debt.Consequently, the actual amount of senior secured or unsecured debt that we are permitted to incur under our debt agreementscould be materially different than the amounts provided above.Liquidity Needs, Including Capital Expenditures -Capital expenditures and nuclear fuel purchases for 2013 are expectedto total approximately $750 million and include:* $560 million for investments in TCEH generation facilities, including approximately:* $460 million for major maintenance and* $100 million for environmental expenditures related to the MATS and other regulations;* $140 million for nuclear fuel purchases and* $50 million for information technology, nuclear generation development and other corporate investments.We expect cash flows from operations, cash on hand and availability under our credit facilities discussed in Note 8 to FinancialStatements to provide sufficient liquidity to fund our current obligations, projected working capital requirements and capitalspending for at least the next twelve months.Pension and OPEB Plan Funding- See Note 13 to Financial Statements and "Significant Activities and Events and ItemsInfluencing Future Performance -Pension Plan Actions" above.EFIH Toggle Notes Interest Election -EFIH has the option every six months at its discretion, ending with the interestpayment due June 2016, to use the payment-in-kind (PIK) feature of its toggle notes ($1.392 billion aggregate principal amountissued in December 2012 and January 2013) in lieu of making cash interest payments. Once EFIH makes a PIK election, theelection is valid for each succeeding interest payment period until it revokes the applicable election. Use of the PIK feature willbe evaluated at each election period, taking into account market conditions and other relevant factors at such time.EFIH will make its June 2013 interest payment and expects to make its December 2013 interest payment on the EFIH ToggleNotes by using the PIK feature of those notes. During the applicable PIK interest periods, the interest rate on these notes isincreased from 11.25% to 12.25%. As a result of the PIK election, EFIH will increase the aggregate principal amount of the notesby $83 million in June 2013 and is expected to issue an additional $90 million in December 2013. See Note 8 to FinancialStatements for further discussion of the EFIH Toggle Notes.80 Table of ContentsLiquidity Effects of Commodity Hedging and Trading Activities -Commodity hedging and trading transactions typicallyrequire a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or tradinginstrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other formsof credit support to satisfy such collateral posting obligations. At December 31,2012, approximately 85% of the long-term naturalgas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEHSenior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral postingrequirements for those hedging transactions. See Note 8 to Financial Statements for more information about the TCEH SeniorSecured Facilities.Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take intoaccount the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin postedto take into account changes in the value of the underlying commodity). The amount of initial margin required is generally definedby exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factorsincluding market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other formsas negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and othercorporate purposes, including reducing short-term borrowings under credit facilities, or is required to be deposited in a separateaccount and restricted from being used for working capital and other corporate purposes. At December 31,2012, all cash collateralheld was unrestricted. With respect to over-the-counter transactions, counterparties generally have the right to substitute lettersof credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterpartiesthereby reducing liquidity in the event that it was not restricted. See Note 17 to Financial Statements regarding restricted cash.With the natural gas price hedging program, increases in natural gas prices generally result in increased cash collateral andletter of credit postings to counterparties. At December 31, 2012, approximately 65 million MMBtu of positions related to thenatural gas price hedging program were not directly secured on an asset-lien basis and thus are subject to cash collateral postingrequirements.At December 31, 2012, TCEH received or posted cash and letters of credit for commodity hedging and trading activities asfollows:* $69 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), ascompared to $50 million posted at December 31, 2011;* $598 million in cash has been received from counterparties, net of $2 million in cash posted, for over-the-counter andother non-exchange cleared transactions, as compared to $1.055 billion received, net of $6 million in cash posted, atDecember 31, 2011;* $376 million in letters of credit have been posted with counterparties, as compared to $363 million posted at December 31,2011, and* $22 million in letters of credit have been received from counterparties, as compared to $103 million received atDecember 31, 2011.81 Table of ContentsIncome Tax Matters -EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, OncorHoldings and TCEH. EFH Corp. and EFCH are two of the corporate members of the EFH Corp. consolidated group, while eachofEFIH, Oncor Holdings and TCEH is classified as a disregarded entity for US federal income tax purposes. Oncor is apartnershipfor US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group. Pursuant to applicableUS Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint andseveral liability for the taxes of such group.EFH Corp. and its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) are boundby a Federal and State Income Tax Allocation Agreement, which provides, among other things, that any corporate member ordisregarded entity in the group is required to make payments to EFH Corp. in an amount calculated to approximate the amountof tax liability such entity would have owed if it filed a separate corporate tax return. EFH Corp., Oncor Holdings and Oncor areparties to a separate tax sharing agreement, which governs the computation of federal income tax liability between EFH Corp.,on one hand, and Oncor Holdings and Oncor and its subsidiary, on the other hand, and similarly provides, among other things,that each of Oncor Holdings and Oncor will make payments to EFH Corp. in an amount calculated to approximate the amount oftax liability such entity would have owed if it filed a separate corporate tax return.An excess loss account (ELA) and a deferred intercompany gain (DIG) are reflected in the tax basis of the EFCH stock heldby EFH Corp. The difference between EFH Corp.'s tax basis in the stock of EFCH and the amount of the stock investment forfinancial reporting purposes represents an outside basis difference. Because we have tax strategies available to us that we believewould avoid triggering income tax payments upon a transaction involving our investment in EFCH, we have not recorded deferredincome tax liabilities with respect to this outside basis difference. The ELA, totaling approximately $19 billion, was created inconnection with the Merger. The DIG, totaling approximately $4 billion, was created as a result of an internal corporatereorganization prior to the Merger. The financing transactions and internal corporate restructurings that created the ELA and DIGinvolved TCEH and its assets but not EFIH or Oncor Holdings.The ELA and/or DIG could be triggered as taxable income in certain limited situations, including an EFH Corp. dispositionof EFCH stock. The ELA and DIG are not mutually exclusive, and if a triggering event were to occur, the amount reported astaxable income would be less than the total amount of the ELA and DIG.We have no plans to separate EFCH from EFH Corp. or otherwise enter into a transaction to trigger the ELA or DIG astaxable income. We continue to evaluate various tax strategies to potentially eliminate the ELA and DIG without tax consequences.Income Tax Payments -In the next twelve months, income tax payments related to the Texas margin tax are expected tototal approximately $60 million, and we do not expect to pay any federal income taxes. Net payments totaled $71 million, $37million and $64 million for the years ended December 31, 2012, 2011 and 2010, respectively.We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions,but expect that no material federal income tax payments related to such positions will be made in the next twelve months (seeNote 4 to Financial Statements).Interest Rate Swap Transactions -See Note 8 to Financial Statements for discussion of TCEH's interest rate swaps.Accounts Receivable Securitization Program -TCEH participates in an accounts receivable securitization program withfinancial institutions. In accordance with transfers and servicing accounting standards, the trade accounts receivable amountsunder the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Underthe program, TXU Energy (originator) sells retail trade accounts receivable to TXU Energy Receivables Company, a consolidated,wholly-owned, bankruptcy-remote, direct subsidiary of TCEH. TXU Energy Receivables Company borrows funds from entitiesestablished for this purpose by the participating financial institutions using the accounts receivable as collateral. All new tradereceivables under the program generated by the originator are continuously purchased by TXU Energy Receivables Companywith the proceeds from collections of receivables previously purchased. Funding under the program and its predecessor totaled$82 million and $104 million at December 31, 2012 and 2011, respectively. See Note 7 to Financial Statements.82 Table of ContentsDistributions of Earnings from Oncor Holdings -Oncor Holdings' distributions of earnings to us totaled $147 million,$116 million and $169 million for the years ended December 31,2012,2011 and 2010, respectively. We also received a distributiontotaling $31 million from Oncor Holdings on February 15, 2013. See Note 2 to Financial Statements for discussion of limitationson amounts Oncor can distribute to its members.In 2009, the PUCT awarded certain CREZ construction projects to Oncor. See discussion above under "Significant Activitiesand Events and Items Influencing Future Performance -Oncor Matters with the PUCT." As a result of the increased capitalexpenditures for CREZ and the debt-to-equity ratio cap, our distributions from Oncor could be substantially reduced or temporarilydiscontinued during the CREZ construction period, which is expected to be largely completed by the end of 2013.Capitalization-- Our capitalization ratios consisted of 140.6% and 128.1% long-term debt, less amounts due currently, and(40.6)% and (28.])% common stock equity, at December 31, 2012 and 2011, respectively. Total debt to capitalization, includingshort-term debt, was 137.5% and 127.3% at December 31, 2012 and 2011, respectively.Financial Covenants, Credit Rating Provisions and Cross Default Provisions -The terms of the TCEH Senior SecuredFacilities contain a maintenance covenant with respect to leverage ratio. At December 31,2012, we were in compliance with suchcovenant.Covenants and Restrictions under Financing Arrangements -The TCEH Senior Secured Facilities and the indenturesgoverning substantially all of the debt EFH Corp.'s subsidiaries (excluding Oncor) have issued in connection with, and subsequentto, the Merger contain covenants that could have a material impact on our liquidity and operations. In particular, the TCEH SeniorSecured Facilities include a requirement to timely deliver to the lenders copies of audited annual financial statements that are notqualified as to the status of TCEH and its subsidiaries as a going concern.Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. SeniorNotes) for the year ended December 31, 2012 totaled $5.257 billion for EFH Corp. See Exhibits 99(b), 99(c) and 99(d) for areconciliation of net income (loss) to Adjusted EBITDA for EFH Corp., TCEH and EFIH, respectively, for the years endedDecember 31, 2012 and 2011.83 Table of ContentsThe table below summarizes TCEH's secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEHSenior Secured Facilities and various other financial ratios of EFH Corp., EFIH and TCEH that are applicable under certain otherthresholds in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the TCEH Senior SecuredNotes, the TCEH Senior Secured Second Lien Notes, the EFH Corp. Senior Notes and the EFIH Notes at December 31, 2012 and2011. The debt incurrence and restricted payments/limitations on investments covenants thresholds described below representlevels that must be met in order for EFH Corp., EFIH or TCEH to incur certain permitted debt or make certain restricted paymentsand/or investments. EFH Corp. and its consolidated subsidiaries are in compliance with their maintenance covenants. In January2013, in accordance with amendments to the terms of the EFH Corp. Senior Secured Notes and their governing indentures,restrictive covenants to the notes were removed. Accordingly, the related coverage ratios are not reflected below (see Note 8 toFinancial Statements).December 31, December 31,2012 2011Threshold Level atDecember 31, 2012Maintenance Covenant:TCEH Senior Secured Facilities:Secured debt to Adjusted EBITDA ratio (a)Debt Incurrence Thresholds:EFIH Notes:EFIH fixed charge coverage ratio (c)TCEH Senior Notes, Senior Secured Notes and SeniorSecured Second Lien Notes:TCEH fixed charge coverage ratioTCEH Senior Secured Facilities:TCEH fixed charge coverage ratioRestricted Payments/Limitations on InvestmentsThresholds:EFH Corp. Senior Notes:General restrictions (Sponsor Group payments):EFH Corp. leverage .ratioEFIH Notes:General restrictions (non-EFH Corp. payments):EFIH fixed charge coverage ratio (c) (e)General restrictions (EFH Corp. payments):EFIH fixed charge coverage ratio (c) (e)EFIH leverage ratioTCEH Senior Notes, Senior Secured Notes and SeniorSecured Second Lien Notes:TCEH fixed charge coverage ratioTCEH Senior Secured Facilities:Payments to Sponsor Group:TCEH total debt to Adjusted EBITDA ratio5.88 to 1.00 5.78 to 1.00 Must not exceed 8.00 to 1.00 (b)0.3 to 1.0(d)At least 2.0 to 1.0At least 2.0 to 1.0At least 2.0 to 1.01.2 to 1.0 1.3 to 1.01.2 to 1.0 1.3 to 1.010.1 to 1.0 9.7 to 1.0 Equal to or less than 7.0 to 1.02.1 to 1.0 81.7 to 1.0At least 2.0 to 1.00.3 to 1.07.0 to 1.0(d) At least 2.0 to 1.05.3 to 1.0 Equal to or less than 6.0 to 1.01.2 tol1. 1.3 to 1.0At least 2.0 to 1.08.5 to 1.0 8.7 to 1.0 Equal to or less than 6.5 to 1.0(a) At December 31, 2012, includes actual Adjusted EBITDA for the more recently constructed Oak Grove (I and 2) generationunits and the Sandow 5 generation unit and all outstanding debt under the Delayed Draw Term Loan. At December 31,2011,includes pro forma Adjusted EBITDA for the Oak Grove 2 unit as well as actual Adjusted EBITDA for Sandow 5 and OakGrove I units and all outstanding debt under the Delayed Draw Term Loan.(b) Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities and up to $1.5 billion ($906million excluded at December 31, 2012) principal amount of TCEH senior secured first lien notes whose proceeds are usedto prepay term loans or deposit letter of credit loans under the TCEH Senior Secured Facilities.(c) The December 31,2012 calculation excludes interest income on the EFH Corp. Senior Notes that EFIH returned as a dividendto EFH Corp. in January 2013 (see Note 8 to Financial Statements).(d) EFIH meets the ratio threshold. Because EFIH's interest income exceeds interest expense, the result of the ratio calculationis not meaningful.(e) The EFIH fixed charge coverage ratio fornon-EFH Corp. payments includes the results of Oncor Holdings and its subsidiaries.The EFIH fixed charge coverage ratio for EFH Corp. payments excludes the results of Oncor Holdings and its subsidiaries.84 Table of ContentsMaterial Credit Rating Covenants and Credit Worthiness Effects on Liquidity -As a result of TCEH's non-investment gradecredit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, at December 31, 2012,counterparties to those contracts could have required TCEH to post up to an aggregate of $20 million in additional collateral. Thisamount largely represents the below market terms of these contracts at December 31,2012; thus, this amount will vary dependingon the value of these contracts on any given day.Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REPto support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under thesetariffs, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equalto estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as thetime period of transition charges covered, varies by utility. At December 31, 2012, TCEH has posted collateral support in theform of letters of credit to the applicable utilities in an aggregate amount equal to $26 million, with $11 million of this amountposted for the benefit of Oncor.The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customerdeposits, if necessary. Under these rules, at December 31,2012, TCEH posted letters of credit in the amount of $71 million, whichare subject to adjustments.The RRC has rules in place to assure that parties can meet their mining reclamation obligations, including through self-bonding when appropriate. If Luminant Generation Company LLC (a subsidiary of TCEH) does not continue to meet the self-bonding requirements as applied by the RRC, TCEH may be required to post cash, letter of credit or other tangible assets ascollateral support in an amount currently estimated to be approximately $850 million to $1.1 billion. The actual amount (if required)could vary depending upon numerous factors, including the amount of Luminant Generation Company LLC's self-bond acceptedby the RRC and the level of mining reclamation obligations.ERCOT has rules in place to assure adequate credit worthiness of parties that participate in the "day-ahead," "real-time" andcongestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantlyin the form of letters of credit, totaling $190 million at December 31,2012 (which is subject to daily adjustments based on settlementactivity with ERCOT).Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issuesin the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in anamount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred, two or more ratingagencies downgrade Oncor's credit ratings below investment grade.Other arrangements of EFH Corp. and its subsidiaries, including Oncor's credit facility, the accounts receivable securitizationprogram (see Note 7 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged underthe agreements may be adjusted depending on the relevant credit ratings.85 Table of ContentsMaterial Cross Default/Acceleration Provisions-- Certain of our financing arrangements contain provisions that could resultin an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenantsthat could or does result in an acceleration ofpayments due. Such provisions are referred to as "cross default" or "cross acceleration"provisions.A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to theaccounts receivable securitization program, in an aggregate amount in excess of $200 million may result in a cross default underthe TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity ofoutstanding balances ($22.276 billion at December 31, 2012) under such facilities.The indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and the TCEH Senior Secured Second LienNotes contain a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtednessunder any instrument or instruments of TCEH or any of its restricted subsidiaries in an aggregate amount equal to or greater than$250 million may cause the acceleration of the TCEH Senior Notes, TCEH Senior Secured Notes and TCEH Senior SecuredSecond Lien Notes.Under the terms of a TCEH rail car lease, which had $41 million in remaining lease payments at December 31, 2012 andterminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in an aggregate principal amount of$ 100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively acceleratethe payment of any remaining lease payments due under the lease.Under the terms of another TCEH rail car lease, which had $44 million in remaining lease payments at December 31, 2012and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to thirdparty creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to theiroriginal stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of anyremaining lease payments due under the lease.The indentures governing the EFIH Notes contain a cross acceleration provision whereby a payment default at maturity oron acceleration of principal indebtedness under any instrument or instruments of EFIH or any of its restricted subsidiaries or ofany debt that EFIH guarantees in an aggregate amount equal to or greater than $250 million may cause the acceleration of theEFIH Notes.The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that appliesin the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under theprogram. TXU Energy Receivables Company (a direct subsidiary of TCEH) has a cross default threshold of $50,000. If any ofthese cross default provisions were triggered, the program could be terminated.We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event ofdefault or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess ofthresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on thecontract.Each of TCEH's natural gas hedging agreements and interest rate swap agreements that are secured with a lien on its assetson a pari passu basis with the TCEH Senior Secured Facilities and TCEH Senior Secured Notes contain a cross default provision.In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but rangingfrom $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedgingagreements would have the right to terminate its hedge or interest rate swap agreement with TCEH and require all outstandingobligations under such agreement to be settled.Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to resultin a significant effect on liquidity.86 Table of ContentsLong-Term Contractual Obligations and Commitments--The following table summarizes our contractual cash obligationsat December 31, 2012 (see Notes 8 and 9 to Financial Statements for additional disclosures regarding these long-term debt andnoncancellable purchase obligations).One to Three to MoreLess Than Three Five Than FiveContractual Cash Obligations: One Year Years Years Years TotalLong-term debt-principal (a) $ 91 $ 7,332 $ 18,589 $ 11,878 $ 37,890Long-term debt -interest (b) 3,328 6,318 4,870 4,628 19,144Operating and capital leases (c) 63 101 125 172 461Obligations under commodity purchaseand services agreements (d) 945 1,179 528 870 3,522Total contractual cash obligations $ 4,427 $ 14,930 S 24,112 $ 17,548 $ 61,017(a) Excludes short-term borrowings (including $2.054 billion of borrowings under the TCEH Revolving Credit Facilities thatmature in 2016), capital lease obligations (shown separately), unamortized premiums and discounts and fair value premiumsand discounts related to purchase accounting. Also excludes $83 million of additional principal amount of notes expectedto be issued in June 2013 and due in 2018, reflecting the election of the PIK feature on toggle notes as discussed above under"EFIH Toggle Notes Interest Election."(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interestrate swaps are calculated based on interest rates in effect at December 31, 2012.(c) Includes short-term noncancellable leases.(d) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the year-end2012 price for all periods except where contractual price adjustment or index-based prices are specified.The following are not included in the table above:" arrangements between affiliated entities and intercompany debt (see Note 15 to Financial Statements);" individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts withone counterparty that are more than $1 million on an aggregated basis have been included);* contracts that are cancellable without payment of a substantial cancellation penalty;* employment contracts with management, and* liabilities related to uncertain tax positions totaling $1.788 billion (as well as accrued interest totaling $217 million)discussed in Note 4 to Financial Statements as the ultimate timing of payment, if any, is not known.Guarantees -See Note 9 to Financial Statements for details of guarantees.OFF-BALANCE SHEET ARRANGEMENTSSee Notes 2 and 9 to Financial Statements regarding VIEs and guarantees, respectively.COMMITMENTS AND CONTINGENCIESSee Note 9 to Financial Statements for discussion of commitments and contingencies.CHANGES IN ACCOUNTING STANDARDSThere have been no recently issued accounting standards effective after December 31, 2012 that are expected to materiallyimpact our financial statements.87 Table of ContentsItem7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKAll dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwiseindicated.Market risk is the risk that we may experience a loss in value as a result of changes in market conditions affecting factors,such as commodity prices and interest rates, that may be experienced in the ordinary course of business. Our exposure to marketrisk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as wellas the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interestrate risk related to debt, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to managecommodity price risk.Risk OversightWe manage the commodity price, counterparty credit and commodity-related operational risk related to the competitiveenergy business within limitations established by senior management and in accordance with overall risk management policies.Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groupsthat operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies.These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value fromchanges in market conditions and include, but are not limited to, position review, Value at Risk (VaR) methodologies and stresstest scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review),operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validationand reporting, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.We have a corporate risk management organization that is headed by the Chief Financial Officer, who also functions as theChief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policiesand procedures to ensure compliance with such limits, and evaluates the risks inherent in our businesses.Commodity Price RiskThe competitive business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas andother energy-related products it markets or purchases. We actively manage the portfolio of owned generation assets, fuel supplyand retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in themarket, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices andspark spreads (differences between the market price of electricity and its cost of production).In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts withcustomers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. Wecontinuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to useconsistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.Natural Gas Price Hedging Program -See "Significant Activities and Events and Items Influencing Future Performance"above for a description of the program, including potential effects on reported results.88 Table of ContentsVaR Methodology--A VaR methodology is used to measure the amount of market risk that exists within the portfolio undera variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidencelevel and considers, among other things, market movements utilizing standard statistical techniques given historical and projectedmarket prices and volatilities.A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effectiveway to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this methodrequires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., thetime necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlationdata.Trading VaR -This measurement estimates the potential loss in fair value, due to changes in market conditions, of allcontracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five to 60 days.Year Ended December 31,2012 2011Month-end average Trading VaR: $ 7$ 4Month-end high Trading VaR:Month-end low Trading VaR:$$12 $1$81VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting -This measurement estimates thepotential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principallyhedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holdingperiod of five to 60 days.Year Ended December 31,2012 2011Month-end average MtM VaR: $ 132 $ 195Month-end high MtM VaR: $ 206 $ 268Month-end low MtM VaR:$96 $121Earnings at Risk (EaR) -This measurement estimates the potential reduction ofpretax earnings for the periods presented,due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). A95% confidence level and a five to 60 day holding period are assumed in determining EaR.Month-end average EaR:Month-end high EaR:Month-end low EaR:Year Ended December 31,2012 2011$ 109 $ 170$ 161 $ 228$ 77 $ 121The increase in the Trading VaR risk measure above reflected higher near-term market volatility and an increase in tradingpositions. The decreases in the MtM VaR and EaR risk measures above reflected a reduction of positions in the natural gas pricehedging program due to maturities and lower forward natural gas prices.89 Table of ContentsInterest Rate RiskThe table below provides information concerning our financial instruments at December 31,2012 and 2011 that are sensitiveto changes in interest rates, which consist of debt obligations and interest rate swaps. We have entered into interest rate swapsunder which we have exchanged fixed-rate and variable-rate interest amounts calculated with reference to specified notionalprincipal amounts at dates that generally coincide with interest payments under our credit facilities. In addition, we have enteredinto certain interest rate basis swaps to further reduce borrowing costs as discussed in Note 8 to Financial Statements. The weightedaverage interest rate presented is based on the rate in effect at the reporting date. Capital leases and the effects of unamortizedpremiums and discounts are excluded from the table. Average interest rate and average receive rate for variable rate instrumentsare based on rates in effect at December 31, 2012. See Note 8 to Financial Statements for a discussion of debt obligations.Expected Maturity Date(millions of dollars, except percentages)Long-term debt(including currentmaturities):Fixed rate debtamount (a)Average interestrate (b)Variable rate debtamountAverage interestrateTotal debtDebt swapped to fixed:Amount (c)Average pay rate2012 2012 2011 2011Total Total Total TotalThere- Carrying Fair Carrying Fair2013 2014 2015 2016 2017 after Amount Value Amount Value$ 91 $ 141 $3,147 $1,769 $ 640 $11,673 $17,461 $11,999 $15,464 $10,2497.24% 5.93% 10.24% 11.22%7.71% 10.95% 10.67%10.29%$ -$ 3,890 $ 154 $ 154 $16,026 $ 205 $20,429 $13,891 $20,429 $13,153/-% 3.76% 4.75% 4.75% 4.74% 0.23% 4.51% 4.54%$ 91 $ 4,031 $3,301 $1,923 $16,666 $11,878 $37,890 $25,890 $35,893 $23,402$ 1,600 $16,860 $3,000 $ -$ 9,600 $ -8.53% 8.24% 6.85% 0-% 8.95% -Average receive rate 4.81% 4.81% 4.87%Variable basis swaps:-% 4.88% -%AmountAverage pay rate$10,917 $ 1,050 $ -$ -$ -$ -$11,9670.33% 0.32% -% -% --0.33%$19,1670.39%0.26%Average receive rate 0.21% 0.21%-% -% --0.21%(a) Reflects the remarketing date and not the maturity date for certain debt that is subject to mandatory tender for remarketingprior to maturity. See Note 8 to Financial Statements for details concerning long-term debt subject to mandatory tender forremarketing.(b) Reflects 11.25% cash rate for EFIH Toggle Notes.(c) $18.46 billion notional amount outstanding that matures in 2013 through October 2014 and $12.6 billion notional amountbeginning October 2014 that mature through October 2017. Notional amounts maturing in 2013 will be replaced by accretionof existing swaps maturing through October 2014.At December 31, 2012, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $11 million, taking into account the interestrate swaps discussed in Note 8 to Financial Statements.90 Table of ContentsCredit RiskCredit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policieswith regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potentialcounterparty's financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific riskmitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negativeexposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businessesincluding methodologies to analyze counterparties' financial strength, measurement of current and potential future exposures andcontract language that provides rights for netting and setoff. Credit enhancements such as parental guarantees, letters of credit,surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed toassess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering intoan agreement with a counterparty that creates exposure. Further, we have established controls to determine and monitor theappropriateness of these limits on an ongoing basis. Prospective material changes in the payment history or financial conditionof a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. Thisprocess can result in the subsequent reduction of the credit limit or a request for additional financial assurances.Credit Exposure -Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) andnet asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $1.321billion at December 31, 2012. The components of this exposure are discussed in more detail below.Assets subject to credit risk at December 31, 2012 include $454 million in retail trade accounts receivable before taking intoaccount cash deposits held as collateral for these receivables totaling $64 million. The risk of material loss (after considerationof bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances foruncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historicalexperience, market or operational conditions and changes in the financial condition of large business customers.The remaining credit exposure arises from wholesale trade receivables, commodity contracts and hedging and tradingactivities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions,electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketingcompanies. At December 31,2012, the exposure to credit risk from these counterparties totaled $867 million taking into accountthe netting provisions of the master agreements described above but before taking into account $612 million in credit collateral(cash, letters of credit and other credit support). The net exposure (after credit collateral) of $255 million decreased $326 millionfor the year ended December 31, 2012, driven by maturities of positions in the natural gas price hedging program.Of this $255 million net exposure, essentially all is with investment grade customers and counterparties, as determined usingpublicly available information including major rating agencies' published ratings and our internal credit evaluation process. Thosecustomers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are ratedusing internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitorsand manages credit exposure to these customers and counterparties on this basis.91 Table of ContentsThe following table presents the distribution ofcredit exposure at December 31,2012 arising from wholesale trade receivables,commodity contracts and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable andnet asset positions in the balance sheet arising from hedging and trading activities after taking into consideration netting provisionswithin each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateralincludes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 12 to FinancialStatements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.Gross Exposure by MaturityExposure GreaterBefore Credit Credit Net 2 years or Between than 5Collateral Collateral Exposure less 2-5 years years TotalInvestment grade $ 866 $ 612 $ 254 $ 866 $ -- $ -$ 866Noninvestment grade 1 -1 1 -Totals $ 867 $ 612 $ 255 $ 867$ --$ -$ 867Investment grade 99.9% 99.6%Noninvestment grade 0.1% 0.4%In addition to the exposures in the table above, contracts classified as "normal" purchase or sale and non-derivative contractualcommitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that isfavorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.Nonperformance could have a material impact on future results of operations, liquidity and financial condition.ISignificant (10% or greater) concentration of credit exposure exists with three counterparties, which represented 19%, 15%and 10% of the $255 million net exposure. We view exposure to these counterparties to be within an acceptable level of risktolerance due to the counterparties' credit ratings, each of which is rated as investment grade, and the importance of our businessrelationship with the counterparties.With respect to credit risk related to the natural gas price hedging program, all of the transaction volumes are withcounterparties that have an investment grade credit rating. However, there is current and potential credit concentration risk relatedto the limited number of counterparties that comprise the substantial majority of the program, with such counterparties being inthe banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that wouldrequire the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. Anevent of default by one or more hedge counterparties could subsequently result in termination-related settlement payments thatreduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts ofexpected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with thesecounterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through thevarious ongoing risk management measures described above.92 Table of ContentsFORWARD-LOOKING STATEMENTSThis report and other presentations made by us contain "forward-looking statements." All statements, other than statementsof historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that addressactivities, events or developments that we expect or anticipate to occur in the future, including such matters as financial oroperational projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, futureacquisitions or dispositions, development or operation of power generation assets, market and industry developments and thegrowth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans,""will likely," "unlikely," "expected," "anticipated," "estimated," "should," "projection," "target," "goal," "objective" and "outlook"),are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations arebased on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety byreference to the discussion of risk factors under Item I A, "Risk Factors" and the discussion under Item 7, "Management's Discussionand Analysis of Financial Condition and Results of Operations" in this report and the following important factors, among others,that could cause our actual results to differ materially from those projected in such forward-looking statements:" prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas,the US Congress, the US Federal Energy Regulatory Commission, the NERC, the TRE, the PUCT, the RRC, the NRC,the EPA, the TCEQ, the US Mine Safety and Health Administration and the US Commodity Futures Trading Commission,with respect to, among other things:o allowed prices;o allowed rates of return;o permitted capital structure;o industry, market and rate structure;o purchased power and recovery of investments;o operations of nuclear generation facilities;o operations of fossil-fueled generation facilities;operations of mines;o acquisition and disposal of assets and facilities;" development, construction and operation of facilities;o decommissioning costs;" present or prospective wholesale and retail competition;changes in tax laws and policies;o changes in and compliance with environmental and safety laws and policies, including the CSAPR, MATS andclimate change initiatives, ando clearing over the counter derivatives through exchanges and posting of cash collateral therewith;" legal and administrative proceedings and settlements;" general industry trends;" economic conditions, including the impact of an economic downturn;" our ability to collect trade receivables from counterparties;" our ability to attract and retain profitable customers;" our ability to profitably serve our customers;" restrictions on competitive retail pricing;" changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;" changes in prices of transportation of natural gas, coal, crude oil and refined products;* changes in market heat rates in the ERCOT electricity market;* our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heatrates and interest rates;* weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts ofsabotage, wars or terrorist or cybersecurity threats or activities;* population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT;" changes in business strategy, development plans or vendor relationships;* access to adequate transmission facilities to meet changing demands;* changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;" changes in operating expenses, liquidity needs and capital expenditures;" commercial bank market and capital market conditions and the potential impact of disruptions in US and internationalcredit markets;* the willingness of our lenders to extend the maturities of our debt instruments and the terms and conditions of any suchextensions;93 Table of Contents" access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability offunds in capital markets;" activity in the credit default swap market related to our debt instruments;" restrictions placed on us by the agreements governing our debt instruments;" our ability to generate sufficient cash flow to make interest payments on, or refinance, our debt instruments;" our ability to successfully execute our liability management program or otherwise address our debt maturities;" any defaults under certain of our financing arrangements that could trigger cross default or cross acceleration provisionsunder other financing arrangements;" our ability to make intercompany loans or otherwise transfer funds among different entities in our corporate structure;* competition for new energy development and other business opportunities;* inability of various counterparties to meet their obligations with respect to our financial instruments;* changes in technology used by and services offered by us;* changes in electricity transmission that allow additional electricity generation to compete with our generation assets;* significant changes in our relationship with our employees, including the availability of qualified personnel, and thepotential adverse effects if labor disputes or grievances were to occur;* changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits,pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure underERISA;* changes in assumptions used to estimate future executive compensation payments;* hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resultingfrom such hazards;* significant changes in critical accounting policies;* actions by credit rating agencies;* adverse claims by our creditors or holders of our debt securities;* our ability to effectively execute our operational strategy, and* our ability to implement cost reduction initiatives.Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, weundertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it ismade or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us topredict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors,may cause results to differ materially from those contained in any forward-looking statement. As such, you should not undulyrely on such forward-looking statements.INDUSTRY AND MARKET INFORMATIONThe industry and market data and other statistical information used throughout this report are based on independent industrypublications, government publications, reports by market research firms or other published independent sources, including certaindata published by ERCOT, the PUCT and NYMEX. We did not commission any of these publications or reports. Some data isalso based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sourceslisted above. Independent industry publications and surveys generally state that they have obtained information from sourcesbelieved to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each ofthese studies and publications is reliable, we have not independently verified such data and make no representation as to theaccuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we donot know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly,while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and wemake no assurances that the predictions contained therein are accurate.94 Table of ContentsITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and Shareholders of Energy Future Holdings Corp.Dallas, TexasWe have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. and subsidiaries ("EFH Corp.")as of December 31, 2012 and 2011, and the related statements of consolidated income (loss), comprehensive income (loss), cashflows and equity for each of the three years in the period ended December 31,2012. Our audits also included the financial statementschedule listed in the Index at Item 15(a). These financial statements and financial statement schedule are the responsibility ofEFH Corp.'s management. Our responsibility is to express an opinion on these financial statements and financial statement schedulebased on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statementsare free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosuresin the financial statements. An audit also includes assessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonablebasis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy FutureHoldings Corp. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows foreach of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted inthe United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basicconsolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.EFH Corp. continues to experience net losses, has substantial indebtedness and has significant cash interest requirements. EFHCorp.'s ability to satisfy its obligations in October 2014, which include the maturities of $3.8 billion of TCEH Term Loan Facilities,is dependent upon the completion of one or more actions discussed in Note I to the consolidated financial statements. Also seeNote 8 to the consolidated financial statements.We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EFHCorp.'s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report datedFebruary 19, 2013 expressed an unqualified opinion on EFH Corp.'s internal control over financial reporting./s/ Deloitte & Touche LLPDallas, TexasFebruary 19, 201395 Table of ContentsENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIESSTATEMENTS OF CONSOLIDATED INCOME (LOSS)Operating revenuesFuel, purchased power costs and delivery feesNet gain from commodity hedging and trading activitiesOperating costsDepreciation and amortizationSelling, general and administrative expensesFranchise and revenue-based taxesImpairment of goodwill (Note 3)Other income (Note 6)Other deductions (Note 6)Interest incomeInterest expense and related charges (Note 17)Loss before income taxes and equity in earnings of unconsolidatedsubsidiariesIncome tax (expense) benefit (Note 5)Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2)Net lossYear Ended December 31,2012 2011 2010(millions of dollars)5,636 $ 7,040 $ 8,235(2,816) (3,396) (4,371)389 1,011 2,161(888) (924) (837)(1,373) (1,499) (1,407)(674) (742) (751)(80) (96) (106)(1,200) -(4,100)30 118 2,051(380) (553) (31)2 2 10(3,508) (4,294) (3,554)(4,862) (3,333) (2,700)1,232 1,134 (389)270 286 277$ (3,360) $ (1,913) $ (2,812)See Notes to Financial Statements.STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)Year Ended December 31,2012 2011 2010(millions of dollars)(3,360) $ (1,913) $ (2,812)Net lossOther comprehensive income, net of tax effects:Effects related to pension and other retirement benefit obligations (netof tax (expense) benefit of $(90), $(24) and S8) (Note 13)Cash flow hedges -Net decrease in fair value of derivatives held byunconsolidated subsidiary (net of tax benefit of $--, $13 and $-)Cash flow hedges derivative value net loss related to hedgedtransactions recognized during the period and reported in:Net loss (net of tax benefit of $3, $10 and $31)Equity in earnings of unconsolidated subsidiaries (net of tax benefitof $1, $- and $--)Total other comprehensive incomeComprehensive loss16645(13)(23)719592 -175 41 46$ (3,185) $ (1,872) $ (2,766)See Notes to Financial Statements.96 Table of ContentsENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIESSTATEMENTS OF CONSOLIDATED CASH FLOWSYear Ended December 31,2012 2011 2010(millions of dollars)Cash flows -operating activities:Net lossAdjustments to reconcile net loss to cash provided by (used in) operatingactivities:Depreciation and amortizationDeferred income tax expense (benefit), netImpairment of goodwill (Note 3)Unrealized net (gain) loss from mark-to-market valuations ofcommodity positionsUnrealized net (gain) loss from mark-to-market valuations of interestrate swaps (Note 8)Interest expense on toggle notes payable in additional principal (Notes8 and 17)Amortization of debt related costs, discounts, fair value discounts andlosses on dedesignated cash flow hedges (Note 17)Equity in earnings of unconsolidated subsidiariesDistributions of earnings from unconsolidated subsidiariesCharges related to pension plan actions (Note 13)Impairment of emissions allowances intangible assets (Note 3)Other asset impairments (Note 6)Third-party fees related to debt amendment and extension (Note 6)(reported as financing)Debt extinguishment gains (Notes 6 and 8)Gain on termination of long-term power sales contract (Note 6)Bad debt expense (Note 7)Accretion expense related primarily to mining reclamation obligations(Note 17)Stock-based incentive compensation expenseNet (gain) loss on sale of assetsOther, netChanges in operating assets and liabilities:Accounts receivable -tradeImpact of accounts receivable securitization program (Note 7)InventoriesAccounts payable -tradePayables due to unconsolidated subsidiaryCommodity and other derivative contractual assets and liabilitiesMargin deposits, netOther -net assetsOther -net liabilitiesCash provided by (used in) operating activities$ (3,360) $ (1,913) $ (2,812)1,552(1,252)1,2001,526(172)209238(270)147285711,743(1,219)(58)1,6896044,100(1,221)812219207446267(286)1164189100(51)56280(277)169(1,814)(116)10826371144813(3)(6)5719(81)821 176 258--(383)19 (23) (6)(142) (120) (93)(118) (78) -9 (31) (44)(476) 540 132(61) (7) 21(322) 119 (145)$ (818) $ 841 $ 1,10697 Table of ContentsENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIESSTATEMENTS OF CONSOLIDATED CASH FLOWSYear Ended December 3 1,2012 2011 2010(millions of dollars)Cash flows -financing activities:Issuances of long-term debt (Note 8)Repayments/repurchases of long-term debt (Note 8)Net short-term borrowings under accounts receivable securitizationprogram (Note 7)Increase (decrease) in other short-term borrowings (Note 8)Decrease in note payable to unconsolidated subsidiary (Note 15)Settlement of agreements with unconsolidated affiliate (Note 15)Sale/leaseback of equipmentContributions from noncontrolling interestsDebt amendment, exchange and issuance costs and discounts, includingthird-party fees expensedOther, netCash provided by (used in) financing activitiesCash flows -investing activities:Capital expendituresNuclear fuel purchasesProceeds from sales of assetsRestricted cash related to debt issuance (Note 8)Reduction of restricted cash related to TCEH Letter of Credit Facility(Note 8)Other changes in restricted cashProceeds from sales of environmental allowances and creditsPurchases of environmental allowances and creditsProceeds from sales of nuclear decommissioning trust fund securitiesInvestments in nuclear decommissioning trust fund securitiesRedemption of investment with derivative counterpartyOther, netCash used in investing activitiesNet change in cash and cash equivalentsEffect of deconsolidation of On;cor HoldingsCash and cash equivalents -beginning balanceCash and cash equivalents -ending balance2,253 $ 1,750 $ 853(41) (1,431) (1,351)(22) 8 961,384 (455) 172(20) (39) (37)(159) --15 --7 16 32(44) (857) (62)-(6) 333,373 (1,014) (264)(664)(213)2(680)(552)(132)52(838)(106)147-188 -129 (96) (33)-10 12(25) (17) (30)106 2,419 974(122) (2,436) (990)--400(1) 29 (4)(1,468) (535) (468)1,087(708)374826 1,534 1,189$ 1,913 $ 826 $ 1,534See Notes to Financial Statements.98 Table of ContentsENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETSDecember 31,2012 2011(millions of dollars)ASSETSCurrent assets:Cash and cash equivalentsRestricted cash (Note 17)Trade accounts receivable -net (includes $445 and $524 in pledged amounts related toa VIE (Notes 2 and 7))Inventories (Note 17)Commodity and other derivative contractual assets (Note 12)Margin deposits related to commodity positionsOther current assetsTotal current assetsRestricted cash (Note 17)Receivable from unconsolidated subsidiary (Note 15)Investment in unconsolidated subsidiary (Note 2)Other investments (Note 17)Property, plant and equipment -net (Note 17)Goodwill (Note 3)Identifiable intangible assets -net (Note 3)Commodity and other derivative contractual assets (Note 12)Other noncurrent assets, primarily unamortized debt amendment and issuance costsTotal assets1,913 $6808261297183931,595717674183,02556143 825,513 5,303947 947825 1,2355,850 5,720767 70918,705 19,4274,952 6,1521,755 1,845586 1,5521,070 1,187S 40,970 $ 44,077LIABILITIES AND EQUITYCurrent liabilities:Short-term borrowings (includes $82 and $104 related to a VIE (Notes 2 and 8))Long-term debt due currently (Note 8)Trade accounts payablePayables due to unconsolidated subsidiary (Note 15)Commodity and other derivative contractual liabilities (Note 12)Margin deposits related to commodity positionsAccumulated deferred income taxes (Note 5)Accrued interestOther current liabilitiesTotal current liabilitiesAccumulated deferred income taxes (Note 5)Commodity and other derivative contractual liabilities (Note 12)Notes or other liabilities due to unconsolidated subsidiary (Note 15)Long-term debt, less amounts due currently (Note 8)Other noncurrent liabilities and deferred credits (Note 17)Total liabilitiesCommitments and Contingencies (Note 9)Equity (Note 10):Common stock (shares outstanding 2012- 1,680,539,245; 2011 -1,679,539,245)Additional paid-in capitalRetained deficitAccumulated other comprehensive lossEFH Corp. shareholders' equityNoncontrolling interests in subsidiariesTotal equityTotal liabilities and equitySee Notes to Financial Statements.99S 2,136 $ 774103 47394 57419 1771,044 1,950600 1,06148 54571 480353 4975,268 5,6142,828 3,9891,556 1,692-- 13837,815 35,3604,426 5,04151,893 51,834227,959 7,947(18,939) (15,579)(47) (222)(11,025) (7,852)102 95(10,923) (7,757)$ 40,970 $ 44,077 Table of ContentsENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIESSTATEMENTS OF CONSOLIDATED EQUITYCommon stock stated value of $0.001 effective May 2009 (number ofauthorized shares -2,000,000,000):Balance at beginning of periodBalance at end of period (number of shares outstanding: 2012 -1,680,539,245; 2011 -1,679,539,245; 2010-- 1,671,812,118)Additional paid-in capital:Balance at beginning of periodEffects of stock-based incentive compensation plansCommon stock repurchasesOtherBalance at end of periodRetained earnings (deficit):Balance at beginning of periodNet loss attributable to EFH Corp.Balance at end of periodAccumulated other comprehensive loss, net of tax effects:Pension and other postretirement employee benefit liabilityadjustments:Balance at beginning of periodChange in unrecognized (gains) losses related to pension andOPEB plansBalance at end of periodAmounts related to dedesignated cash flow hedges:Balance at beginning of periodChange during the periodBalance at end of periodTotal accumulated other comprehensive loss at end of periodEFH Corp. shareholders' equity at end of period (Note 10)Noncontrolling interests in subsidiaries (Note 10):Balance at beginning of periodNet income attributable to noncontrolling interestsInvestments by noncontrolling interestsEffect of deconsolidation of Oncor Holdings (Notes I and 2)OtherNoncontrolling interests in subsidiaries at end of periodTotal equity at end of periodYear Ended December 31,2012 2011 2010(millions of dollars)$ 2 $ 2$ 22 2 27,947127,937117,91424--- (2)-- (1) 17,959 7,947 7,937(15,579) (13,666) (10,854)(3,360) (1,913) (2,812)(18,939) (15,579) (13,666)(149)(194)(181)166 45 (13)17 (149) (194)(73) (69) (128)9 (4) 59(64) (73) (69)(47) (222) (263)(11,025) (7,852) (5,990)95791,4117 16 32--(1,363)-- -- (1)102 95 79(10,923) $ (7,757) $ (5,911)See Notes to Financial Statements.100 Table of ContentsENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIESDescription of BusinessReferences in this report to "we," "our," "us" and "the company" are to EFH Corp. and/or its subsidiaries, as apparent in thecontext. See "Glossary" for defined terms.EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through itsTCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. EFCHis a holding company and a wholly-owned subsidiary of EFH Corp., and TCEH is a wholly-owned subsidiary of EFCH. TCEHis a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricitygeneration, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales.EFIH is a holding company and a wholly-owned subsidiary of EFH Corp. Oncor Holdings, a holding company and a wholly-owned subsidiary of EFIH, holds an approximately 80% equity interest in Oncor. Oncor is engaged in regulated electricitytransmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH,which sell electricity to residential, business and other consumers. Oncor (and its majority owner, Oncor Holdings) are notconsolidated in EFH Corp.'s financial statements in accordance with consolidation accounting standards related to variable interestentities (VIEs) (see Note 2).TCEH operates largely in the ERCOT market, and wholesale electricity prices in that market have generally moved withthe price ofnatural gas. Wholesale electricity prices have significant implications to its profitability and cash flows and, accordingly,the value of its business.Various "ring-fencing" measures have been taken to enhance the credit quality of Oncor. Such measures include, amongother things: the sale of a 19.75% equity interest in Oncor to Texas Transmission in November 2008; maintenance of separatebooks and records for the Oncor Ring-Fenced Entities; Oncor's board of directors being comprised of a majority of independentdirectors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, anymember of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct fromthose of the Texas Holdings Group, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt orcontractual obligations of any member of the Texas Holdings Group. Moreover, Oncor's operations are conducted, and its cashflows managed, independently from the Texas Holdings Group.We have two reportable segments: the Competitive Electric segment, consisting largely ofTCEH, and the Regulated Deliverysegment, consisting largely of our investment in Oncor. See Note 16 for further information concerning reportable businesssegments.Liquidity ConsiderationsEFH Corp.'s competitive business has been and is expected to continue to be adversely affected by the sustained decline innatural gas prices and its effect on wholesale and retail electricity prices in ERCOT. Further, the remaining natural gas hedgesthat TCEH entered into when forward market prices of natural gas were significantly higher than current prices will mature in2013 and 2014. These market conditions challenge the long-term profitability and operating cash flows of EFH Corp.'s competitivebusinesses and the ability to support their significant interest payments and debt maturities, and could adversely impact their abilityto obtain additional liquidity and service, refinance and/or extend the maturities of their outstanding debt.Note 8 provides the details of EFH Corp.'s and its consolidated subsidiaries' short-term borrowings and long-term debt,including principal amounts and maturity dates, as well as details of recent debt activity, including the three-year extension of theportion of the TCEH Revolving Credit Facility that would have expired in 2013. At December 31, 2012, TCEH had $1.2 billionof cash and cash equivalents and $183 million of available capacity under its letter of credit facility. Based on the current forecastof cash from operating activities, which reflects current forward market electricity prices, projected capital expenditures and othercash flows, including the settlement of the TCEH Demand Notes by EFH Corp., we expect that TCEH will have sufficient liquidityto meets its obligations until October 2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures. TCEH'sability to satisfy this obligation is dependent upon the implementation of one or more of the actions described immediately below.101 Table of ContentsEFH Corp. and its subsidiaries (other than Oncor Holdings and its subsidiaries) continue to consider and evaluate possibletransactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and mayfrom time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives. Thesetransactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to and extensionsof debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debt of EFCH and TCEHinto equity of EFH Corp., EFCH, TCEH and/or any of their subsidiaries. These actions could result in holders of TCEH debtinstruments not recovering the full principal amount of those obligations.Basis of PresentationThe consolidated financial statements have been prepared in accordance with US GAAP. See Note 2 for discussion of theprospective adoption of amended guidance regarding consolidation accounting standards related to VIEs that resulted in thedeconsolidation of Oncor Holdings effective January 1, 2010 and Note 7 for discussion of amended guidance regarding transfersof financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accountsreceivable and the funding under the program reported as short-term borrowings effective January 1, 2010. Investments inunconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, areaccounted for under the equity method (see Note 2). All intercompany items and transactions have been eliminated in consolidation.Any acquisitions of outstanding debt for cash, including notes that had been issued in lieu of cash interest, are presented in thefinancing activities section of the statement of cash flows. All dollar amounts in the financial statements and tables in the notesare stated in millions of US dollars unless otherwise indicated.Use of EstimatesPreparation of financial statements requires estimates and assumptions about future events that affect the reporting of assetsand liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. Inthe event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods toreflect more current information.Derivative Instruments and Mark-to-Market AccountingWe enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities and alsoenter into other derivative instruments such as options, swaps, futures and forwards primarily to manage our commodity price andinterest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instrumentsand hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses,unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the balance sheet.This recognition is referred to as "mark-to-market" accounting. The fair values of our unsettled derivative instruments undermark-to-market accounting are reported in the balance sheet as commodity and other derivative contractual assets or liabilities.We report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements we havewith counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the balancesheet. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gainsand losses and derivative assets and liabilities are reversed. See Notes I 1 and 12 for additional information regarding fair valuemeasurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accountingstandards related to derivative instruments and hedging activities, we may elect the "normal" purchase and sale exemption. Acommodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physicallyreceived or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accountedfor under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of thecontract until settlement.102 Table of ContentsBecause derivative instruments are frequently used as economic hedges, accounting standards related to derivativeinstruments and hedging activities allow for "hedge accounting," which provides for the designation of such instruments as cashflow or fair value hedges if certain conditions are met. A cash flow hedge mitigates the risk associated with the variability of thefuture cash flows related to an asset or liability (e.g., a forecasted sale of electricity in the future at market prices or the paymentof interest related to variable rate debt), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debtwith fixed interest rate payments). In accounting for changes in the fair value of cash flow hedges, derivative assets and liabilitiesare recorded on the balance sheet with an offset to other comprehensive income to the extent the hedges are effective and thehedged transaction remains probable of occurring. If the hedged transaction becomes probable of not occurring, hedge accountingis discontinued and the amount recorded in other comprehensive income is immediately reclassified into net income. If therelationship between the hedge and the hedged transaction ceases to exist or is dedesignated, hedge accounting is discontinued,and the amounts recorded in other comprehensive income are reclassified to net income as the previously hedged transactionimpacts net income. Changes in value of fair value hedges are recorded as derivative assets or liabilities with an offset to netincome, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset tonet income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or lossassociated with the hedge is amortized into income over the remaining life of the hedged item. In the statement of cash flow, theeffects of settlements of derivative instruments are classified consistent with the related hedged transactions.To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedgeditem. Assessment of the hedge's effectiveness is tested at least quarterly throughout its term to continue to qualify for hedgeaccounting. Changes in fair value that represent hedge ineffectiveness, even if the hedge continues to be assessed as effective,are immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the changein value of the hedging instrument over the change in value of the hedged item.At December 31, 2012 and 2011, there were no derivative positions accounted for as cash flow or fair value hedges.Accumulated other comprehensive income includes amounts related to interest rate swaps previously designated as cash flowhedges that are being reclassified to net income as the hedged transactions impact net income (see Note 8).Realized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reportedin the income statement in net gain (loss) from commodity hedging and trading activities. In accordance with accounting rules,upon settlement of physical derivative sales and purchase contracts that are marked-to-market in net income, related wholesaleelectricity revenues and fuel and purchased power costs are reported at approximated market prices, instead of the contract price.As a result, this noncash difference between market and contract prices is included in the operating revenues and fuel and purchasedpower costs and delivery fees line items ofthe income statement, with offsetting amounts included in net gain (loss) from commodityhedging and trading activities.Revenue RecognitionWe record revenue from electricity sales and delivery service under the accrual method of accounting. Revenues arerecognized when electricity or delivery services are provided to customers on the basis of periodic cycle meter readings and includean estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).We report physically delivered commodity sales and purchases in the income statement on a gross basis in revenues andfuel, purchased power and delivery fees, respectively, and we report all other commodity related contracts and financial instruments(primarily derivatives) in the income statement on a net basis in net gain (loss) from commodity hedging and trading activities.As part of ERCOT's transition to a nodal wholesale market effective December 1, 2010, volumes under nontrading bilateralpurchase and sales contracts, including contracts intended as hedges, are no longer scheduled as physical power with ERCOT.Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, effective with thenodal market implementation, such contracts are reported net in the income statement in net gain (loss) from commodity hedgingand trading activities instead of reported gross as wholesale revenues or purchased power costs. As a result of the changes inwholesale market operations, effective with the nodal market implementation, if volumes delivered to our retail and wholesalecustomers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues,and if volumes delivered to our retail and wholesale customers exceed, our generation volumes, we record additional purchasedpower costs. The additional wholesale revenues or purchased power costs are offset in net gain (loss) from commodity hedgingand trading activities.103 Table of ContentsImpairment of Long-LivedAssetsWe evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications ofimpairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are lessthan the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying valueexceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, ifapplicable. See Note 3 for discussion of impairments of intangible assets and mining-related assets in 2012 and 2011.We evaluate investments in unconsolidated subsidiaries for impairment when factors indicate that a decrease in the valueof the investment has occurred that is not temporary. Indicators that should be evaluated for possible impairment of investmentsinclude recurring operating losses of the investee or fair value measures that are less than carrying value. Any impairmentrecognition is based on fair value that is not reflective of temporary conditions. Fair value is determined primarily by discountedlong-term cash flows, supported by available market valuations, if applicable.Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives basedon the expected realization of economic effects. See Note 3 for additional information.Goodwill and Intangible Assets with Indefinite LivesWe evaluate goodwill and intangible assets with indefinite lives for impairment at least annually (at December 1). See Note3 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations and goodwillimpairments recorded in 2012, 2010 and 2009.Amortization of Nuclear FuelAmortization of nuclear fuel is calculated on the units-of-production method and is reported as fuel costs.Major MaintenanceMajor maintenance costs incurred during generation plant outages and the costs of other maintenance activities are chargedto expense as incurred and reported as operating costs.Defined Benefit Pension Plans and OPEB PlansWe offer pension benefits to eligible employees based on either a traditional defined benefit formula or a cash balanceformula and also offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon theretirement of such employees from the company. Costs of pension and OPEB plans are dependent upon numerous factors,assumptions and estimates. The pension and OPEB accrued benefit obligations reported in the balance sheet are in accordancewith accounting standards related to employers' accounting for defined benefit pension and other postretirement plans. See Notes13 and 15 for additional information regarding pension and OPEB plans, including a discussion of amendments to the EFH Corp.pension plan approved in August 2012.Stock-Based Incentive CompensationOur 2007 Stock Incentive Plan authorizes discretionary grants to directors, officers and qualified managerial employees ofEFH Corp. or its affiliates of non-qualified stock options, stock appreciation rights, restricted shares, shares of common stock, theopportunity to purchase shares of common stock and other stock-based awards. Stock-based compensation expense is recognizedover the vesting period based on the grant-date fair value of those awards. See Note 14 for information regarding stock-basedincentive compensation.Sales and Excise TaxesSales and excise taxes are accounted for as a "pass through" item on the balance sheet with no effect on the income statement;i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability tothe taxing jurisdiction.104 Table of ContentsFranchise and Revenue-Based TaxesUnlike sales and excise taxes, franchise and gross receipt taxes are not a "pass through" item. These taxes are assessed tous by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as anexpense. Rates we charge to customers are intended to recover our costs, including the franchise and gross receipt taxes, but weare not acting as an agent to collect the taxes from customers.Income TaxesWe file a consolidated federal income tax return, and pursuant to tax sharing agreements federal income taxes are calculatedfor our subsidiaries substantially as if the entities file separate corporate income tax returns. Deferred income taxes are providedfor temporary differences between the book and tax basis of assets and liabilities as required under accounting rules. Oncor is apartnership for US federal income tax purposes, and we provide deferred income taxes on the difference between the book andtax basis of our investment in Oncor. See Note 5.We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 4.Accounting for ContingenciesOur financial results may be affected byjudgments and estimates related to loss contingencies. Accruals for loss contingenciesare recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred andthat such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts andcircumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 9 for a discussion ofcontingencies.Cash and Cash EquivalentsFor purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity ofthree months or less are considered to be cash equivalents.Restricted CashThe terms of certain agreements require the restriction of cash for specific purposes. At December 31, 2012, $947 millionof cash was restricted to support letters of credit and $680 million related to an escrow account used to repay the TCEH DemandNotes in January 2013. See Notes 8 and 17 for more details regarding restricted cash.Fair Value of Nonderivative Financial InstrumentsThe carrying amounts of financial assets classified as current assets and the carrying amounts of financial liabilities classifiedas current liabilities approximate fair value due to the short maturity of such balances, which include cash equivalents, accountsreceivable and accounts payable.Property, Plant and EquipmentAs a result of purchase accounting, carrying amounts of property, plant and equipment related to competitive businesseswere adjusted to estimated fair values at the Merger date. Subsequent additions have been recorded at cost. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs.Depreciation of our property, plant and equipment is calculated on a straight-line basis over the estimated service lives ofthe properties. Depreciation expense is calculated on a component asset-by-asset basis. Estimated depreciable lives are based onmanagement's estimates of the assets'economic useful lives. See Note 17.105 Table of ContentsAsset Retirement ObligationsA liability is initially recorded at fair value for an asset retirement obligation associated with the retirement of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. These liabilities primarily relate to nucleargeneration plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatmentfacilities and generation plant asbestos removal and disposal costs. The obligation is initially measured at fair value. Over time,the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining usefullives of the assets. See Note 17.Capitalized InterestInterest related to qualifying construction projects and qualifying software projects is capitalized in accordance withaccounting guidance related to capitalization of interest cost. See Note 17.InventoriesInventories are reported at the lower of cost (on a weighted average basis) or market unless expected to be used in thegeneration of electricity. Also see discussion immediately below regarding environmental allowances and credits.EnvironmentalAllowances and CreditsWe account for all environmental allowances and credits as identifiable intangible assets with finite lives that are subject toamortization. The recorded values of these intangible assets were originally established reflecting fair value determinations as ofthe date of the Merger under purchase accounting. Amortization expense associated with these intangible assets is recognized ona unit of production basis as the allowances or credits are consumed in generation operations. The environmental allowances andcredits are assessed for impairment when conditions or events occur that could affect the carrying value of the assets and areevaluated with the generation units to the extent they are planned to be consumed in generation operations. See Note 6 for detailsof impairment amounts recorded in 2011.InvestmentsInvestments in unconsolidated subsidiaries that are 50% or less owned and/or do not meet accounting standards criteria forconsolidation are accounted for under the equity method. See Note 2 for discussion of VIEs and equity method investments.Investments in a nuclear decommissioning trust fund are carried at current market value in the balance sheet. Assets relatedto employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current marketvalue. See Note 17 for discussion of these and other investments.Noncontrolling InterestsSee Note 10 for discussion of accounting for noncontrolling interests in subsidiaries.106 Table of Contents2. VARIABLE INTEREST ENTITIESA variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level ofcontrol over the entity or results in economic risks to us. Accounting standards require consolidation of a VIE if we have (a) thepower to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (primarybeneficiary). In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decisionmaking processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationshipsamong the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.As discussed below, our balance sheet includes assets and liabilities of VIEs that meet the consolidation standards. OncorHoldings, an indirect wholly-owned subsidiary of EFH Corp. that holds an approximate 80% interest in Oncor, is not consolidatedin EFH Corp.'s financial statements, and instead is accounted for as an equity method investment, because the structural andoperational "ring-fencing" measures discussed in Note I prevent us from having power to direct the significant activities of OncorHoldings or Oncor. In accordance with accounting standards, we account for our investment in Oncor Holdings under the equitymethod, as opposed to the cost method, based on our level of influence over its activities. The maximum exposure to loss fromour interests in VIEs does not exceed our carrying value. See below for additional information about our equity method investmentin Oncor Holdings. There are no other material investments accounted for under the equity or cost method.Consolidated VIEsSee discussion in Note 7 regarding the VIE related to our accounts receivable securitization program that is consolidatedunder the accounting standards on a prospective basis effective January 1, 2010.We also consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEHand Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existingComanche Peak nuclear-fueled generation facility using MII's US-Advanced Pressurized Water Reactor technology and to obtaina combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries ofTCEH and MHI that hold 88% and 12% of CPNPC's equity interests, respectively (see Note 10).The carrying amounts and classifications of the assets and liabilities related to our consolidated VIEs are as follows:December 31, December 31,Assets: 2012 2011 Liabilities: 2012 2011Cash and cash equivalents $ 43 $ 10 Short-term borrowings $ 82 $ 104Accounts receivable 445 525 Trade accounts payable 1 IProperty, plant and equipment 134 132 Other current liabilities 7 9Other assets, including $12million and $2 million ofcurrent assets 16 6Total assets $ 638 $ 673 Total liabilities $ 90 $ 114The assets of our consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of our consolidatedVIEs do not have recourse to our assets to settle the obligations of the VIE.107 Table of ContentsNon-Consolidation of Oncor HoldingsThe adoption of amended accounting standards resulted in the deconsolidation of Oncor Holdings, which holds anapproximate 80% interest in Oncor, and the reporting ofour investment in Oncor Holdings under the equity method on a prospectivebasis effective January 1, 2010.In reaching the conclusion to deconsolidate, we conducted an extensive analysis of Oncor Holdings' underlying governingdocuments and management structure. Oncor Holdings' unique governance structure was adopted in conjunction with the Merger,when the Sponsor Group, EFH Corp. and Oncor agreed to implement structural and operational measures to "ring-fence" (theRing-Fencing Measures) Oncor Holdings and Oncor as discussed in Note 1. The Ring-Fencing Measures were designed to prevent,among other things, (i) increased borrowing costs at Oncor due to the attribution to Oncor of debt from any of our other subsidiaries,(ii) the activities of our competitive operations following the Merger resulting in the deterioration of Oncor's business, financialcondition and/or investment in infrastructure, and (iii) Oncor becoming substantively consolidated into a bankruptcy proceedinginvolving any member of the Texas Holdings Group. The Ring-Fencing Measures effectively separate the daily operational andmanagement control of Oncor Holdings and Oncor from EFH Corp. and its other subsidiaries. By implementing the Ring-FencingMeasures, Oncor maintained its investment grade credit rating following the Merger, and we reaffirmed Oncor's independencefrom our competitive businesses to the PUCT.We determined the most significant activities affecting the economic performance of Oncor Holdings (and Oncor) are theoperation, maintenance and growth of Oncor's electric transmission and distribution assets and the preservation of its investmentgrade credit profile. The boards of directors of Oncor Holdings and Oncor have ultimate responsibility for the management ofthe day-to-day operations of their respective businesses, including the approval of Oncor's capital expenditure and operatingbudgets and the timing and prosecution of Oncor's rate cases. While both boards include members appointed by EFH Corp., amajority of the board members are independent in accordance with rules established by the New York Stock Exchange, andtherefore, we concluded for purposes of applying the amended accounting standards that EFH Corp. does not have the power tocontrol the activities deemed most significant to Oncor Holdings' (and Oncor's) economic performance.In assessing EFH Corp.'s ability to exercise control over Oncor Holdings and Oncor, we considered whether it could takeactions to circumvent the purpose and intent of the Ring-Fencing Measures (including changing the composition ofOncor Holdings'or Oncor's board) in order to gain control over the day-to-day operations of either Oncor Holdings or Oncor. We also consideredwhether (i) EFH Corp. has the unilateral power to dissolve, liquidate or force into bankruptcy either Oncor Holdings or Oncor,(ii) EFH Corp. could unilaterally amend the Ring-Fencing Measures contained in the underlying governing documents of OncorHoldings or Oncor, and (iii) EFH Corp. could control Oncor's ability to pay distributions and thereby enhance its own cash flow.We concluded that, in each case, no such opportunity exists.Our investment in unconsolidated subsidiary as presented in the balance sheet totaled $5.850 billion and $5.720 billion atDecember 31, 2012 and 2011, respectively, and consists almost entirely of our interest in Oncor Holdings (100% owned), whichwe account for under the equity method as described above. Oncor provides services, principally electricity distribution, to TCEH'sretail operations, and the related revenues represented 29%, 33% and 36% of Oncor Holdings' consolidated operating revenuesfor the years ended December 31, 2012, 2011 and 2010, respectively.See Note 15 for discussion of Oncor Holdings' and Oncor's transactions with EFH Corp. and its other subsidiaries.Distributions from Oncor Holdings -Oncor Holdings' distributions of earnings to us totaled $147 million, $116 millionand $169 million for the years ended December 31, 2012, 2011 and 2010, respectively. Distributions were limited to Oncor'scumulative net income until December 31, 2012 and may not be paid except to the extent Oncor maintains a required regulatorycapital structure, as discussed below. At December 31, 2012, $167 million was eligible to be distributed to Oncor's members aftertaking into account the remaining regulatory capital structure limit, of which approximately 80% relates to our ownership interestin Oncor. The boards of directors of each of Oncor and Oncor Holdings can withhold distributions to the extent the applicableboard determines in good faith that it is necessary to retain such amounts to meet expected future requirements of Oncor and/orOncor Holdings.108 Table of ContentsFor the period beginning October 11, 2007 and ending December 31, 2012, distributions (other than distributions of theproceeds of any equity issuance) paid by Oncor to its members were limited by a PUCT order to an amount not to exceed Oncor'scumulative net income determined in accordance with US GAAP, as adjusted. Adjustments consisted of the removal of noncashimpacts of purchase accounting and deducting two specific cash commitments. The noncash impacts consisted of removing theeffect of an $860 million goodwill impairment charge in 2008 and the cumulative amount of net accretion of fair value adjustments.The two specific cash commitments were a $72 million ($46 million after tax) one-time refund to customers in September 2008and funds spent as part of a five-year, $100 million commitment for additional energy efficiency initiatives that was completedin 2012.Oncor's distributions continue to be limited by its regulatory capital structure, which is required to be at or below the assumeddebt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40%equity. At December 31, 2012, Oncor's regulatory capitalization ratio was 58.8% debt and 41.2% equity. The PUCT has theauthority to determine what types of debt and equity are included in a utility's debt-to-equity ratio. For purposes of this ratio, debtis calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums andlosses on reacquired debt. The debt calculation excludes bonds issued by Oncor Electric Delivery Transition Bond Company,which were issued in 2003 and 2004 to recover specific generation-related regulatory asset stranded and other qualified costs.Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of accounting forthe Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments andamortization). At December 31,2012, $167 million was available for distribution under the capital structure restriction, of whichapproximately 80% relates to our ownership interest in Oncor.In addition to distributions of earnings, under a tax sharing agreement we received income tax net payments from Oncor andOncor Holdings totaling $35 million for the year ended December 31, 2012, paid income tax net refunds to Oncor and OncorHoldings totaling $89 million for the year ended December 31,2011 and received income tax net payments from Oncor and OncorHoldings totaling $107 million for the year ended December 31, 2010 (see Note 15).Oncor Holdings Financial Statements- Condensed statements of consolidated income of Oncor Holdings and itssubsidiaries for the years ended December 31, 2012, 2011 and 2010 are presented below:Operating revenuesOperation and maintenance expensesDepreciation and amortizationTaxes other than income taxesOther incomeOther deductionsInterest incomeInterest expense and related chargesIncome before income taxesIncome tax expenseNet incomeNet income attributable to noncontrolling interestsNet income attributable to Oncor HoldingsYear Ended December 31,2012 2011 2010$ 3,328 $ 3,118 $ 2,914(1,171) (1,097) (1,009)(771) (719) (673)(415) (400) (384)26 30 36(64) (9) (8)24 32 38(374) (359) (347)583 596 567(243) (236) (220)340 360 347(70) (74) (70)$ 270 $ 286 $ 277109 Table of ContentsAssets and liabilities of Oncor Holdings at December 31, 2012 and 2011 are presented below:ASSETSCurrent assets:Cash and cash equivalentsRestricted cashTrade accounts receivable -netTrade accounts and other receivables from affiliatesInventoriesAccumulated deferred income taxesPrepayments and other current assetsTotal current assetsRestricted cashOther investmentsProperty, plant and equipment -netGoodwillNote receivable due from TCEHRegulatory assets -netOther noncurrent assetsTotal assetsLIABILITIESCurrent liabilities:Short-term borrowingsLong-term debt due currentlyTrade accounts payable -nonaffiliatesIncome taxes payable to EFH Corp.Accrued taxes other than incomeAccrued interestOther current liabilitiesTotal current liabilitiesAccumulated deferred income taxesInvestment tax creditsLong-term debt, less amounts due currentlyOther noncurrent liabilities and deferred creditsTotal liabilitiesDecember 31,2012 201145 $ 1255 57338 30353 17973 7126 7382 74672 769161683 7311,318 10,5694,064 4,064-- 1381,788 1,73078 7318,019 $ 17,432735 $ 392125 494121 19734 2153 15195 108110 1121,373 1,4561,736 1,68824285,400 5,1441,999 1,83210,532 $ 10,148110 Table of Contents3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETSGoodwillThe following table provides information regarding our goodwill balance, all of which relates to the Competitive Electricsegment. There were no changes to the goodwill balance for the year ended December 31, 2011. None of the goodwill is beingdeducted for tax purposes.Goodwill before impairment charges 18,342Accumulated impairment charges through 2011 (a) (12,190)Balance at December 31, 2011 6,152Additional impairment charge in 2012 (1,200)Balance at December 31, 2012 (b) $ 4,952(a) Includes $4.1 billion recorded in 2010 and $8.090 billion largely recorded in 2008 as described below.(b) Net of accumulated impairment charges totaling $13.390 billion.Goodwill ImpairmentsGoodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (wehave selected a December 1 test date) or whenever events or changes in circumstances indicate an impairment may exist.Because our analyses indicate that the carrying value of the Competitive Electric segment exceeds its estimated fair value(enterprise value), we perform the following steps in testing goodwill for impairment: first, we estimate the debt-free enterprisevalue of the business as of the testing date (December 1 for annual testing) taking into account future estimated cash flows andcurrent securities values of comparable companies; second, we estimate the fair values of the individual operating assets andliabilities of the business at that date; third, we calculate "implied" goodwill as the excess of the estimated enterprise value overthe estimated value of the net operating assets; and finally, we compare the implied goodwill amount to the carrying value ofgoodwill and, if the carrying amount exceeds the implied value, we record an impairment charge for the amount the carrying valueof goodwill exceeds implied goodwill.Changes in circumstances that we monitor closely include trends in natural gas prices. Wholesale electricity prices in theERCOT market, in which our Competitive Electric segment largely operates, have generally moved with natural gas prices asmarginal electricity demand is generally supplied by natural gas-fueled generation facilities. Accordingly, declining natural gasprices, which we have experienced since mid-2008, negatively impact our profitability and cash flows and reduce the value of ourgeneration assets, which consist largely of lignite/coal and nuclear-fueled facilities. While we have mitigated these effects withhedging activities, we are significantly exposed to this price risk. This market condition increases the risk of a goodwill impairment.Key inputs into our goodwill impairment testing at December 1, 2012 were as follows.* The carrying value (excluding debt) of the Competitive Electric segment exceeded its estimated enterprise value byapproximately 40%.* Enterprise value was estimated using a two-thirds weighting ofvalue based on internally developed cash flow projectionsand a one-third weighting of value using implied cash flow multiples based on current securities values of comparablepublicly traded companies.The discount rate applied to internally developed cash flow projections was 9.25%. The discount rate represents theweighted average cost of capital consistent with the risk inherent in future cash flows, taking into account the capitalstructure, debt ratings and current debt yields of comparable public companies as well as an estimate of return on equitythat reflects historical market returns and current market volatility for the industry.* The cash flow projections assume rising wholesale electricity prices, though the forecasted electricity prices are lessthan those assumed in the cash flow projections used in the 2011 goodwill impairment testing.* Enterprise value based on internally developed cash flow projections reflected annual estimates through 2018, with aterminal year value calculated using the "Gordon Growth Formula."III Table of ContentsChanges in the above and other assumptions could materially affect the calculated amount of implied goodwill.In the fourth quarter 2012, we recorded a $1.2 billion noncash goodwill impairment charge related to the Competitive Electricsegment. This amount represents our best estimate of impairment pending finalization of the fair value calculations, which isexpected in the first quarter 2013. The impairment charge reflected a decline in the estimated enterprise value of the CompetitiveElectric segment. The decline was due largely to lower wholesale electricity prices, reflecting the sustained decline in natural gasprices, and the maturing of positions in our natural gas hedge program, as reflected in our cash flow projections, as well as declinesin market values of securities of comparable companies. The impairment test was based upon values at the December 1, 2012test date.In the third quarter 2010, we recorded a $4.1 billion noncash goodwill impairment charge related to the Competitive Electricsegment. The impairment charge reflected a decline in the estimated enterprise value of the Competitive Electric segment. Thedecline was due largely to lower wholesale electricity prices, reflecting the sustained decline in natural gas prices, as reflected inour cash flow projections, as well as declines in market values of securities of comparable companies. The impairment test wasbased upon values as of the July 31, 2010 test date.In the first quarter 2009, we completed the fair value calculations supporting a $8.950 billion goodwill impairment charge,substantially all of which was recorded in 2008, that consisted of an impairment of $8.09 billion related to the Competitive Electricsegment and $860 million related to the Regulated Delivery segment. This charge was the first goodwill impairment recordedsubsequent to the Merger date.The impairment determinations involved significant assumptions and judgments. The calculations supporting the estimatesof the enterprise value of our businesses and the fair values of their operating assets and liabilities utilized models that take intoconsideration multiple inputs, including commodity prices, discount rates, debt yields, the effects of environmental rules, securitiesprices of comparable publicly traded companies and other inputs, assumptions regarding each of which could have a significanteffect on valuations. The fair value measurements resulting from these models are classified as non-recurring Level 3 measurementsconsistent with accounting standards related to the determination of fair value (see Note 11). Because of the volatility of thesefactors, we cannot predict the likelihood of any future impairment.Identifiable Intangible AssetsIdentifiable intangible assets reported in the balance sheet are comprised of the following:December 31, 2012GrossCarryingIdentifiable Intangible Asset AmountRetail customer relationship 463Favorable purchase and sales contracts 552Capitalized in-service software 356Environmental allowances and credits (a) 594Mining development costs 163Total intangible assets subject toamortization $ 2,128AccumulatedAmortization Net$ 378 $ 85314 238174 182393 20182 81December 31,2011GrossCarrying AccumulatedAmount Amortization Net$ 463 $ 344 $ 119548 288 260318 137 181582 375 207140 55 85$ 1,341Retail trade name (not subject toamortization)Mineral interests (not currently subject toamortization) (b)Total intangible assets787 $ 2,051 $ 1,19995585295513$ 1,75538$ 1,845(a) See discussion below regarding impairment of emission allowance intangible assets reported in other deductions in thethird quarter 2011 as a result of the EPA's issuance of the CSAPR in July 2011.(b) In 2012, we recorded an impairment charge (reported in other deductions) totaling $24 million related to certain mineralinterests whose fair value declined as a result of lower expected natural gas drilling activity and prices. The impairmentwas based on a Level 3 valuation (see Note 11).112 Table of ContentsAmortization expense related to intangible assets (including income statement line item) consisted of:Identifiable Intangible AssetRetail customer relationshipFavorable purchase and salescontractsCapitalized in-servicesoftwareEnvironmental allowances andcreditsIncome Statement LineDepreciation andamortizationOperating revenues/fuel,purchased power costs anddelivery feesDepreciation andamortizationFuel, purchased powercosts and delivery feesUseful lives atDecember 31, 2012 Year Ended December 31,(weighted average inSegment years) _2012 2011 2010CompetitiveElectric 5 $ 34 $ 51 $ 78CompetitiveElectric1125 31 35All5CompetitiveElectricCompetitiveElectricMining development costsTotal amortization expenseDepreciation andamortization25340 40 3518 71 9227 38 11$ 144 $ 231 $ 251Following is a description of the separately identifiable intangible assets recorded as part of purchase accounting for theMerger. The intangible assets were recorded at estimated fair value as of the Merger date, based on observable prices or estimatesof fair value using valuation models." Retailcustomer relationship- Retail customer relationship intangible asset represents the fair value of the non-contractedcustomer base and is being amortized using an accelerated method based on customer attrition rates and reflecting theexpected pattern in which economic benefits are realized over their estimated useful life." Favorable purchase and sales contracts -Favorable purchase and sales contracts intangible asset primarily representsthe above market value of commodity contracts for which: (i) we had made the "normal" purchase or sale electionallowed by accounting standards related to derivative instruments and hedging transactions or (ii) the contracts did notmeet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of thecontracts. Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits(see Note 17)." Retail trade name -The trade name intangible asset represents the fair value of the TXU Energy trade name, and wasdetermined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairmentat least annually in accordance with accounting guidance related to goodwill and other intangible assets." Environmental allowances and credits -This intangible asset represents the fair value of environmental credits,substantially all of which were expected to be used in our power generation activities. These credits are amortizedutilizing a units-of-production method.Estimated Amortization ofIntangible Assets -The estimated aggregate amortization expense of intangible assets for eachof the next five fiscal years is as' follows:Year Estimated Amortization Expense2013 $ 1332014 $ 1162015 $ 1052016 $ 862017 $ 67113 Table of ContentsCross-State Air Pollution Rule Issued by the EPAIn July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR), compliance with which would have requiredsignificant additional reductions of sulfur dioxide (SO2) and nitrogen oxide (NO,) emissions firom our fossil-fueled generationunits. In order to meet the emissions reduction requirements by the dates mandated in July 2011, we determined it would benecessary to idle two of our lignite/coal-fueled generation units at our Monticello facility by the end of 2011, switch the fuel weuse at three lignite/coal-fueled generation units from a blend of Texas lignite and Wyoming Powder River Basin coal to 100 percentPowder River Basin coal, cease lignite mining operations that serve our Big Brown and Monticello generation facilities in the firstquarter 2012 and construct upgraded scrubbers at five of our lignite/coal-fueled generation units. The action plan to cease operationsat the mines required an evaluation of the remaining useful lives and recoverability of recorded values of tangible and intangibleassets related to the mines. This evaluation resulted in the recording of accelerated depreciation and amortization expense in thethird and fourth quarters of 2011 related to mine assets totaling $44 million. Also, in the third quarter 2011, we recorded assetimpairments totaling $9 million related to capital projects in progress at the mines.Additionally, because of emissions allowance limitations under the CSAPR, we would have had excess SO2 emissionallowances under the Clean Air Act's existing acid rain cap-and-trade program, and market values of such allowances were estimatedto be de minimis based on Level 3 fair value estimates, which are described in Note 11. Accordingly, we recorded a noncashimpairment charge of $418 million (before deferred income tax benefit) related to our existing SO2 emission allowance intangibleassets in the third quarter 2011. SO2 emission allowances granted to us were recorded as intangible assets at fair value in connectionwith purchase accounting related to the Merger in October 2007.In light of ajudicial stay of the CSAPR at the end of 2011 and the U.S. Court of Appeals' for the District of Columbia CircuitAugust 2012 decision to vacate the CSAPR and remand it to the EPA for further proceedings (see Note 9), we did not idle the twoMonticello generation units at the end of 2011 and have continued mining lignite at the mines that serve the Big Brown andMonticello generation facilities.4. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXESAccounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed andassessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to theultimate outcome, regardless of whether this assessment is favorable or unfavorable.We file or have filed income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by theIRS and other taxing authorities.. Examinations of our income tax returns for the years ending prior to January 1,2007 are complete,but the tax years 1997 to 2006 remain in appeals with the IRS, with closing agreements reached on such appeals for tax years1997 to 2002 currently under review by the IRS Joint Committee. Federal income tax returns are under examination for tax years2007 to 2009. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginningafter 2002.The IRS audit for the years 2003 through 2006 was concluded in June 2011. A significant number of proposed adjustmentsare in appeals with the IRS. The results of the audit did not affect management's assessment of issues for purposes of determiningthe liability for uncertain tax positions.In 2010, we engaged in negotiations with the IRS regarding the 2002 worthlessness loss associated with our discontinuedEurope business as well as other matters. Accordingly, we have adjusted the liability for uncertain tax positions to reflect the mostlikely settlement of the issues. The adjustment resulted in a net reduction of the liability for uncertain tax positions totaling $162million. This reduction consisted of a $225 million reversal of accrued interest ($146 million after tax), reported as a reductionof income tax expense, principally related to the discontinued Europe business, partially offset by $63 million in adjustmentsrelated to several other positions that have been accounted for as reclassifications to net deferred tax liabilities. The conclusionof all issues contested from the 1997 through 2002 audit, including IRS Joint Committee review, is expected to occur in 2013.Upon such conclusion, we expect to further reduce the liability for uncertain tax positions by approximately $700 million with anoffsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes. Any cashincome tax liability related to the conclusion of the 1997 through 2002 audit is expected to be immaterial.114 Table of ContentsWe classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded relatedto interest and penalties totaled an expense of $16 million and $18 million in 2012 and 2011, respectively, and a benefit of $115million in 2010 (all amounts after tax).Noncurrent liabilities included a total of $217 million and $193 million in accrued interest at December 31,2012 and 2011,respectively. The federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferredincome taxes.The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in theconsolidated balance sheet, during the years ended December 31, 2012, 2011 and 2010:Year Ended December 31,2012 2011 2010Balance at January 1, excluding interest and penalties (a) $ 1,779 $ 1,642 $ 1,566Additions based on tax positions related to prior years 19 81 312Reductions based on tax positions related to prior years (33) (6) (308)Additions based on tax positions related to the current year 23 62 72Balance at December 31, excluding interest and penalties $ 1,788 $ 1,779 $ 1,642(a) 2010 reflects the deconsolidation of Oncor Holdings, which had a balance of $72 million, at January 1, 2010.Of the balance at December 31, 2012, $1.569 billion represents tax positions for which the uncertainty relates to the timingof recognition in tax returns. The disallowance of such positions would not affect the effective tax rate, but could accelerate thepayment of cash to the taxing authority to an earlier period.With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should we sustain suchpositions on income tax returns previously filed, tax liabilities recorded would be reduced by $219 million, and accrued interestwould be reversed resulting in a $35 million after-tax benefit, resulting in increased net income and a favorable impact on theeffective tax rate.Other than the items discussed above, we do not expect the total amount of liabilities recorded related to uncertain taxpositions will significantly increase or decrease within the next 12 months.115 Table of Contents5. INCOME TAXESEFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. EFHCorp. and EFCH are two of the corporate members of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdingsand TCEH is classified as a disregarded entity for US federal income tax purposes. Oncor is a partnership for US federal incometax purposes and is not a corporate member of the EFH Corp. consolidated group. Pursuant to applicable US Treasury regulationsand published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for thetaxes of such group.EFH Corp. and its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) are boundby a Federal and State Income Tax Allocation Agreement, which provides, among other things, that any corporate member ordisregarded entity in the group is required to make payments to EFH Corp. in an amount calculated to approximate the amountof tax liability such entity would have owed if it filed a separate corporate tax return. EFH Corp., Oncor Holdings and Oncor areparties to a separate tax sharing agreement, which governs the computation of federal income tax liability between EFH Corp.,on one hand, and Oncor Holdings and Oncor, on the other hand, and similarly provides, among other things, that each of OncorHoldings and Oncor will make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability suchentity would have owed if it filed a separate corporate tax return.The components of our income tax expense (benefit) are as follows:Current:US FederalStateTotal currentDeferred:US FederalStateTotal deferredTotalYear Ended December 31,2012 2011 2010$ (19) $ 46 $ (256)39 39 4120 85 (215)(1,233)(1,222)590(19) 3 14(1,252) (1,219) 604$ (1,232) $ (1,134) $ 389Reconciliation of income taxes computed at the US federal statutory rate to income tax expense:Income (loss) before income taxesIncome taxes at the US federal statutory rate of 35%Nondeductible goodwill impairmentTexas margin tax, net of federal benefitInterest accrued for uncertain tax positions, net of taxNondeductible interest expenseLignite depletion allowanceOtherIncome tax expense (benefit)Effective tax rateYear Ended December 31,2012 2011 2010$ (4,862) $ (3,333) $ (2,700)$ (1,702) $ (1,167) $ (945)420 -1,43512 27 3416 18 (115)22 15 11(19) (23) (21)19 (4) (10)$ (1,232) $ (1,134) $ 38925.3% 34.0% (14.4)%116 Table of ContentsDeferred Income Tax BalancesDeferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2012 and 2011 areas follows:December 31,20122011Total Current Noncurrent Total Current NoncurrentDeferred Income Tax AssetsAlternative minimum tax creditcarryforwardsEmployee benefit obligationsNet operating loss (NOL) carryforwardsUnfavorable purchase and salescontractsDebt extinguishment gainsAccrued interestOtherTotalDeferred Income Tax LiabilitiesProperty, plant and equipmentCommodity contracts and interest rateswapsIdentifiable intangible assetsDebt fair value discountsOtherTotalNet Deferred Income Tax Liability381 $1271,197-- $ 381 $-- 127-- 1,197382 $207699S$ 382-- 207699221 -221 231 -231729 -729 560 -560240 -240 210 -210197 -197 318 -3183,092 -3,092 2,607 -2,6074,327731514-4,32731 700-5144,2391,391631-4,23931 1,360-631373 -373 323 -32323 17 6 66 23 435,968 48 5,920 6,650 54 6,596$ 2,876 $ 48 $ 2,828 $ 4,043 $ 54 $ 3,989At December 31, 2012 we had $381 million of alternative minimum tax credit carryforwards (AMT) available to offsetfuture tax payments. The AMT credit carryforwards have no expiration date. At December 31, 2012, we had net operating loss(NOL) carryforwards for federal' income tax purposes of $3.4 billion that expire between 2028 and 2033. The NOL carryforwardscan be used to offset future taxable income. We expect to utilize all of our NOL carryforwards prior to their expiration dates.The income tax effects of the components included in accumulated other comprehensive income at December 31, 2012 and2011 totaled a net deferred tax asset of $25 million and $119 million, respectively.See Note 4 for discussion regarding accounting for uncertain tax positions.Effect of Health Care Legislation -The Patient Protection and Affordable Care Act and the Health Care and EducationReconciliation Act enacted in March 2010 reduces, effective in 2013, the amount of OPEB costs deductible for federal incometax purposes by the amount of the Medicare Part D subsidy we receive. Under income tax accounting rules, deferred tax assetsrelated to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in 2010,EFH Corp.'s and Oncor's deferred tax assets were reduced by $50 million. Of this amount, $8 million was recorded as a chargeto income tax expense and $42 million was recorded in receivables from unconsolidated subsidiary, reflecting a regulatory assetrecorded by Oncor (before gross-up for liability in lieu of deferred income taxes) as the additional income taxes are expected tobe recoverable by Oncor in its future revenue rates.117 Table of Contents6. OTHER INCOME AND DEDUCTIONSYear Ended December 31,2012 2011 2010Other income:Office space rental income (a)Consent fee related to novation of hedge positions between counterparties(b)Insurance/litigation settlements (b)Sales tax refundsDebt extinguishment gains (Note 8) (c)Settlement of counterparty bankruptcy claims (b)(d)Property damage claim (b)Franchise tax refund (b)Gain on termination of long-term power sales contract (b)(e)Gain on sale of land/water rights (b)Gain on sale of interest in natural gas gathering pipeline business (b)All otherTotal other incomeOther deductions:Charges related to pension plan actions (Note 13) (f)Impairment of remaining assets from cancelled generation developmentprogram (b)Impairment of mineral interests (Note 3) (b)Other asset impairmentsCounterparty contract settlement (b)Loss on sales of land (b)Net third-party fees paid in connection with the amendment andextension of the TCEH Senior Secured Facilities (Note 8) (g)Impairment of emission allowances (Note 3) (b)(h)Impairment of assets related to mining operations (Note 3) (b)(h)Professional fees incurred related to the Merger (a)Ongoing pension and OPEB expense related to discontinued businesses(a)All otherTotal other deductions$12 $12 $12625512176651,814116443710 16 17$ 30 $ 118 $ 2,051$ 285 $ -$ -35 -24 -11---4 -4 --100-- 418-9--- 510 13 77 13 19$ 380 $ 553 $ 31(a) Reported in Corporate and Other.(b) Reported in Competitive Electric segment.(c) 2010 includes $687 million reported in Competitive Electric segment. All other amounts relate to Corporate and Other.(d) Represents net cash received as a result of the settlement of bankruptcy claims against a hedging/trading counterparty. Areserve of $26 million was established in 2008 related to amounts then due from the counterparty.(e) In November 2010, the counterparty to a long-term power sales agreement terminated the contract, which had a remainingterm of 27 years. The contract was a derivative and subject to mark-to-market accounting. The termination resulted in anoncash gain of $116 million, which represented the derivative liability as of the termination date.(f) Includes $141 million reported in Competitive Electric segment and $144 million reported in Corporate and Other.(g) Includes $86 million reported in Competitive Electric segment and $14 million in Corporate and Other.(h) Charges resulting from the EPA's issuance of the CSAPR in July 2011, including a $418 million impairment charge forexcess emission allowances and $9 million in mining asset write-offs (see Note 3).118 Table of Contents7. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAMIn November 2012, TCEH entered into a new accounts receivable securitization program, and EFH Corp. terminated theprevious program. Upon termination of the program, TXU Energy repurchased receivables previously sold and then sold themto TXU Energy Receivables Company, a new entity that is described below. Except as noted below, the new program is substantiallythe same as the terminated program.Under the program, TXU Energy (originator) sells all of its trade accounts receivable to TXU Energy Receivables Company,which is an entity created for the special purpose of purchasing receivables from the originator and is a consolidated, wholly-owned, bankruptcy-remote subsidiary of TCEH. TXU Energy Receivables Company borrows funds from entities established forthis purpose by the participating financial institutions (funding entities) using the accounts receivable as collateral. A directsubsidiary of EFH Corp. with similar characteristics performed these functions under the terminated program by selling undividedinterests in the purchased accounts receivable to the funding entities.The trade accounts receivable amounts under the program are reported in the financial statements as pledged balances, andthe related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the program activity was accountedfor as a sale of accounts receivable, under accounting rules then applicable to the program, which resulted in the funding beingrecorded as a reduction of accounts receivable.The maximum funding amount currently available under the program is $200 million, which approximates the expectedusage and applies only to receivables related to non-executory retail sales contracts, as compared to $350 million under theterminated program. Program funding decreased to $82 million at December 31, 2012 from $104 million at December 31, 2011.Because TCEH's credit ratings were lower than Ba3/BB-, under the terms of the program available funding is reduced by theamount of customer deposits held by the originator, which totaled $36 million at December 31, 2012.TXU Energy Receivables Company issues a subordinated note payable to the originator for the difference between the faceamount of the accounts receivable purchased, less a discount, and cash paid to the originator. Because the subordinated note islimited to 25% of the uncollected accounts receivable purchased, and the amount of borrowings are limited by terms of the financingagreement, any additional funding to purchase the receivables is sourced from cash on hand and/or capital contributions fromTCEH. Under the program, the subordinated note issued by TXU Energy Receivables Company is subordinated to the securityinterests of the funding entities. There was no subordinated note limit under the terminated program. The balance ofthe subordinatednote payable, which is eliminated in consolidation, totaled $97 million and $420 million at December 31,2012 and December 31,2011, respectively.All new trade receivables under the program generated by the originator are continuously purchased by TXU EnergyReceivables Company with the proceeds from collections of receivables previously purchased and, as necessary, increasedborrowings or funding sources as described immediately above. Changes in the amount ofborrowings by TXU Energy ReceivablesCompany reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such aschanges in sales prices and volumes.The discount from face amount on the purchase of receivables from the originator principally funds program fees paid tothe funding entities. The program fees consist primarily of interest costs on the underlying financing and are reported as interestexpense and related charges. The discount also funds a servicing fee, which is reported as SG&A expense, paid by TXU EnergyReceivables Company to TXU Energy, which provides recordkeeping services and is the collection agent under the program.Program fee amounts were as follows:Year Ended December 31,2012 2011 2010Program fees $ 9 $ 9 $ 10Program fees as a percentage of average funding (annualized) 6.7% 6.4% 3.8%119 Table of ContentsActivities of TXU Energy Receivables Company and TXU Receivables Company were as follows:Cash collections on accounts receivableFace amount of new receivables purchasedDiscount from face amount of purchased receivablesProgram fees paid to funding entitiesServicing fees paid for recordkeeping and collection servicesIncrease (decrease) in subordinated notes payableCapital contribution from TCEH, net of cash heldCash flows used by (provided to) originator under the programYear Ended December 31,2012 2011 2010$ 4,566 S 5,080 $ 6,334(4,496) (4,992) (6,100)11 11 12(9) (9) (10)(2) (2) (2)(323) (96) 53275 --$ 22 $ (8) $ 287Under the previous accounting rules, changes in funding under the program were reported as operating cash flows. Theaccounting rules effective January 1, 2010 required that the amount of funding under the program as of the adoption date ($383million) be reported as a use of operating cash flows and a source of financing cash flows, with all subsequent changes in fundingreported as financing activities.The new program extends the expiration date by two years to November 2015, provided that the expiration date will changeto June 2014 if at that time more than $500 million aggregate principal amount of the term loans and deposit letter of credit loansunder the TCEH Senior Secured Facilities maturing prior to October 2017 remain outstanding. The new program is subject to thesame financial maintenance covenant as the TCEH Senior Credit Facilities as discussed in Note 8. The program may be terminatedupon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the soldreceivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputesand other allowances) or the days outstanding ratio exceed stated thresholds, unless the funding entities waive such events oftermination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXUEnergy Receivables Company defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities,or if EFH Corp., TCEH, any affiliate of TCEH acting as collection agent, any parent guarantor of the originator or the originatordefaults in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for suchentities. At December 31, 2012, there were no such events of termination.If the program was terminated, TCEH's liquidity would be reduced because collections of sold receivables would be usedby TXU Energy Receivables Company to repay borrowings from the funding entities instead of purchasing new receivables. Weexpect that the level of cash flows would normalize in approximately 16 to 30 days following termination.Trade Accounts ReceivableDecember 31,Wholesale and retail trade accounts receivable, including $454 and $524 in pledged retailreceivablesAllowance for uncollectible accountsTrade accounts receivable -reported in balance sheet2012 2011$ 727 $ 794(9) (27)$ 718 $ 767Gross trade accounts receivable at December 31,2012 and 2011 included unbilled revenues of $260 million and $269 million,respectively.120 Table of ContentsAllowance for Uncollectible Accounts ReceivableYear Ended December 31,2012 2011 2010Allowance for uncollectible accounts receivable at beginning of period (a) $ 27 $ 64 $ 81Increase for bad debt expense 26 56 108Decrease for account write-offs (44) (67) (125)Reversal of reserve related to counterparty bankruptcy (Note 6) -(26) --Allowance for uncollectible accounts receivable at end of period $ 9 $ 27 $ 64(a) The beginning balance in 2010 is reduced by $2 million reflecting the deconsolidation of Oncor (see Note 2).121 Table of Contents8. SHORT-TERM BORROWINGS AND LONG-TERM DEBTShort-Term BorrowinesAt December 31, 2012, outstanding short-term borrowings totaled $2.136 billion, which included $2.054 billion under theTCEH Revolving Credit Facility at a weighted average interest rate of 4.40%, excluding customary fees, and $82 million underthe accounts receivable securitization program discussed in Note 7.At December 31, 2011, outstanding short-term borrowings totaled $774 million, which included $670 million under theTCEH Revolving Credit Facility at a weighted average interest rate of 4.46%, excluding certain customary fees, and $104 millionunder the accounts receivable securitization program.Credit FacilitiesCredit facilities with cash borrowing and/or letter of credit availability at December 31, 2012 are presented below. Thefacilities are all senior secured facilities of TCEH.December 31, 2012Maturity Facility Letters of CashFacility Date Limit Credit Borrowings AvailabilityTCEH Revolving Credit Facility (a) October 2013 $ 645 $ -- $ 645 $ -TCEH Revolving Credit Facility (a) October 2016 1,409 -1,409TCEH Letter of Credit Facility (b) October 2017 (b) 1,062 -- 1,062 --Total TCEH $ 3,116 $ -$ 3,116 $ -(a) Facility used for borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. AtDecember 31, 2012, borrowings under the facility maturing October 2013 bear interest at LIBOR plus 3.50%, and acommitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion ofthe facility. At December 31, 2012, borrowings under the facility maturing October 2016 bear interest at LIBOR plus4.50%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 1.00% of the average daily unusedportion of the facility. In January 2013, commitments maturing in 2013 were extended to 2016 as discussed below.(b) Facility, $42 million of which matures in October 2014, used for issuing letters of credit for general corporate purposes,including, but not limited to, providing collateral support under hedging arrangements and other commodity transactionsthat are not secured by a first-lien interest in the assets of TCEH. The borrowings under this facility have been recordedby TCEH as restricted cash that supports issuances of letters of credit and are classified as long-term debt. At December 31,2012, the restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009 related to anoffice building financing. At December 31, 2012, the restricted cash supports $764 million in letters of credit outstanding,leaving $183 million in available letter of credit capacity.Amendment and Extension of TCEH Revolving Credit Facilitv -In January 2013, the Credit Agreement governing theTCEH Senior Secured Facilities was amended to extend the maturity date of the $645 million of commitments maturing in October2013 to October 2016, bringing the maturity date of the entire commitment of $2.054 billion to October 2016. The extendedcommitments will have the same terms and conditions as the existing commitments expiring in October 2016 under the CreditAgreement. Fees in consideration for the extension were settled through the incurrence of $340 million principal amount ofincremental TCEH Term Loan Facilities maturing in October 2017. In connection with the extension request, TCEH eliminatedits ability to draw letters of credit under the TCEH Revolving Credit Facility. At the date of the extension, there were no outstandingletters of credit under the TCEH Revolving Credit Facility.122 Table of ContentsLone-Term DebtAt December 31, 2012 and 2011, long-term debt consisted of the following:EFH Corp. (parent entity)9.75% Fixed Senior Secured First Lien Notes due October 15, 201910% Fixed Senior Secured First Lien Notes due January 15, 202010.875% Fixed Senior Notes due November 1, 2017 (a)11.25 / 12.00% Senior Toggle Notes due November 1, 2017 (a)5.55% Fixed Series P Senior Notes due November 15, 2014 (a)6.50% Fixed Series Q Senior Notes due November 15, 2024 (a)6.55% Fixed Series R Senior Notes due November 15, 2034 (a)8.82% Building Financing due semiannually through February 11, 2022 (b)Unamortized fair value premium related to Building Financing (b)(c)Capital lease obligationsUnamortized premiumUnamortized fair value discount (c)Total EFH Corp.EFIH6.875% Fixed Senior Secured First Lien Notes due August 15, 20179.75% Fixed Senior Secured First Lien Notes due October 15, 201910% Fixed Senior Secured First Lien Notes due December 1, 202011% Fixed Senior Secured Second Lien Notes due October 1, 202111.75% Fixed Senior Secured Second Lien Notes due March 1, 202211.25% / 12.25% Senior Toggle Notes due December 1, 2018Unamortized premiumUnamortized discountTotal EFIHEFCH_9.58% Fixed Notes due in annual installments through December 4, 2019 (d)8.254% Fixed Notes due in quarterly installments through December 31, 2021 (d)1.113% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (e)8.175% Fixed Junior Subordinated Debentures. Series E due January 30, 2037Unamortized fair value discount (c)Total EFCHTCEH_Senior Secured Facilities:3.746% TCEH Term Loan Facilities maturing October 10, 2014 (e)(f)3.712% TCEH Letter of Credit Facility maturing October 10, 2014 (e)4.746% TCEH Term Loan Facilities maturing October 10, 2017 (a)(e)(f)4.712% TCEH Letter of Credit Facility maturing October 10, 2017 (e)11.5% Fixed Senior Secured Notes due October 1, 202015% Fixed Senior Secured Second Lien Notes due April 1, 202115% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B10.25% Fixed Senior Notes due November 1, 2015 (a)10.25% Fixed Senior Notes due November 1, 2015, Series B (a)10.50 / 11.25% Senior Toggle Notes due November 1, 2016December31,2012 2011115 $1,06164609223029153II1151,06119643832674074461146(137) (430)1,840 3,272503141 1412,180 2,180406 4061,7501,304351(131)6,504 2,72735 4139 431 18 8(7) (8)76 853,8094215,3511,0201,7503361,2351,8331,2921,7493,8094215,3511,0201,7503361,2351,8331,2921,568123 Table of ContentsDecember 31,2012 2011Pollution Control Revenue Bonds:Brazos River Authority:5.40% Fixed Series 1994A due May 1, 20297.70% Fixed Series 1999A due April 1, 20336.75% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (g)7.70% Fixed Series 1999C due March 1, 20328.25% Fixed Series 2001A due October 1, 20308.25% Fixed Series 2001D3l due May 1, 20330.143% Floating Series 2001D-2 due May 1, 2033 (h)0.400% Floating Taxable Series 20011 due December 1, 2036 (i)0.143% Floating Series 2002A due May 1, 2037 (h)6.75% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (g)6.30% Fixed Series 2003B due July 1, 20326.75% Fixed Series 2003C due October 1, 20385.40% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (g)5.00% Fixed Series 2006 due March 1, 2041Sabine River Authority of Texas:6.45% Fixed Series 2000A due June 1, 20215.20% Fixed Series 2001C due May 1, 20285.80% Fixed Series 2003A due July 1, 20226.15% Fixed Series 2003B due August 1, 2022Trinity River Authority of Texas:6.25% Fixed Series 2000A due May 1, 2028Unamortized fair value discount related to pollution control revenue bonds (c)Other:7.46% Fixed Secured Facility Bonds with amortizing payments through January 20157% Fixed Senior Notes due March 15, 2013Capital leasesOtherUnamortized discountUnamortized fair value discount (c)Total TCEHTotal EFH Corp. consolidatedLess amount due currentlyTotal long-term debt39111165071171976245443952311005170124539IIl165071171976245443952311005170124514(112)14(120)12564285633 3(10) (11)(1) (1)29,498 29,32337,918 35,407(103) (47)37,815 $ 35,360(a) Excludes the following debt held by EFIH or EFH Corp. (parent entity) and eliminated in consolidation:December3i,EFH Corp. 10.875% Fixed Senior Notes due November 1, 2017EFH Corp. 11.25 / 12.00% Senior Toggle Notes due November 1, 2017EFH Corp. 5.55% Fixed Series P Senior Notes due November 15, 2014EFH Corp. 6.50% Fixed Series Q Senior Notes due November 15, 2024EFH Corp. 6.55% Fixed Series R Senior Notes due November 15, 2034TCEH 4.746% Term Loan Facilities maturing October 10, 2017TCEH 10.25% Fixed Senior Notes due November 1, 2015TCEH 10.25% Fixed Senior Notes due November 1, 2015, Series BTotal2012 2011$ 1,685 $ 1,5913,441 2,784279 45516 6456 319 19213 213150 150.$ 6759 $ 4,811124 Table of Contents(b) This financing is the obligation of a subsidiary of EFH Corp. and will be serviced with cash drawn by the beneficiary of aletter of credit that was previously issued to secure the obligation.(c) Amount represents unamortized fair value adjustments recorded under purchase accounting.(d) EFCH's obligations with respect to these financings are guaranteed by EFH Corp. and secured on a first-priority basis by,among other things, an undivided interest in the Comanche Peak nuclear generation facility.(e) Interest rates in effect at December 31, 2012.(f) Interest rate swapped to fixed on $18.46 billion principal amount of maturities through October 2014 and up to an aggregate$12.6 billion principal amount from October 2014 through October 2017.(g) These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatoryremarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.(h) Interest rates in effect at December 31, 2012. These series are in a daily interest rate mode and are classified as long-termas they are supported by long-term irrevocable letters of credit.(i) Interest rate in effect at December 31, 2012. This series is in a weekly interest rate mode and is classified as long-term asit is supported by long-term irrevocable letters of credit.Debt Amounts Due CurrentlyAmounts due currently (within twelve months) at December 31, 2012 total $103 million and consist of $60 million principalamount of TCEH pollution control revenue bonds (PCRBs) subject to mandatory tender and remarketing in April 2013, which weexpect to repurchase in April 2013, and $43 million of scheduled installment payments on capital leases and debt securities.Debt Related Activity in 2013Issuance of EFIH 10% Notes and EFIH Toggle Notes in Exchange for EFH Corp. and EFIH Debt -In exchanges inJanuary 2013, EFIH and EFIH Finance issued $1.302 billion principal amount of EFIH 10% Senior Secured Notes due 2020 (NewEFIH 10% Notes) for $1.310 billion total principal amount of EFH Corp. and EFIH senior secured notes consisting of: (i) $113million principal amount of EFH Corp. 9.75% Senior Secured Notes due 2019 (EFH Corp. 9.75% Notes), (ii) $1.058 billionprincipal amount of EFH Corp. 10% Senior Secured Notes due 2020 (EFH Corp. 10% Notes), and (iii) $139 million principalamount of EFIH 9.75% Senior Secured Notes due 2019 (EFIH 9.75% Notes). The New EFIH 10% Notes have terms and conditionssubstantially the same as the existing EFIH 10% Notes discussed below. EFIH cancelled the EFIH notes it received in the exchanges.In connection with these debt exchange transactions, EFH Corp. received the requisite consents from holders of the EFHCorp. 9.75% Notes and EFH Corp. 10% Notes and EFIH received the requisite consents from holders of the EFIH 9.75% Notesapplicable to certain amendments to the respective indentures governing such notes. These amendments, among other things, (i)eliminated EFIH's pledge of its 100% ownership of the membership interests it owns in Oncor Holdings as collateral for the EFHCorp. 9.75% Notes, EFH Corp. 10% Notes and EFIH 9.75% Notes, (ii) made EFCH and EFIH unrestricted subsidiaries under theEFH Corp. 9.75% Notes and EFH Corp. 10% Notes, thereby eliminating EFCH's and EFIH's guarantees ofthe notes, (iii) eliminatedsubstantially all of the restrictive covenants in the indentures and (iv) eliminated certain events of default, modified covenantsregarding mergers and consolidations and modified or eliminated certain other provisions in such indentures.In additional exchanges in January 2013, EFIH and EFIH Finance issued $89 million principal amount of additional11.25%/12.25% Toggle Notes due 2018 (EFIH Toggle Notes) for $95 million total principal amount of EFH Corp. senior notesconsisting of: (i) $31 million principal amount of EFH Corp. 10.875% Senior Notes due 2017 (EFH Corp. 10.875% Notes), (ii)$33 million principal amount of EFH Corp. 11.25%/12.00% Senior Toggle Notes due 2017 (EFH Corp. Toggle Notes), (iii) $2million principal amount of EFH Corp. 5.55% Series P Notes due 2014 (EFH Corp. 5.55% Notes) and (iv) $29 million principalamount of EFH Corp. 6.50% Series Q Notes due 2024 (EFH Corp. 6.50% Notes). The additional EFIH Toggle Notes have thesame terms and conditions as the existing EFIH Toggle Notes discussed below.Largely in early 2013, EFIH returned $6.518 billion principal amount of EFH Corp. debt that it received in debt exchanges,including $1.799 billion received in December 2012 and January 2013, as a dividend to EFH Corp., which cancelled it, leaving$1.361 billion principal amount of affiliate debt still held by EFIH. The debt returned included $1.754 billion principal amountof EFH Corp. 10.875% Notes, $3.593 billion principal amount of EFH Corp. Toggle Notes, $1.058 billion principal amount ofEFH Corp. 10% Notes and $113 million principal amount of EFH Corp. 9.75% Notes.125 Table of ContentsDebt Related Activity in 2012Issuances of debt for cash in 2012 consisted of the $503 million principal amount of EFIH 6.875% Senior Secured Notesdue 2017 (net proceeds of $502 million excluding accrued interest received) and $1.750 billion principal amount of EFIH 11.75%Senior Secured Second Lien Notes due 2022 (net proceeds of $1.716 billion net of accrued interest received), as discussed below.Repayments of long-term debt in the year ended December 31, 2012 totaled $41 million and consisted of $26 million ofpayments of principal at scheduled maturity dates and $15 million of contractual payments under capital leases.Issuance of EFIH Toggle Notes in Exchange for EFH Corp. Debt -In exchanges in December 2012, EFIH and EFIHFinance issued $1.304 billion principal amount of EFIH Toggle Notes in exchange for $1.761 billion total principal amount ofEFH Corp. debt consisting of $234 million of EFH Corp. 5.55% Notes, $510 million of EFH Corp. 6.50% Notes, $453 millionof EFH Corp. 6.55% Series R Senior Notes due 2034 (EFH Corp. 6.55% Notes), $132 million of EFH Corp. 10.875% Notes and$432 million of EFH Corp. Toggle Notes.In connection with the debt exchange transactions, EFH Corp. received the requisite consents from holders of the EFH Corp.6.50% Notes and EFH Corp. 6.55% Notes applicable to certain amendments to the respective indentures governing such notes.These amendments, among other things, eliminated substantially all of the restrictive covenants, eliminated certain events ofdefault, modified covenants regarding mergers and consolidations and modified or eliminated certain other provisions in suchindentures, including the limitation on the incurrence of secured indebtedness.Accounting and Income Tax Effects of the December 2012 Debt Exchanges -In consideration of the circumstances andterms of the exchanges, accounting rules require that the gain on the exchanges, which totaled $336 million, be deferred andamortized to interest income over the life of the debt issued. The deferred gain is reported as debt premium associated with theEFIH Toggle Notes.For federal income tax purposes, the transactions resulted in taxable cancellation of debt income of approximately $480million, which was fully offset by utilization of operating loss carryforwards. The transactions resulted in a cash charge underthe Texas margin tax of $3 million (reported as income tax expense).The EFIH Toggle Notes mature in December 2018, with interest payable semiannually on June 1 and December 1 beginningJune 1, 2013 at a fixed rate of 11.25% per annum for cash interest and 12.25% per annum for PIK Interest. For any interest perioduntil June 1, 2016, EFIH may elect to pay interest on the Toggle Notes (i) entirely in cash; (ii) by increasing the principal amountof the notes or by issuing new EFIH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once EFIH makesa PIK election, the election is valid for each succeeding interest payment period until EFIH revokes the election. The interestpayment due on June 1, 2013 will be paid 100% in PIK interest.The indenture governing the EFIH Toggle Notes contains a number of covenants that, among other things, restrict, subjectto certain exceptions, EFIH's and its restricted subsidiaries' ability to:" make restricted payments, including certain investments;" incur debt and issue preferred stock;" create liens;" enter into mergers or consolidations;" sell or otherwise dispose of certain assets, and" engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes when due. If certain events of default occur and are continuing under the notes and the indenture, the trustee or the holdersof at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payableimmediately. Currently, there are no restricted subsidiaries under the indenture (other than EFIH Finance, which has no assets).Oncor Holdings, Oncor and their respective subsidiaries are unrestricted subsidiaries under the EFIH Toggle Notes and the indentureand, accordingly, are not subject to any of the restrictive covenants in the notes and the related indenture.126 Table of ContentsUntil December 1,2014, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of the EFIH Toggle Notes from time to time at a redemption price of 111.25% of the aggregate principal amountof the notes being redeemed, plus accrued interest. EFIH may redeem the notes at any time prior to December 1, 2014 at a priceequal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture governingthe notes. EFIH may also redeem the notes, in whole or in part, at any time on or after December 1, 2014, at specified redemptionprices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture governing the notes), EFIHmust offer to repurchase the notes at 101% of their principal amount, plus accrued interest.The EFIH Toggle Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreedto use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH ToggleNotes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchangefreely tradable notes for the EFIH Toggle Notes. If the registration statement has not been filed and declared effective within 365days after the date the initial EFIH Toggle notes were issued (a Registration Default), the annual interest rate on the notes willincrease by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter, the annualinterest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues.If the Registration Default is cured, the interest rate on the notes will revert to the original level.Issuances ofEFIH6.875% SeniorSecured Notes- In October 2012, EFIH and EFIH Finance issued $253 million principalamount of 6.875% Senior Secured Notes due 2017 (EFIH 6.875% Notes). The offering was issued at a premium of $8 million,which will be amortized to interest expense over the life of the notes. In August 2012, EFIH and EFIH Finance issued $250 millionprincipal amount of EFIH 6.875% Notes and $600 million principal amount of 11.75% Senior Secured Second Lien Notes due2022 (EFIH 11.75% Notes). The EFIH 11.75% Notes are discussed further below. Of the net proceeds from the August 2012issuances, $680 million was placed in escrow (and is reported as restricted cash in the balance sheet) and was issued as a dividendto EFH Corp. in January 2013, and EFH Corp. used the dividend and cash on hand to repay the balance of the demand notespayable by EFH Corp. to TCEH. Remaining proceeds from the August and October 2012 issuances are to be used for generalcorporate purposes.The EFIH 6.875% Notes mature in August 2017, with interest payable in cash semiannually in arrears on February 15 andAugust 15, beginning February 15, 2013, at a fixed rate of 6.875% per annum. The EFIH 6.875% Notes are secured on a first-priority basis by the EFIH Collateral on an equal and ratable basis with the EFIH 10% Notes.The EFIH 6.875% Notes are senior obligations of EFIH and rank equally in right of payment with all senior indebtednessof EFIH and are senior in right ofpayment to any future subordinated indebtedness of EFIH. The EFIH 6.875% Notes are effectivelysenior to all unsecured indebtedness of EFIH, to the extent of the value of the EFIH Collateral, and are effectively subordinatedto any indebtedness of EFIH secured by assets of EFIH other than the EFIH Collateral, to the extent of the value of such assets.Furthermore, the EFIH 6.875% Notes are structurally subordinated to all indebtedness and other liabilities of EFIH's subsidiaries(other than EFIH Finance), including Oncor Holdings and its subsidiaries.The indenture governing the EFIH 6.875% Notes contains a number of covenants that, among other things, restrict, subjectto certain exceptions, EFIH's and its restricted subsidiaries' ability to:* make restricted payments;* incur debt and issue preferred stock;* create liens;* enter into mergers or consolidations;* sell or otherwise dispose of certain assets, and* engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes when due. If certain events of default occur and are continuing under the notes and the indenture, the trustee or the holdersof at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payableimmediately.There currently are no restricted subsidiaries under the indenture related to the EFIH 6.875% Notes (other than EFIH Finance,which has no assets). Oncor Holdings, the immediate parent of Oncor, and its subsidiaries are unrestricted subsidiaries under theindenture and, accordingly, are not subject to any of the restrictive covenants in the indenture.127 Table of ContentsUntil February 15,2015, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of the EFIH 6.875% Notes from time to time at a redemption price of 106.875% of the aggregate principalamount of the notes being redeemed, plus accrued interest. EFIH may redeem the notes at any time prior to February 15, 2015at a price equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenturegoverning the notes. EFIH may also redeem the notes, in whole or in part, at any time on or after February 15, 2015, at specifiedredemption prices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture governing thenotes), EFIH must offer to repurchase the notes at 101% of their principal amount, plus accrued interest.The EFIH 6.875% Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreedto use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFFH 6.875%Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchangefreely tradable notes for the EFIH 6.875% Notes. If the registration statement has not been filed and declared effective within365 days after the date the initial EFIH 6.875% Notes were issued (a Registration Default), the annual interest rate on the noteswill increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter, the annualinterest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues.If the Registration Default is cured, the interest rate on the notes will revert to the original level.Issuances of EFIH 11. 75% Senior Secured Second Lien Notes -In February and August 2012, EFIH and EFIH Financeissued $1.150 billion and $600 million principal amount of EFIH 11.75% Notes, respectively. The February 2012 offerings wereissued at a discount of $12 million, and the August 2012 offering was issued at a premium of $14 million, both of which will beamortized to interest expense over the life of the notes. The net proceeds from the February 2012 issuance were used to pay a$950 million dividend to EFH Corp., and the balance was retained as cash on hand. EFH Corp. used the proceeds from the dividendto repay a portion of the demand notes payable by EFH Corp. to TCEH. TCEH used the majority of the $950 million to repay allborrowings under the TCEH Revolving Credit Facility. Use of proceeds from the August 2012 issuance is discussed above inconnection with the issuance of EFIH 6.875% Notes.The EFIH 11.75% Notes mature in March 2022, with interest payable in cash semiannually in arrears on March 1 andSeptember 1 at a fixed rate of 11.75% per annum. The EFIH 11.75% Notes are secured on a second-priority basis by the EFIHCollateral on an equal and ratable basis with the EFIH 11% Notes. The EFIH 11.75% Notes have substantially the same covenantsas the EFIH 11% Notes, and the holders of the EFIH 11.75% Notes will generally vote as a single class with the holders of theEFIH 11% Notes.Until March 1, 2015, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of the EFIH 11.75% Notes from time to time at a redemption price of 111.750% of the aggregate principal amountof the notes being redeemed, plus accrued interest. EFIH may redeem the notes at any time prior to March 1,2017 at a price equalto 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture governing thenotes. EFIH may also redeem the notes, in whole or in part, at any time on or after March 1, 2017, at specified redemption prices,plus accrued interest. Upon the occurrence of a change of control (as described in the indenture governing the notes), EFIH mustoffer to repurchase the notes at 101% of their principal amount, plus accrued interest.The EFIH 11.75% Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreedto use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH 11.75%Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchangefreely tradable notes for the EFIH 11.75% Notes. Because the exchange offer was not completed by February 5, 2013, the annualinterest rate on the notes increased by 25 basis points and will remain at that level until the earlier of the completion of the exchangeoffer or May 6, 2013. If the exchange offer is not complete by May 6, 2013, the annual interest rate on the notes will increase byan additional 25 basis points (to 12.25%) until the exchange offer is complete. Once the exchange offer is complete, the interestrate on the notes will revert to the original level.128 Table of ContentsDebt Related Activity in 2011Issuances of debt for cash in 2011 consisted of the $1.750 billion principal amount of TCEH 11.5% Senior Secured Notesdiscussed below (net proceeds of $1.703 billion).Repayments of long-term debt in 2011 totaled $1.431 billion and included $958 million of long-term debt borrowings underthe TCEH Senior Secured Facilities as discussed below, $437 million of principal payments at scheduled maturity or remarketingdates (including $415 million of pollution control revenue bonds), $20 million of repurchases ($47 million principal amount asdiscussed below) and $16 million of contractual payments under capitalized lease obligations. In addition, short-term borrowingsof $455 million under the TCEH Revolving Credit Facility were repaid.Amendment and Extension of TCEH Senior Secured Facilities -Borrowings under the TCEH Senior Secured Facilitiestotaled $22.276 billion at December 31, 2012 and consisted of:* $3.809 billion of TCEH Term Loan Facilities maturing in October 2014 with interest payable at LIBOR plus 3.50%;* $15.351 billion of TCEH Term Loan Facilities maturing in October 2017 with interest payable at LIBOR plus 4.50%;* $42 million of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2014 with interest payableat LIBOR plus 3.50% (see discussion under "Credit Facilities" above);* $1.020 billion of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2017 with interest payableat LIBOR plus 4.50% (see discussion under "Credit Facilities" above), and* Amounts borrowed under the TCEH Revolving Credit Facility, which may be reborrowed from time to time until October2016 and represent the entire amount of commitments under the facility totaling $2.054 billion at December 31, 2012.See "Credit Facilities" above for discussion regarding the $645 million in commitments maturing in 2013 that wereextended to 2016 in January 2013.The TCEH Commodity Collateral Posting Facility, under which there were no borrowings in 2012, matured in December2012.In April 2011, (i) the Credit Agreement governing the TCEH Senior Secured Facilities was amended, (ii) the maturity datesof approximately 80% of the borrowings under the term loans (initial term loans and delayed draw term loans) and deposit letterof credit loans under the TCEH Senior Secured Facilities and approximately 70% of the commitments under the TCEH RevolvingCredit Facility were extended, (iii) borrowings totaling $1.604 billion under the TCEH Senior Secured Facilities were repaid fromproceeds of issuance of $1.750 billion principal amount of TCEH 11.5% Senior Secured Notes as discussed below and (iv) theamount of commitments under the TCEH Revolving Credit Facility was reduced by $646 million.The amendment to the Credit Agreement included, among other things, amendments to certain covenants contained in theTCEH Senior Secured Facilities (including the financial maintenance covenant), as well as acknowledgement by the lenders that(i) the terms of the intercompany notes receivable (as described below) from EFH Corp. payable to TCEH complied with theTCEH Senior Secured Facilities, including the requirement that these loans be made on an "arm's-length" basis, and (ii) nomandatory repayments were required to be made by TCEH relating to "excess cash flows," as defined under covenants of theTCEH Senior Secured Facilities, for fiscal years 2008, 2009 and 2010.As amended, the maximum ratios for the secured debt to Adjusted EBITDA financial maintenance covenant are 8.00 to 1.00for test periods through December 31, 2014, and decline over time to 5.50 to 1.00 for the test periods ending March 31, 2017 andthereafter. In addition, (i) up to $1.5 billion principal amount of TCEH senior secured first lien notes (including $906 million ofthe TCEH Senior Secured Notes discussed below), to the extent the proceeds are used to repay term loans and deposit letter ofcredit loans under the TCEH Senior Secured Facilities and (ii) all senior secured second lien debt will be excluded for the purposesof the secured debt to Adjusted EBITDA financial maintenance covenant.129 Table of ContentsThe amendment contained certain provisions related to TCEH Demand Notes that arise from cash loaned for (i) debt principaland interest payments (P&I Note) and (ii) other general corporate purposes of EFH Corp. (SG&A Note). TCEH also agreed inthe Amendment:" not to make any further loans to EFH Corp. under the SG&A Note (at December 31, 2012, the outstanding balance ofthe SG&A Note was $233 million, reflecting the repayment discussed below);" that borrowings outstanding under the P&I Note will not exceed $2.0 billion in the aggregate at any time (at December 31,2012, the outstanding balance of the P&I Note was $465 million), and" that the sum of (i) the outstanding indebtedness (including guarantees) issued by EFH Corp. or any subsidiary of EFHCorp. (including EFIH) secured by a second-priority lien on the equity interests that EFIH owns in Oncor Holdings(EFIH Second-Priority Debt) and (ii) the aggregate outstanding amount of the SG&ANote and P&I Note will not exceed,at any time, the maximum amount of EFIH Second-Priority Debt permitted by the indenture governing the EFH Corp.10% Notes as in effect on April 7, 2011.Further, in connection with the amendment, in April 2011 the following actions were completed related to the intercompanyloans:* EFH Corp. repaid $770 million of borrowings under the SG&A Note (using proceeds from TCEH's repayment of the$770 million TCEH borrowed from EFH Corp. in January 2011 under a demand note), and* EFIH and EFCH guaranteed, on an unsecured basis, the remaining balance of the SG&A Note (consistent with theexisting EFIH and EFCH unsecured guarantees of the P&I Note and the EFH Corp. Senior Notes discussed below).Pursuant to the extension of the TCEH Senior Secured Facilities in April 2011:" the maturity of $15.351 billion principal amount of first lien term loans held by accepting lenders was extended fromOctober 10, 2014 to October 10, 2017 and the interest rate with respect to the extended term loans was increased fromLIBOR plus 3.50% to LIBOR plus 4.50%;" the maturity of S 1.020 billion principal amount of first lien deposit letter of credit loans held by accepting lenders wasextended from October 10, 2014 to October 10, 2017 and the interest rate with respect to the extended deposit letter ofcredit loans was increased from LIBOR plus 3.50% to LIBOR plus 4.50%, and" the maturity of $1.409 billion of the commitments under the TCEH Revolving Credit Facility held by accepting lenderswas extended from October 10, 2013 to October 10, 2016, the interest rate with respect to the extended revolvingcommitments was increased from LIBOR plus 3.50% to LIBOR plus 4.50% and the undrawn fee with respect to suchcommitments was increased from 0.50% to 1.00%.Upon the effectiveness of the extension, TCEH paid an up-front extension fee of 350 basis points on extended term loansand extended deposit letter of credit loans.Each of the loans described above that matures in 2016 or 2017 includes a "springing maturity" provision pursuant to which(i) in the event that more than $500 million aggregate principal amount of the TCEH 10.25% Notes due in 2015 (other than notesheld by EFH Corp. or its controlled affiliates at March 31,2011 to the extent held at the determination date as defined in the CreditAgreement) or more than $150 million aggregate principal amount of the TCEH Toggle Notes due in 2016 (other than notes heldby EFH Corp. or its controlled affiliates at March 31, 2011 to the extent held at the determination date as defined in the CreditAgreement), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (ii) TCEH'stotal debt to Adjusted EBITDA ratio (as defined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at the applicabledetermination date, then the maturity date of the extended loans will automatically change to 90 days prior to the maturity dateof the applicable notes.Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are severaland not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH's available liquidity could be reduced by an amountup to the aggregate amount of such lender's commitments under the TCEH Senior Secured Facilities.130 Table of ContentsThe TCEH Senior Secured Facilities are fully and unconditionally guaranteed jointly and severally on a senior secured basisby EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US subsidiary of TCEH.The TCEH Senior Secured Facilities, along with the TCEH Senior Secured Notes and certain commodity hedging transactionsand the interest rate swaps described under "TCEH Interest Rate Swap Transactions" below, are secured on a first priority basisby (i) substantially all of the current and future assets of TCEH and TCEH's subsidiaries who are guarantors of such facilities and(ii) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.The TCEH Senior Secured Facilities contain customary negative covenants that, among other things, restrict, subject tocertain exceptions, TCEH and its restricted subsidiaries' ability to:* incur additional debt;* create additional liens;" enter into mergers and consolidations;" sell or otherwise dispose of assets;" make dividends, redemptions or other distributions in respect of capital stock;" make acquisitions, investments, loans and advances, and" pay or modify certain subordinated and other material debt.The TCEH Senior Secured Facilities contain certain customary events of default for senior leveraged acquisition financings,the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.Accounting and Income Tax Effects of the Amendment and Extension -Based on application of the accounting rules,including analyses of discounted cash flows, the amendment and extension transactions were determined not to be an extinguishmentof debt. Accordingly, no gain was recognized, and transaction costs totaling $699 million, consisting of consent and extensionpayments to loan holders, were capitalized. Amounts capitalized will be amortized to interest expense through the maturity datesof the respective loans. Net third party fees related to the amendment and extension totaling $100 million were expensed (seeNote 6).The transactions were determined to be a significant modification of debt for federal income tax purposes, resulting in taxablecancellation of debt income of approximately $2.5 billion. The income will be reversed as deductions in future years (through2017), and consequently a deferred tax asset has been recorded. The effect of the income on federal income taxes payable relatedto 2011 was largely offset by current year deductions, including the impact of bonus depreciation, and utilization of approximately$600 million in operating loss carryforwards. The transactions resulted in a cash charge under the Texas margin tax of$13 million(reported as income tax expense).Issuance of TCEH 11.5% Senior Secured Notes -In April 2011, TCEH and TCEH Finance issued $1.750 billion principalamount of 11.5% Senior Secured Notes due 2020, and used the proceeds, net of issuance fees and a $12 million discount, to:" repay $770 million principal amount of term loans under the TCEH Senior Secured Facilities (representing amortizationpayments that otherwise would have been paid from March 2011 through September 2014);" repay $188 million principal amount of deposit letter of credit loans under the TCEH Senior Secured Facilities;" repay $646 million ofborrowings under the TCEH Revolving Credit Facility (with commitments under the facility beingreduced by the same amount), and" fund $99 million of the $799 million of total transaction costs associated with the amendment and extension of theTCEH Senior Secured Facilities discussed above, with the remainder of the transaction costs paid with cash on hand.Issuance of EFIH 11% Senior Secured Second Lien Notes in Exchange for EFH Corp. Debt -In April 2011, EFIH andEFIH Finance issued $406 million principal amount of 11% Senior Secured Second Lien Notes due 2021 in exchange for $428million of EFH Corp. debt consisting of $163 million principal amount of EFH Corp. 10.875% Notes due 2017, $229 millionprincipal amount of EFH Corp. Toggle Notes due 2017 and $36 million principal amount of EF.H Corp. 5.55% Series P SeniorNotes due 2014. The transaction resulted in a debt extinguishment gain of $25 million (reported as other income).131 Table of ContentsIssuance of New EFH Corp. Toggle Notes in Exchange for EFH Corp. Series P Notes -In a private exchange in October2011, EFH Corp. issued $53 million principal amount of new EFH Corp. 11.25%/12.00% Toggle Notes due 2017 in exchange for$65 million principal amount of EFH Corp. 5.55% Series P Senior Notes due 2014 (EFH Corp. 5.55% Notes), which EFH Corp.retired. The new EFH Corp. Toggle Notes have substantially the same terms and conditions and are subject to the same indentureas the existing EFH Corp. Toggle Notes. A premium totaling $6 million was recorded on the transaction and is being amortizedto interest expense over the life of the new notes. Concurrent with the exchange, EFIH returned $53 million principal amount ofEFH Corp. Toggle Notes as a dividend to EFH Corp., which cancelled them. EFIH had previously held the EFH Corp. ToggleNotes as an investment, which was eliminated in consolidation.2011 Debt Repurchases -In the fourth quarter 2011, EFH Corp. repurchased $40 million principal amount ofTCEH 10.25%Notes due 2015 and $7 million principal amount of EFH Corp. 5.55% Notes in private transactions for $20 million in cash. EFHCorp. retired the 5.55% Notes and is holding the TCEH 10.25% Notes as an investment, which is eliminated in consolidation.The transactions resulted in debt extinguishment gains totaling $26 million (reported as other income).MaturitiesLong-term debt maturities at December 31, 2012, excluding amounts held by EFH Corp. and EFIH as a result of debtexchanges and eliminated in consolidation, are as follows (see discussion above regarding transactions in early 2013):Year20132014 (a)201520162017 (a) (b)Thereafter (a)Unamortized premiumsUnamortized discountsCapital lease obligationsTotalEFH Corp.(parent entity) EFIH EFCH TCEH Total$ 7 $ -$ 11 $ 73 $ 9198 -12 3,921 4,0315 -13 3,283 3,3014 -15 1,904 1,923129 503 7 16,027 16,6661,723 5,781 25 4,349 11,87811 351 --362(137) (131) (7) (123) (398)---64 64$ 1,840 $ 6,504 $ 76 $ 29,498 $ 37,918(a) Long-term debt maturities for EFH Corp. (parent entity) total $8.290 billion, consisting of $371 million in 2014, $5.250billion in 2017 and $2.669 billion after 2017, and include $6.377 billion held by EFIH that is not included above.(b) TCEH Senior Secured Facilities due in 2017 are subject to a "springing maturity" provision as discussed above.Information Regarding Other Significant Outstanding DebtTCEH 11.5% Senior Secured Notes -At December 31, 2012, the principal amount of the TCEH 11.5% Senior SecuredNotes totaled $1.750 billion. The notes mature in October 2020, with interest payable in cash quarterly in arrears on January 1,April 1, July 1 and October 1, at a fixed rate of 11.5% per annum. The notes are fully and unconditionally guaranteed on a jointand several basis by EFCH and each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities (collectively, theGuarantors). The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and the guaranteesare secured on a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent suchassets and equity interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), subject to certainexceptions and permitted liens.The notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness of TCEH, (ii) seniorin right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of theTCEH Collateral and (iii) senior in right of payment to any future subordinated debt of TCEH. These notes are effectivelysubordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of thevalue of the assets securing such obligations.The guarantees of the TCEH Senior Secured Notes by the Guarantors are effectively senior to any unsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. The guarantees are effectively subordinated toall debt of the Guarantors secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateralsecuring that debt.132 Table of ContentsThe indenture for the TCEH Senior Secured Notes contains a number of covenants that, among other things, restrict, subjectto certain exceptions, TCEH's and its restricted subsidiaries' ability to:* make restricted payments, including certain investments;* incur debt and issue preferred stock;* create liens;* enter into mergers or consolidations;* sell or otherwise dispose of certain assets, and* engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes when due. If certain events of default occur under the indenture, the trustee or the holders of at least 30% of aggregateprincipal amount of all outstanding TCEH Senior Secured Notes may declare the principal amount on all such notes to be due andpayable immediately.Until April 1, 2014, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of the TCEH Senior Secured Notes from time to time at a redemption price of 111.5% of the aggregate principalamount of the notes being redeemed, plus accrued interest. TCEH may redeem the notes at any time prior to April 1, 2016 at aprice equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. TCEHmay also redeem the notes, in whole or in part, at any time on or after April 1, 2016, at specified redemption prices, plus accruedinterest. Upon the occurrence of a change of control (as described in the indenture), TCEH must offer to repurchase the notes at101% of their principal amount, plus accrued interest.TCEH 15% Senior Secured Second Lien Notes (including Series B) -At December 31, 2012, the principal amount ofthe TCEH 15% Senior Secured Second Lien Notes totaled $1.571 billion. These notes mature in April 2021, with interest payablein cash quarterly in arrears on January 1, April 1, July 1 and October 1 at a fixed rate of 15% per annum. The notes are fully andunconditionally guaranteed on ajoint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH thatguarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by security interests in all ofthe assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of theassets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to theextent such assets and security interests secure obligations under the TCEH Senior Secured Facilities on a first-priority basis,subject to certain exceptions (including the elimination of the pledge of equity interests of any Subsidiary Guarantor to the extentthat separate financial statements would be required to be filed with the SEC for such Subsidiary Guarantor under Rule 3-16 ofRegulation S-X) and permitted liens. The guarantee from EFCH is not secured.The notes are senior obligations of the issuer and rank equally in right of payment with all senior indebtedness of TCEH,are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral(after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinateddebt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, theTCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEHCollateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEHCollateral, and to all secured obligations of TCEH that are secured by assets other than the TCElH Collateral, to the extent of thevalue of the assets securing such obligations.The guarantees of the TCEH Senior Secured Second Lien Notes by the Subsidiary Guarantors are effectively senior to anyunsecured debt of the Subsidiary Guarantors to the extent of the value of theTCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral). These guarantees are effectively subordinated to all debt of the Subsidiary Guarantorssecured by the TCEH Collateral on a first-priority basis or that is secured by assets that are not part of the TCEH Collateral, tothe extent of the value of the collateral securing that debt. EFCH's guarantee ranks equally with its unsecured debt (includingdebt it guarantees on an unsecured basis) and is effectively subordinated to any of its secured debt to the extent of the value of thecollateral securing that debt.133 Table of ContentsThe indenture for the TCEH Senior Secured Second Lien Notes contains a number of covenants that, among other things,restrict, subject to certain exceptions, TCEH's and its restricted subsidiaries' ability to:* make restricted payments, including certain investments;* incur debt and issue preferred stock;* create liens;* enter into mergers or consolidations;* sell or otherwise dispose of certain assets, and* engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes when due. In general, all of the series of TCEH Senior Secured Second Lien Notes vote together as a single class. As aresult, if certain events of default occur under the indenture, the trustee or the holders of at least 30% of aggregate principal amountof all outstanding TCEH Senior Secured Second Lien Notes may declare the principal amount on all such notes to be due andpayable immediately.Until October 1,2013, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of each series of the TCEH Senior Secured Second Lien Notes from time to time at a redemption price of 115.00%of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEH may redeem each series of the notesat any time prior to October 1, 2015 at a price equal to 100% of their principal amount, plus accrued interest and the applicablepremium as defined in the indenture. TCEH may also redeem each series of the notes, in whole or in part, at any time on or afterOctober 1, 2015, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as describedin the indenture), TCEH must offer to repurchase each series of the notes at 101% of their principal amount, plus accrued interest.TCEH 10.25% Senior Notes (including Series B) and 10.50/11.25% Senior Toggle Notes (collectively, the TCEH SeniorNotes) --At December 31, 2012, the principal amount of the TCEH Senior Notes totaled $4.874 billion, excluding $363 millionaggregate principal amount held by EFH Corp. and EFIH, and the notes are fully and unconditionally guaranteed on a joint andseveral unsecured basis by TCEH's direct parent, EFCH (which owns 100% of TCEH), and by each subsidiary that guaranteesthe TCEH Senior Secured Facilities. The TCEH 10.25% Notes mature in November 2015, with interest payable in cash semi-annually in arrears on May 1 and November I at a fixed rate of 10.25% per annum. The TCEH Toggle Notes mature in November2016, with interest payable semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.50% per annum for cashinterest and at a fixed rate of 11.25% per annum for PIK Interest, which option expired with the November 1,2012 interest payment.TCEH may redeem the TCEH 10.25% Notes and TCEH Toggle Notes, in whole or in part, at any time, at specified redemptionprices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFCH or TCEH, TCEH must offerto repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.The indenture for the TCEH Senior Notes contains a number of covenants that, among other things, restrict, subject to certainexceptions, TCEH's and its restricted subsidiaries' ability to:* make restricted payments;* incur debt and issue preferred stock;* create liens;* enter into mergers or consolidations;* sell or otherwise dispose of certain assets, and* engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes when due. If certain events of default occur and are continuing under the indenture, the trustee or the holders of at least30% in principal amount of the notes may declare the principal amount on the notes to be due and payable immediately.134 Table of ContentsEFIH 10% Senior Secured Notes --At December 31, 2012 and January 31, 2013, the principal amount of the EFIH 10%Notes totaled $2.180 billion and $3.482 billion, respectively. The notes mature in December 2020, with interest payable in cashsemiannually in arrears on June 1 and December I at a fixed rate of 10% per annum. The notes are secured by the EFIH Collateralon an equal and ratable basis with the EFIH 6.875% Notes as discussed above.The EFIH 10% Notes are senior obligations of EFIH and rank equally in right of payment with all existing and future seniorindebtedness of EFIH, including the EFIH 6.875% Notes. The EFIH 10% Notes have substantially the same terms, covenantsand events of default as the EFIH 6.875% Notes discussed above.Until December 1,2013, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of the EFIH 10% Notes from time to time at a redemption price of 110% of the aggregate principal amount ofthe notes being redeemed, plus accrued and unpaid interest, if any. EFIH may redeem the EFIH 10% Notes, in whole or in part,at any time prior to December 1, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest, if any,and the applicable premium as defined in the indenture. EFIH may redeem any of the EFIH 10% Notes, in whole or in part, atany time on or after December 1,2015, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrenceof a change of control (as defined in the indenture), EFIH may be required to offer to repurchase the notes at 101% of their principalamount, plus accrued and unpaid interest, if any.EFIH 11% Senior Secured Second Lien Notes -At December 31, 2012, the principal amount of the EFIH 11% Notestotaled $406 million. The notes mature in October 2021, with interest payable in cash semiannually in arrears on May 15 andNovember 15 at a fixed rate of I 1% per annum. The EFIH 11% Notes are secured on a second-priority basis by the EFIH Collateralon an equal and ratable basis with the EFIH 11.75% Notes.The EFIH 11% Notes are senior obligations of EFIH and EFIH Finance and rank equally in right of payment with all seniorindebtedness of EFIH and are effectively senior in right of payment to all existing or future unsecured debt of EFIH to the extentof the value of the EFIH Collateral. The notes have substantially the same terms, covenants and events of default as the EFIH11.75% Notes discussed above.Until May 15, 2014, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of the EFIH 11% Notes from time to time at a redemption price of 111% of the aggregate principal amount ofthe notes being redeemed, plus accrued interest. EFIH may redeem the notes at any time prior to May 15, 2016 at a price equalto 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. EFIH may alsoredeem the notes, in whole or in part, at any time on or after May 15, 2016, at specified redemption prices, plus accrued interest.Upon the occurrence of a change of control (as described in the indenture), EFIH must offer to repurchase the notes at 101% oftheir principal amount, plus accrued interest.EFH Corp. 10.8 75% Senior Notes and 11.25/12.00% Senior Toggle Notes (collectively, EFH Corp. Senior Notes) -AtDecember 31, 2012, the principal amount of the EFH Corp. Senior Notes totaled $124 million, excluding $5.126 billion principalamount held by EFIH. After the exchanges and other transactions in early 2013 described above, the principal amount of the notesoutstanding totals $60 million, none of which was held by EFIH. The notes are fully and unconditionally guaranteed on a jointand several senior unsecured basis by EFCH and EFIH. The notes mature in November 2017, with interest payable in cash semi-annually in arrears on May I and November 1 at a fixed rate for the 10.875% Notes of 10.875% per annum and at a fixed rate forthe Toggle Notes of 11.250% per annum for cash interest and 12.000% per annum for PIK Interest, which option expired with theNovember 1, 2012 interest payment.EFH Corp. may redeem these notes, in whole or in part, at any time, at specified redemption prices, plus accrued and unpaidinterest, if any.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes or the guarantees when due. If an event of default occurs under the indenture, the trustee or the holders of at least 30% inprincipal amount outstanding of the notes may declare the principal amount on the notes to be due and payable immediately.135 Table of ContentsMaterial Cross Default/Acceleration Provisions -Certain of our financing arrangements contain provisions that couldresult in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe othercovenants that could or does result in an acceleration of payments due. Such provisions are referred to as "cross default" or "crossacceleration" provisions.Intercreditor Agreement -TCEH has entered into an intercreditor agreement with Citibank, N.A. and five securedcommodity hedge counterparties (the Secured Commodity Hedge Counterparties). The intercreditor agreement takes into account,among other things, the possibility that TCEH could issue notes and/or loans secured by collateral (other than the collateral thatsecures the TCEH Senior Secured Facilities) that ranks on parity with, or junior to, TCEH's existing first lien obligations underthe TCEH Senior Secured Facilities. The Intercreditor Agreement provides that the lien granted to the Secured Commodity HedgeCounterparties will rank pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH SeniorSecured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will be entitledto share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateralin an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the SecuredCommodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of theIntercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties' lien on such collateral relativeto the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to theSecured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the liengranted to the secured parties under the TCEH Senior Secured Facilities.Second Lien Intercreditor Agreement -TCEH has also entered into a second lien intercreditor agreement (the SecondLien Intercreditor Agreement) with Citibank, N.A., as senior collateral agent, and The Bank of New York Mellon Trust Company,N.A., as initial second priority representative. The Second Lien Intercreditor Agreement provides that liens on the collateral thatsecure the obligations under the TCEH Senior Secured Facilities, the obligations of the Secured Commodity Hedge Counterpartiesand any other obligations which are permitted to be secured on a pari passu basis therewith (collectively, the First Lien Obligations)will rank prior to the liens on such collateral securing the obligations under the TCEH Senior Secured Second Lien Notes, andany other obligations which are permitted to be secured on a pari passu basis (collectively, the Second Lien Obligations). TheSecond Lien Intercreditor Agreement provides that the holders of the First Lien Obligations will be entitled to the proceeds of anyliquidation of such collateral in connection with a foreclosure on such collateral until paid in full, and that the holders of the SecondLien Obligations will not be entitled to receive any such proceeds until the First Lien Obligations have been paid in full. TheSecond Lien Intercreditor Agreement also provides that the holders of the First Lien Obligations will control enforcement actionswith respect to such collateral, and the holders ofthe Second Lien Obligations will not be entitled to commence any such enforcementactions, with limited exceptions. The Second Lien Intercreditor Agreement also provides that releases of the liens on the collateralby the holders of the First Lien Obligations will automatically require that the liens on such collateral by the holders of the SecondLien Obligations be automatically released, and that amendments, waivers or consents with respect to any of the collateraldocuments in connection with the First Lien Obligations apply automatically to any comparable provision of the collateraldocuments in connection with the Second Lien Obligations.Fair Value of Long-Term DebtAt December 31, 2012 and 2011, the estimated fair value of our long-term debt (excluding capital leases) totaled $25.890billion and $23.402 billion, respectively, and the carrying amount totaled $37.854 billion and $35.343 billion, respectively. AtDecember 31, 2012, the estimated fair value of our short-term borrowings under the TCEH Revolving Credit Facilities totaled$1.500 billion and the carrying amount totaled $2.054 billion. We determine fair value in accordance with accounting standardsas discussed in Note 11, and at December 31, 2012, our debt fair value represents Level 2 valuations. We obtain security pricingfrom a vendor who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices arevalidated through subscription services such as Bloomberg.136 Table of ContentsTCEH Interest Rate Swap TransactionsTCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at December 31,2012, TCEH has entered into the following series of interest rate swap transactions that effectively fix the interest rates at between5.5% and 9.3%.Fixed Rates Expiration Dates Notional Amount5.5% -9.3% February 2013 through October 2014 $18.46 billion (a)6.8% -9.0% October 2015 through October 2017 $12.60 billion (b)(a) Swaps related to an aggregate $2.6 billion principal amount of debt expired in 2012. Per the terms of the transactions, thenotional amount of swaps entered into in 2011 grew by $2.405 billion, substantially offsetting the expired swaps.(b) These swaps are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes$3 billion that expires in October 2015 with the remainder expiring in October 2017.TCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achievedthrough the interest rate swaps. Basis swaps in effect at December 31, 2012 totaled $11.967 billion notional amount, a decreaseof $5.783 billion from December 31, 2011 reflecting both new and expired swaps. The basis swaps relate to debt outstandingthrough 2014.The interest rate swap counterparties are secured on an equal and ratable basis by the same collateral package granted to thelenders under the TCEH Senior Secured Facilities.The interest rate swaps have resulted in net losses reported in interest expense and related charges as follows:Year Ended December 31,2012 2011 2010Realized net loss $ (670) $ (684) $ (673)Unrealized net gain (loss) 166 (812) (207)Total $ _ 5041 $ (1,496) $ (880)The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.065 billion and$2.231 billion at December 31, 2012 and 2011, respectively, of which $65 million and $76 million (both pretax), respectively,were reported in accumulated other comprehensive income.137 Table of Contents9. COMMITMENTS AND CONTINGENCIESContractual CommitmentsAt December 31, 2012, we had noncancellable commitments under energy-related contracts, leases and other agreementsas follows:Coal purchaseandtransportationagreements432308292Pipeline Capacity paymentstransportation and under electricitystorage reservation purchase Nuclearfees agreements (a) Fuel Contracts Other Contracts$ 31 $ 99 $ 158 $ 13020132014201520162017ThereafterTotal$2912116167124110432626241234344 --645 119$ 1,242 $ 72 $ 99 $ 1,320 $ 368(a) On the basis of current expectations of demand from electricity customers as compared with capacity and take-or-paypayments, management does not consider it likely that any material payments will become due for electricity not takenbeyond capacity payments.Expenditures under our coal purchase and coal transportation agreements totaled $245 million, $463 million and $445 millionfor the years ended December 31, 2012, 2011 and 2010, respectively.At December 31, 2012, future minimum lease payments under both capital leases and operating leases are as follows:20132014201520162017ThereafterTotal future minimum lease paymentsLess amounts representing interestPresent value of future minimum lease paymentsLess current portionLong-term capital lease obligationCapital OperatingLeases Leases (a)$ 14 $ 4910 477 376 4735 37-17272 $ 3898641252(a) Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.Rent reported as operating costs, fuel costs and SG&A expenses totaled $102 million, $91 million and $89 million for theyears ended December 31, 2012, 2011 and 2010, respectively.138 Table of ContentsGuaranteesWe have entered into contracts that contain guarantees to unaffiliated parties that could require performance or paymentunder certain conditions. Material guarantees are discussed below.Disposed 7XU Gas Company operations -In connection with the sale of the assets of TXU Gas Company to Atmos EnergyCorporation (Atmos) in October 2004, EFH Corp. agreed to indemnify Atmos, until October 1, 2014, for up to $500 million forany liability related to assets retained by TXU Gas Company, including certain inactive gas plant sites not acquired by Atmos,and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximumaggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required tomake any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.See Note 8 for discussion of guarantees and security for certain of our debt.Letters of CreditAt December 31, 2012, TCEH had outstanding letters of credit under its credit facilities totaling $764 million as follows:* $376 million to support risk management and trading margin requirements in the normal course of business, includingover-the-counter hedging transactions and collateral postings with ERCOT;* $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);* $71 million to support TCEH's REP financial requirements with the PUCT, and* $109 million for miscellaneous credit support requirements.Litigation Related to Generation FacilitiesIn November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak GroveManagement Company LLC's (Oak Grove) (a wholly-owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System(TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in theTravis County, Texas District Court. Plaintiffs sought a reversal of the TCEQ's order and a remand back to the TCEQ for furtherproceedings. Oral argument was held in this administrative appeal on October 23, 2012, and the court affirmed the TCEQ'sissuance of the TPDES permit to Oak Grove. In December 2012, plaintiffs appealed the district court's decision to the Third Courtof Appeals in Austin, Texas. While we cannot predict the timing or outcome of this proceeding, we believe the renewal andamendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (TexarkanaDivision) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violationsof the Clean Air Act (CAA) at Luminant's Martin Lake generation facility. In May 2012, the Sierra Club filed a lawsuit in the USDistrict Court for the Western District of Texas (Waco Division) against EFH Corp. and Luminant Generation Company LLC foralleged violations of the CAA at Luminant's Big Brown generation facility. The Big Brown and Martin Lake cases are currentlyscheduled for trial in November 2013. While we are unable to estimate any possible loss or predict the outcome, we believe thatthe Sierra Club's claims are without merit, and we intend to vigorously defend these lawsuits. In addition, in December 2010 andagain in October 2011, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating CAA provisions inconnection with Luminant's Monticello generation facility. In May 2012, the Sierra Club informed us that it may sue us forallegedly violating CAA provisions in connection with Luminant's Sandow 4 generation facility. While we cannot predict whetherthe Sierra Club will actually file suit regarding Monticello or Sandow 4 or the outcome of any resulting proceedings, we believewe have complied with the requirements of the CAA at all of our generation facilities.See below for discussion of litigation regarding the CSAPR and the Texas State Implementation Plan.139 Table of ContentsRegulatory ReviewsIn June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of theCAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, includingNew Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generationfacilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received alarge and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently receiveda notice of violation from the EPA, which has in some cases progressed to litigation or settlement. In July 2012, the EPA sent usa notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our MartinLake and Big Brown generation facilities. While we cannot predict whether the EPA will initiate enforcement proceedings underthe notice of violation, we believe that we have complied with all requirements of the CAA at all of our generation facilities. Wecannot predict the outcome of any resulting enforcement proceedings or estimate the penalties that might be assessed in connectionwith any such proceedings. In September 2012, we filed a petition for review in the United States Court of Appeals for the FifthCircuit Court seeking judicial review of the EPA's notice of violation. Given recent legal precedent subjecting agency orders likethe notice of violation to judicial review, we filed the petition for review to preserve our ability to challenge the EPA's issuanceof the notice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December 2012, the Fifth CircuitCourt issued an order that will delay a ruling on the EPA's motion to dismiss until after the case has been fully briefed and oralargument, if any, is held. We cannot predict the outcome of these proceedings, including the financial effects, if any.Cross-State Air Pollution Rule (CSAPR)In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions ofsulfur dioxide (SO2) and nitrogen oxides (NO.) emissions from our fossil-fueled generation units. In September 2011, we fileda petition for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) challenging the CSAPRas it applies to Texas. If the CSAPR had taken effect, it would have caused us to, among other actions, idle two lignite/coal-fueledgeneration units and cease certain lignite mining operations by the end of 2011.In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR,including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule.In April 2012, we filed in the D.C. Circuit Court a petition for review of the Final Revisions on the ground, among others, thatthe rules do not include all of the budget corrections we requested from the EPA. The parties to the case have agreed that the caseshould be held in abeyance pending the conclusion of the CSAPR rehearing proceeding discussed below. In June 2012, the EPAfinalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPR issued by the EPA inOctober 2011, the Final Revisions and the Second Revised Rule finalize emissions budgets for our generation assets that areapproximately 6% lower for SO2, 3% higher for annual NO, and 2% higher for seasonal NOx.In August 2012, a three judge panel of the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for furtherproceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule do not impose any immediate requirementson us, the State of Texas, or other affected parties. The D.C. Circuit Court's order stated that the EPA was expected to continueadministering the CAIR (the predecessor rule to the CSAPR) pending the EPA's further consideration of the rule. In October2012, the EPA and certain other parties that supported the CSAPR filed petitions with the D.C. Circuit Court seeking review bythe full court of the panel's decision to vacate and remand the CSAPR. In January 2013, the D.C. Circuit Court denied theserequests for rehearing, concluding the CSAPR rehearing proceeding. The EPA and the other parties have approximately 90 daysto appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeals will be filed.State Implementation Plan (SIP)In September 2010, the EPA disapproved a portion of the State Implementation Plan pursuant to which the TCEQ implementsits program to achieve the requirements of the Clean Air Act. The EPA disapproved the Texas standard permit for pollution controlprojects. We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. Wechallenged the EPA's disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) arguingthat the TCEQ's adoption of the standard permit conditions for pollution control projects was consistent with the Clean Air Act.In March 2012, the Fifth Circuit Court vacated the EPA's disapproval of the Texas standard permit for pollution control projectsand remanded the matter to the EPA for reconsideration. We cannot predict the timing or outcome of the EPA's reconsideration,including the financial effects, if any.140 Table of ContentsIn November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacingthat exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generationfacility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicabilityof the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and receivedthe generation facility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the Fifth CircuitCourt arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issuedis consistent with the Clean Air Act. In July 2012, the Fifth Circuit Court denied our challenge and ruled that the EPA's actionswere in accordance with the Clean Air Act. In October 2012, the Fifth Circuit Court panel withdrew its original opinion and issueda new expanded opinion that again upheld the EPA's disapproval. In November 2012, we filed a petition with the Fifth CircuitCourt asking for review by the full Fifth Circuit Court of the panel's new expanded opinion. Other parties to the proceedings alsofiled a petition with the Fifth Circuit Court asking the panel to reconsider its decision. We cannot predict the timing or outcomeof this matter, including the financial effects, if any.Other MattersWe are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutionsof which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity orfinancial condition.Environmental ContingenciesSee discussion above regarding the CSAPR issued by the EPA in July 2011 and revised in February 2012 that includeprovisions which, among other things, place limits on SO2 and NOx emissions produced by electricity generation plants. TheCSAPR provisions and the Mercury and Air Toxics Standard (MATS) issued by the EPA in December 2011, would requiresubstantial additional capital investment in our lignite/coal-fueled generation facilities.We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Webelieve that we are in compliance with current environmental laws and regulations; however, the impact, if any, of changes toexisting regulations or the implementation of new regulations is not determinable and could materially affect our financial condition,results of operations and liquidity.The costs to comply with environmental regulations could be significantly affected by the following external events orconditions:" enactment of state or federal regulations regarding CO2 and other greenhouse gas emissions;" other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances andhazardous and solid wastes, and other environmental matters, including revisions to CAIR currently being developedby the EPA as a result of court rulings discussed above and MATS, and" the identification of sites requiring clean-up or the filing of other complaints in which we may be asserted to be a potentialresponsible party under applicable environmental laws or regulations.Labor ContractsCertain personnel engaged in TCEH activities are represented by labor unions and covered by collective bargainingagreements with varying expiration dates. In November 2011, three-year labor agreements were reached covering bargaining unitpersonnel engaged in lignite-fueled generation operations (excluding Sandow) and lignite mining operations (excluding ThreeOaks). Also in November 2011, a four-year labor agreement was reached covering bargaining unit personnel engaged in naturalgas-fueled generation operations. In October 2010, two-year labor agreements were reached covering bargaining unit personnelengaged in the Sandow lignite-fueled generation operations and the Three Oaks lignite mining operations, and although the termof these agreements have now expired, we are currently negotiating new labor agreements for the Sandow operations and ThreeOaks Mine and are operating under the terms of the existing agreements for these two facilities. In August 2010, a three-yearlabor agreement was reached covering bargaining unit personnel engaged in nuclear-fueled generation operations. We do notexpect any changes in collective bargaining agreements to have a material effect on our results of operations, liquidity or financialcondition.141 Table of ContentsNuclear InsuranceNuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverageand accidental outage and/or extra expense coverage. The liability coverage is governed by the Price-Anderson Act (Act), whilethe property damage, decontamination and premature decommissioning coverage are promulgated by the rules and regulations ofthe NRC. We intend to maintain insurance against nuclear risks as long as such insurance is available. The company is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations,(iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses couldhave a material effect on our financial condition and results of operations and liquidity.With regard to liability coverage, the Act provides financial protection for the public in the event of a significant nucleargeneration plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $12.5 billion andrequires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $12.5 billion limit for a single incident mandated by the Act.As required, the company provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodilyinjury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As thefirst layer of financial protection, the company has $375 million of liability insurance from American Nuclear Insurers (ANI),which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association.The second layer of financial protection is provided under an industry-wide retrospective payment program called SecondaryFinancial Protection (SFP).Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in theUS is subject to an assessment of up to $117.5 million plus a 3% insurance premium tax, subject to increases for inflation everyfive years. Assessments are limited to $17.5 million per operating licensed reactor per year per incident. The company's maximumpotential assessment under the industry retrospective plan would be $235 million (excluding taxes) per incident but no more than$35 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375million per accident at any nuclear facility. The SFP and liability coverage are not subject to any deductibles.With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plantlicense-holders maintain at least $1.06 billion of such insurance and require the proceeds thereof to be used to place a plant in asafe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds canbe used for plant repair or restoration or to provide for premature decommissioning. The company maintains nucleardecontamination and property damage insurance for Comanche Peak in the amount of$2.25 billion (subject to $5 million deductibleper accident), above which the company is self-insured. This insurance coverage consists of a primary layer of coverage of $500million provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company and$1.25 billion of premature decommissioning coverage also provided by NEIL. The European Mutual Association for NuclearInsurance provides additional insurance limits of $500 million in excess of NEIL's $1.75 billion coverage.The company maintains Accidental Outage Insurance through NEIL to cover the additional costs of obtaining replacementelectricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as aresult of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeksand $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The totalmaximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both unitsare out of service at the same time as a result of the same accident.If NEIL's losses exceeded its reserves for the applicable coverage, potential assessments in the form of a retrospectivepremium call could be made up to ten times annual premiums. The company maintains insurance coverage against these potentialretrospective premium calls.Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL wouldmake available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits foreach claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.142 Table of Contents10. EQUITYEquity Issuances and RepurchasesChanges in common stock shares outstanding for each of the last three years are reflected (in millions of shares) in the tablebelow. Essentially all shares issued and purchased were as a result of stock-based compensation transactions for the benefit ofcertain officers, directors and employees. See Note 14 for discussion of stock-based compensation.Year Ended December 31,2012 2011 2010Shares outstanding at beginning of year 1,679.5 1,671.8 1,668.1Shares issued (a) 1.0 7.7 3.9Shares repurchased --(0.1)Shares outstanding at end of year 1,680.5 1,679.5 1,671.8(a) Includes share awards granted to directors and other nonemployees (see Note 14). 2011 and 2010 issuances also included0.2 million and 1.2 million shares of previously issued restricted or deferred stock units that vested in 2011 and 2010,respectively.Dividend RestrictionsEFH Corp. has not declared or paid any dividends since the Merger.The indenture governing the EFH Corp. Senior Notes includes covenants that, among other things and subject to certainexceptions, restrict our ability to pay dividends or make other distributions in respect of our common stock. Accordingly, our netincome is restricted from being used to make distributions on our common stock unless such distributions are expressly permittedunder these indentures and/or on a pro forma basis, after giving effect to such distribution, EFH Corp.'s consolidated leverageratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, "consolidated leverage ratio" is defined as the ratio ofconsolidated total debt (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries otherthan Oncor Holdings and its subsidiaries. EFH Corp.'s consolidated leverage ratio was 10.1 to 1.0 at December 31, 2012.The indentures governing the EFIH Notes generally restrict EFIH from making any cash distribution to EFH Corp. for theultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend,EFIH's consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indentures governing the EFIH Notes, the term"consolidated leverage ratio" is defined as the ratio of EFIH's consolidated total debt (as defined in the indentures) to EFIH'sAdjusted EBITDA on a consolidated basis (including Oncor's Adjusted EBITDA). EFIH's consolidated leverage ratio was 7.0 to1.0 at December 31, 2012. In addition, the EFIH Notes generally restrict EFIH's ability to make distributions or loans to EFHCorp., unless such distributions or loans are expressly permitted under the indentures governing the EFIH Notes.The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companiesfor the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to suchdistribution, TCEH's consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would beequal to or less than 6.5 to 1.0. At December 31, 2012, the ratio was 8.5 to 1.0.In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior SecuredNotes and TCEH Senior Secured Second Lien Notes generally restrict TCEH's ability to make distributions or loans to any of itsparent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior SecuredFacilities and the indentures governing such notes.Under applicable law, we are also prohibited from paying any dividend to the extent that immediately following paymentof such dividend, there would be no statutory surplus or we would be insolvent.143 Table of ContentsCommon Stock Registration RightsThe Sponsor Group and certain other investors entered into a registration rights agreement with EFH Corp. upon closing ofthe Merger. Pursuant to this agreement, in certain instances, the Sponsor Group can cause EFH Corp. to register shares of EFHCorp.'s common stock owned directly or indirectly by them under the Securities Act. In certain instances, the Sponsor Group andcertain other investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.'s common stock underthe Securities Act that it may undertake.See Note 14 for discussion of stock-based compensation plans.Noncontrolling InterestsAt December 31, 2012, ownership of Oncor's membership interests was as follows: 80.03% held indirectly by EFH Corp.,0.22% held indirectly by Oncor's management and board of directors and 19.75% held by Texas Transmission. See Notes 1 and2 for discussion of the deconsolidation of Oncor effective January 1, 2010.As discussed in Note 2, we consolidate a joint venture formed in 2009 for the purpose of developing two new nucleargeneration units, which results in a noncontrolling interests component of equity. Net loss attributable to the noncontrollinginterests was immaterial for the years ended December 31, 2012, 2011 and 2010.144 Table of Contents11. FAIR VALUE MEASUREMENTSAccounting standards related to the determination of fair value define fair value as the price that would be received to sellan asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a"mid-market" valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair valuefor the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the marketapproach for recurring fair value measurements and use valuation techniques to maximize the use ofobservable inputs and minimizethe use of unobservable inputs.We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:Level I valuations use quoted prices in active markets for identical assets or liabilities that are accessible at themeasurement date. An active market is a market in which transactions for the asset or liability occur with sufficientfrequency and volume to provide pricing information on an ongoing basis. Our Level I assets and liabilities includeexchange-traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures andswaps transacted through clearing brokers for which prices are actively quoted.Level 2 valuations use inputs that, in the absence of actively quoted market prices, are observable for the asset or liability,either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets,(b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quotedprices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quotedintervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation orother means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilitiesthat are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes areavailable.Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observableinputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset orliability at the measurement date. We use the most meaningful information available from the market combined withinternally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assetsand liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs tothe valuations, including inputs that are not observable or easily corroborated through other means. See further discussionbelow.Our valuation policies and procedures are developed, maintained and validated by a centralized risk management group thatreports to the Chief Financial Officer, who also functions as the Chief Risk Officer. Risk management functions include valuationmodel validation, risk analytics, risk control, credit risk management and risk reporting.We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on themarket approach of using prices and other market information for identical and/or comparable assets and liabilities for those itemsthat are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationshipsbetween different price curves.In utilizing broker quotes, we attempt to obtain multiple quotes from brokers (generally non-binding) that are active in thecommodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input asobservable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputsvaries depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends andvarious other factors. In addition, for valuation of interest rate swaps, we use generally accepted interest swap valuation modelsutilizing month-end interest rate curves.Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multipleinputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficientamount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significantunobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locationsand credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forward pricecurves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fairvalue measurements resulting from such curves are classified as Level 3.145 Table of ContentsThe significant unobservable inputs and valuation models are developed by employees trained and experienced in marketoperations and fair value measurement and validated by the company's risk management group, which also further analyzes anysignificant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upwardor downward changes in the fair value measurement.With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset orliability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fairvalue measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for theeffects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input tothe fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.Assets and liabilities measured at fair value on a recurring basis consisted of the following:December 31, 2012Level 1 Level 2 Level 3 (a) Reclassification (b) TotalAssets:Commodity contractsInterest rate swapsNuclear decommissioning trust -equity securities (c)Nuclear decommissioning trust -debt securities (c)Total assetsLiabilities:Commodity contractsInterest rate swapsTotal liabilities$ 180 $1,784 $13483 $2,047134249144393-261 --261$ 429 $ 2,323 $ 83 $ -$ 2,835$ 208 $121 $54 $383-2,217 --2,217Lv 208 $ 2,338 $ 54 $ -2,600December 31, 2011Level I Level 2 Level 3 (a) Reclassification (b) TotalAssets:Commodity contractsInterest rate swapsNuclear decommissioning trust -equity securities (c)Nuclear decommissioning trust -debt securities (c)Total assetsLiabilities:Commodity contractsInterest rate swapsTotal liabilities$ 395 $3,915 $142124 $1 $4,435142208124332-242 --242$ 603 $ 4,423 $ 124 $ 1 $ 5,151$ 446 $ 727 $ 71 $ 1 $ 1,245-2,397 --2,397$ 446 $ 3,124 $ 71 $ 1 $ 3,642(a) See table below for description of Level 3 assets and liabilities.(b) Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or viceversa, as presented in the balance sheet.(c) The nuclear decommissioning trust investment is included in the other investments line in the balance sheet. See Note 17.In conjunction with ERCOT's transition to a nodal wholesale market structure effective December 2010, we have enteredinto certain derivative transactions (primarily congestion revenue rights transactions) that are valued at illiquid pricing locations(unobservable inputs), thus requiring classification as Level 3 assets or liabilities.146 Table of ContentsCommodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal derivative instruments enteredinto for hedging purposes and include physical contracts that have not been designated "normal" purchases or sales. See Note 12for further discussion regarding the company's use of derivative instruments.Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debtas well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 8 for discussion of interestrate swaps.Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement anddecommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securitiesconsistent with investment rules established by the NRC and the PUCT.There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31,2012, 2011 and 2010. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfersbetween Level 2 and Level 3 for the years ended December 31, 2012, 2011 and 2010.The following table presents the fair value of the Level 3 assets and liabilities by major contract type (all related to commoditycontracts) and the significant unobservable inputs used in the valuations at December 31, 2012:Fair ValueContract Type Valuation(a) Assets Liabilities Total Technique Significant Unobservable Input Range (b)Electricitypurchases and Valuation $20 to $40/sales $ 5 $ (9) $ (4) Model Illiquid pricing locations (c) MWhHourly price curve shape $20 to $50!(d) MWhElectricity Option Pricingspread options 34 (10) 24 Model Gas to power correlation (e) 20% to 90%Power volatility (f) 20% to 40%Electricity Illiquid price differencescongestion Market between settlement pointsrevenue rights 41 (2) 39 Approach (g) (h) $0.00 to $0.50Coal Market Illiquid price variancespurchases -(32) (32) Approach (g) between mines (i) $0.00 to $1.00Probability of default (j) 5% to 40%Recovery rate (k) 0% to 40%Other 3 (1) 2Total $ 83 $ (5J4 $ 29(a) Electricity purchase and sales contracts include wind generation agreements and hedging positions in the ERCOT westregion, as well as power contracts, the valuations of which include unobservable inputs related to the hourly shaping of theprice curve. Electricity spread options consist of physical electricity call options. Electricity congestion revenue rightscontracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences betweensettlement points within ERCOT. Coal purchase contracts relate to western (Powder River Basin) coal.(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.(c) Based on the historical range of forward average monthly ERCOT West Hub prices.(d) Based on the historical range of forward average hourly ERCOT North Hub prices.(e) Estimate of the historical range based on forward natural gas and on-peak power prices for the ERCOT hubs most relevantto our spread options.(f) Based on historical forward price changes.(g) While we use the market approach, there is either insufficient market data to consider the valuation liquid or the significanceof credit reserves or non-performance risk adjustments results in a Level 3 designation.(h) Based on the historical price differences between settlement points in ERCOT North Hub.(i) Based on the historical range of price variances between mine locations.147 Table of Contents(j) Estimate of the range of probabilities of default based on past experience and the length of the contract as well as our andcounterparties' credit ratings.(k) Estimate of the default recovery rate based on historical corporate rates.The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts)for the years ended December 31, 2012, 2011 and 2010:Net asset balance at beginning of periodTotal unrealized valuation gains (losses)Purchases, issuances and settlements (a):PurchasesIssuancesSettlementsTransfers into Level 3 (b)Transfers out of Level 3 (b)Net change (c)Net asset balance at end of periodUnrealized valuation gains (losses) relating to instruments held at end ofperiodYear Ended December 31,2012 2011 2010$ 53 $ 342 $ 81(17) (1) 26673 117 68(23) (15) (31)(12) (41) (11)(42) -(12)(3) (349) (19)(24) (289) 261$ 29 $ 53 $ 342(24)17111(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases andissuances reflect option premiums paid or received.(b) Includes transfers due to changes in the observability of significant inputs. Transfers in and out occur at the end of eachquarter, which is when the assessments are performed. Transfers out during 2012 reflect increased observability of pricingrelated to certain congestion revenue rights. Transfers in during 2012 were driven by an increase in nonperformance riskadjustments related to certain coal purchase contracts as well as certain power contracts that include unobservable inputsrelated to the hourly shaping of the price curve. Transfers out during 2011 were driven by the effect of an increase in optionmarket trading activity on our natural gas collars for 2014 and increased liquidity in forward periods for coal purchasecontracts for 2014. All Level 3 transfers during the years presented are in and out of Level 2.(c) Substantially all changes in values of commodity contracts are reported in the income statement in net gain from commodityhedging and trading activities, except in 2010, a gain of $116 million on the termination of a long-term power sales contractis reported in other income in the income statement. Activity excludes changes in fair value in the month the position settledas well as amounts related to positions entered into and settled in the same month.148 Table of Contents12. COMMODITY AND OTHER DERIVATIVE CONTRACTUALASSETS AND LIABILITIESStrategic Use of DerivativesWe transact in derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodityprice risk and interest rate risk exposure. Our principal activities involving derivatives consist of a commodity hedging programand the hedging of interest costs on our long-term debt. See Note 11 for a discussion of the fair value of all derivatives.Natural Gas Price Hedging Program -TCEH has a natural gas price hedging program designed to reduce exposure tochanges in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricitysales and related cash flows. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas.Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has soldforward natural gas through 2014. These transactions are intended to hedge a portion of electricity price exposure related toexpected lignite/coal- and nuclear-fueled generation for this period. Unrealized gains and losses arising from changes in the fairvalue of the instruments under the program as well as realized gains and losses upon settlement of the instruments are reported inthe income statement in net gain (loss) from commodity hedging and trading activities.Interest Rate Swap Transactions -Interest rate swap agreements are used to reduce exposure to interest rate changes byconverting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swapsare used to effectively reduce the hedged borrowing costs. Unrealized gains and losses arising from changes in the fair value ofthe swaps as well as realized gains and losses upon settlement of the swaps are reported in the income statement in interest expenseand related charges. See Note 8 for additional information about interest rate swap agreements.Other Commodity Hedging and TradingActivity -In addition to the natural gas price hedging program, TCEH enters intoderivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for shorter-term hedgingpurposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in naturalgas and electricity markets.Financial Statement Effects of DerivativesSubstantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accountingstandards related to derivative instruments and hedging activities. The following tables provide detail of commodity and otherderivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported inthe balance sheets at December 31, 2012 and 2011:December 31, 2012Derivative assets Derivative liabilitiesCommodity Interest rate Commodity Interest ratecontracts swaps contracts swaps TotalCurrent assets $ 1,461 $ 134 $ -$ -$ 1,595Noncurrent assets 586 ---586Current liabilities -(366) (678) (1,044)Noncurrent liabilities --(17) (1,539) (1,556)Net assets (liabilities) $ 2,047 $ 134 $ (383) $ (2,217) $ (419)December 31, 2011Derivative assets Derivative liabilitiesCurrent assetsNoncurrent assetsCurrent liabilitiesNoncurrent liabilitiesNet assets (liabilities)Commodity Interest rate Commodity Interest ratecontracts swaps contracts swaps Total$ 2,883 $ 142 $ -$ -$ 3,0251,552 ---1,552(I) -(1,162) (787) (1,950)--(82) (1,610) (1,692)$ 4,434 $ 142 $ (1,244) $ (2,397) $ 935149 Table of ContentsAt December 31, 2012 and 2011, there were no derivative positions accounted for as cash flow or fair value hedges.Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled$568 million and $1.006 billion in net liabilities at December 31, 2012 and 2011, respectively. Reported amounts as presented inthe above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements.This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positionswith the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantlyfrom period to period.The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealizedeffects:Derivative (income statement presentation)Commodity contracts (Net gain from commodity hedging and tradingactivities) (a)Commodity contracts (Other income) (b)Interest rate swaps (Interest expense and related charges) (c)Net gain (loss)Year Ended December 31,2012 2011 2010$ 279 $ 1,139 $ 2,162--116(503) (1,496) (880)$ (224) $ (357) $ 1,398(a) Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts relatedto positions settled are assumed to equal reversals of previously recorded unrealized amounts.(b) Represents a noncash gain on termination of a long-term power sales contract (see Note 6).(c) Includes unrealized mark-to-market net (gain) loss as well as the net realized effect on interest paid/accrued, both reportedin "Interest Expense and Related Charges" (see Note 17).The following table presents the pretax effect (all losses) on net income and other comprehensive income (OCI) of derivativeinstruments previously accounted for as cash flow hedges. There were no amounts recognized in OCI for the years endedDecember 31, 2012, 2011 or 2010.Derivative type (income statement presentation of loss reclassified from accumulatedOCI into income)Interest rate swaps (interest expense and related charges)Interest rate swaps (depreciation and amortization)Commodity contracts (operating revenues)TotalYear Ended December 31,2012 2011 2010$ (8) $ (27) $ (87)(2) (2) (2)(- -- (9)$ (10) $ (29) $ (90)There were no transactions designated as cash flow hedges during the years ended December 31, 2012, 2011 or 2010.Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedge) atDecember 31, 2012 and 2011 totaled $43 million and $50 million in net losses (after-tax), respectively, substantially all of whichrelates to interest rate swaps. We expect that $6 million of net losses (after-tax) related to cash flow hedges included in accumulatedother comprehensive income at December 31, 2012 will be reclassified into net income during the next twelve months as therelated hedged transactions affect net income.150 Table of ContentsDerivative Volumes-- The following table presents the gross notional amounts of derivative volumes at December 31,2012and 2011:December 31,2012 2011Derivative type Notional Volume Unit of MeasureInterest rate swaps:Floating/fixed (a) $ 32,760 $ 32,955 Million US dollarsBasis (b) $ 11,967 $ 19,167 Million US dollarsNatural gas:Natural gas price hedge forward sales and purchases (c) 875 1,602 Million MMBtuLocational basis swaps 495 728 Million MMBtuAll other 1,549 841 Million MMBtuElectricity 76,767 105,673 GWhCongestion Revenue Rights (d) 111,185 142,301 GWhCoal 13 23 Million tonsFuel oil 47 51 Million gallonsUranium 441 480 Thousand pounds(a) Includes notional amount of interest rate swaps maturing between February 2013 and October 2014 as well as notionalamount of swaps effective from October 2014 with maturity dates through October 2017 (see Note 8).(b) The December 31,2011 amount includes $1.417 billion notional amount ofswaps entered into but not effective until February2012.(c) Represents gross notional forward sales, purchases and options transactions in the natural gas price hedging program. Thenet amount of these transactions was approximately 360 million MMBtu and 700 million MMBtu at December 31, 2012and 2011, respectively.(d) Represents gross forward purchases associated with instruments used to hedge price differences between settlement pointsin the nodal wholesale market design in ERCOT.Credit Risk-Related Contingent Features of DerivativesThe agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent featuresthat could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement.Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies;however, due to our credit ratings being below investment grade, substantially all of such collateral posting requirements arealready effective.At December 31, 2012 and 2011, the fair value of liabilities related to derivative instruments under agreements with creditrisk-related contingent features that were not fully cash collateralized totaled $58 million and $364 million, respectively. Theliquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling$12 million and $78 million at December 31,2012 and 2011, respectively. If all the credit risk-related contingent features relatedto these derivatives had been triggered, including cross default provisions, at December 31,2012 there were no remaining liquidityrequirements, and at December 31, 2011 the remaining related liquidity requirement would have totaled $7 million after reductionfor net accounts receivable and derivative assets under netting arrangements.In addition, certain derivative agreements that are collateralized primarily with liens on certain of our assets includeindebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under otherfinancing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of suchindebtedness. At December 31, 2012 and 2011, the fair value of derivative liabilities subject to such cross-default provisions,largely related to interest rate swaps, totaled $2.299 billion and $2.816 billion, respectively, before consideration of the amountof assets subject to the liens. No cash collateral or letters of credit were posted with these counterparties at December 31, 2012or 2011 to reduce the liquidity exposure. If all the credit risk-related contingent features related to these derivatives, includingamounts related to cross-default provisions, had been triggered at December 31, 2012 and 2011, the remaining related liquidityrequirement after reduction for derivative assets under netting arrangements but before consideration of the amount of assetssubject to the liens would have totaled $1.141 billion and $1.183 billion, respectively. See Note 8 for a description of otherobligations that are supported by liens on certain of our assets.151 Table of ContentsAs discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-relatedcontingent features, including cross-default provisions, totaled $2.357 billion and $3.180 billion at December 31, 2012 and 2011,respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable andderivative assets under netting arrangements and assets subject to related liens.Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amountsto be posted if the features are triggered. These provisions include material adverse change, performance assurance, and otherclauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosedabove exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.Concentrations of Credit Risk Related to DerivativesWe have significant concentrations of credit risk with the counterparties to its derivative contracts. At December 31, 2012,total credit risk exposure to all counterparties related to derivative contracts totaled $2.279 billion (including associated accountsreceivable). The net exposure to those counterparties totaled $255 million at December 31, 2012 after taking into effect nettingarrangements, setoff provisions and collateral. At December 31, 2012, the credit risk exposure to the banking and financial sectorrepresented 93% of the total credit risk exposure and 52% of the net exposure, a significant amount of which is related to thenatural gas price hedging program, and the largest net exposure to a single counterparty totaled $50 million.Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerancebecause all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases therisk that a default by any of these counterparties would have a material effect on our financial condition, results of operations andliquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to postcollateral in the event of a material downgrade in their credit rating.We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorizespecific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positiveand negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit,surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financialcondition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty.The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event ofdefault by one or more counterparties could subsequently result in termination-related settlement payments that reduce availableliquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlementsif the counterparties owe amounts to us.152 Table of Contents13. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANSEFH Corp. is the plan sponsor of the EFH Retirement Plan (the Plan), which provides benefits to eligible employees ofsubsidiaries (participating employers), including Oncor prior to the pension plan actions described immediately below. The Planis a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), andis subject to the provisions of ERISA. The Plan provides benefits to participants under one of two formulas: (i) a Cash BalanceFormula under which participants earn monthly contribution credits based on their compensation and a combination of their ageand years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and theaverage earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and isdetermined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will notapply to prior service costs. Since October 1, 2007, all new employees, with the exception of employees hired by Oncor, havenot been eligible to participate in the Plan. New hires at Oncor have been eligible to participate in the Cash Balance Formula ofthe Plan. It is our policy to fund the Plan to the extent deductible under existing federal tax regulations.In August 2012, EFH Corp. approved certain amendments to the Plan. These actions were completed in the fourth quarter2012, and the amendments resulted in:* splitting off assets and liabilities under the Plan associated with employees of Oncor and all retirees and terminated vestedparticipants of EFH Corp. and its subsidiaries (including discontinued businesses) to a new plan sponsored andadministered by Oncor;* splitting off assets and liabilities under the Plan associated with active employees of EFH Corp.'s competitive businesses,other than collective bargaining unit (union) employees, to a Terminating Plan, freezing benefits and vesting all accruedplan benefits for these participants;* the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities under the TerminatingPlan, and* maintaining assets and liabilities associated with union employees of EFH Corp.'s competitive businesses under the Plan.Settlement of the Terminating Plan obligations and the full funding of the EFH Corp. competitive operations portion ofliabilities (including discontinued businesses) under the Oncor Plan resulted in an aggregate cash contribution by EFH Corp.'scompetitive operations of $259 million in the fourth quarter 2012.EFH Corp.'s competitive operations recorded charges totaling $285 million in the fourth quarter 2012, including $92 millionrelated to the settlement of the Terminating Plan and $193 million related to the competitive business obligations (includingdiscontinued businesses) that are being assumed under the Oncor Plan. These amounts represent the previously unrecognizedactuarial losses reported in accumulated other comprehensive income (loss). TCEH's allocated share of the charges totaled $141million. TCEH settled $91 million of this allocation with EFH Corp. in cash in 2012 and expects to settle the remaining $50million with EFH Corp. in the first quarter 2013.We also have supplemental unfunded retirement plans for certain employees whose retirement benefits cannot fully be earnedunder the qualified Retirement Plan, the information for which is included below.EFH Corp. offers OPEB in the form of health care and life insurance to eligible employees (including Oncor's) and theireligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retireecontributions required for such coverage vary based on a formula depending on the retiree's age and years of service. In 2011,we announced a change to the OPEB plan whereby, effective January 1, 2013, Medicare-eligible retirees from the competitivebusiness will be subject to a cap on increases in subsidies received under the plan to offset medical costs.153 Table of ContentsRegulatory Recovery of Pension and OPEB CostsPURA provides for the recovery by Oncor, in its regulated revenue rates, of pension and OPEB costs applicable to servicesof Oncor's active and retired employees, as well as services of other EFH Corp. active and retired employees prior to the deregulationand disaggregation of our electric utility business effective January 1, 2002. Oncor is authorized to establish a regulatory assetor liability for the difference between the amounts ofpension and OPEB costs reflected in Oncor's approved (by the PUCT) revenuerates and the actual amounts that would otherwise have been recorded as charges or credits to earnings, including amounts relatedto pre-2002 service of EFH Corp. employees. Regulatory assets and liabilities are ultimately subject to PUCT approval.Pension and OPEB CostsPension costs (a)OPEB costsTotal benefit costsLess amounts expensed by Oncor (and not consolidated)Less amounts deferred principally as a regulatory asset or property byOncorNet amounts recognized as expense by EFH Corp. and consolidatedsubsidiariesYear Ended December 31,2012 2011 2010$ 512 $ 141 $ 10025 94 80537 235 180(36) (37) (37)(165) (130) (93)$ 336 $ 68 $ 50(a) As a result of pension plan actions discussed in this Note, 2012 includes $285 million recorded by EFH Corp. as a settlementcharge and $81 million recorded by Oncor as a regulatory asset.At December 31,2012 and 2011, Oncor had recorded regulatory assets totaling $1.010 billion and $884 million, respectively,related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilitiesthat otherwise would be recorded as other comprehensive income.Market-Related Value ofAssets Held in Postretirement Benefit TrustsWe use the calculated value method to determine the market-related value of the assets held in trust. We include the realizedand unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gainsand losses for the current year and for each of the preceding three years is included in the market-related value. Each year, themarket-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit paymentsand expenses for that year.154 Table of ContentsDetailed Information Regarding Pension BenefitsThe following information is based on December 31, 2012, 2011 and 2010 measurement dates (includes amounts related toOncor, except for the pension plan status at December 31, 2012):Year Ended December 31,2012 2011 2010Assumptions Used to Determine Net Periodic Pension Cost:Discount rate (a)Expected return on plan assetsRate of compensation increaseComponents of Net Pension Cost:Service costInterest costExpected return on assetsAmortization of prior service costAmortization of net actuarial lossEffect of pension plan actions (b)Net periodic pension costOther Changes in Plan Assets and Benefit Obligations Recognized in OtherComprehensive Income:Net lossAmortization of net lossEffect of pension plan actions (c)Total loss (income) recognized in other comprehensive incomeTotal recognized in net periodic benefit cost and other comprehensiveincomeAssumptions Used to Determine Benefit Obligations:Discount rateRate of compensation increase5.00%7.40%3.81%$ 44 $157(161)5.50%7.70%3.74%45 $162(157)1905.90%8.00%3.71%42160(160)157106366 --$ 512 $ 141 $ 100$ 57 $(31)54 $(29)27(19)(307) --$ (281) $ 25 $ 8$ 231 $ 166 $ 1084.30% 5.00% 5.50%3.50% 3.81% 3.74%(a) As a result of the amendments discussed above, the discount rate reflected in net pension costs for January through July2012 was 5.00%, for August through September 2012 was 4.15% and for October through December 2012 was 4.20%.(b) Includes settlement charges of $285 million recorded by EFH Corp. and $81 million recorded by Oncor as a regulatory asset.(c) Includes $285 million in actuarial losses reclassified to net income (loss) as a settlement charge and a $22 million plancurtailment adjustment.155 Table of ContentsChange in Pension Obligation:Projected benefit obligation at beginning of yearService costInterest costActuarial lossBenefits paidPlan curtailmentSettlementsPlans sponsored by Oncor (a)Other transfersProjected benefit obligation at end of yearAccumulated benefit obligation at end of yearChange in Plan Assets:Fair value of assets at beginning of yearActual return on assetsEmployer contributionsBenefits paidSettlementsPlans sponsored by OncorFair value of assets at end of yearFunded Status:Projected pension benefit obligationFair value of assetsFunded status at end of year (b)Amounts Recognized in the Balance Sheet Consist of..Other noncurrent assets (c)Other current liabilitiesOther noncurrent liabilitiesNet liability recognizedAmounts Recognized in Accumulated Other Comprehensive Income Consist of:Net lossAmounts Recognized by Oncor as Regulatory Assets Consist of:Net lossPrior service costNet amount recognizedYear Ended December 31,2012 2011$ 3,331 $ 3,07245 46159 165299 181(140) (133)(27)(513)(2,880)11$ 285 $ 3,331$ 258 $ 3,130$ 2,409 $ 2,185297 178369 179(140) (133)(513)(2,271) _$ 151 $ 2,409$ (285) $ (3,331)151 2,409$ (134) $ (922)$ 11 $ 23(2) (5)(143) (940)$ (134) $ (922)$ 2 $ 286$58 $659$ 58 $ 659(a) Amount includes $62 million related to a non-qualified plan.(b) 2012 amount includes $101 million for which Oncor is contractually responsible and is expected to be recovered in Oncor'srates.(c) Amounts represent overfunded plans.156 Table of ContentsThe following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulatedbenefit obligation (ABO) in excess of the fair value of plan assets.December 31,2012 2011Pension Plans with PBO and ABO in Excess Of Plan Assets:Projected benefit obligationsAccumulated benefit obligationPlan assets$ 281 $$ 254 $$ 136 $3,3273,1262,394Pension Plan Investment Strategy and Asset AllocationsOur investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligationsat an acceptable level of risk, while minimizing the volatility of contributions. Considering the pension plan actions discussed inthis Note, the target allocation ranges have shifted to fixed income securities from equities. US equities, international equitiesand fixed income securities were previously in the ranges of 12% to 34%, 10% to 26% and 40% to 70%, respectively. Equitysecurities are held to enhance returns by participating in a wide range of investment opportunities. International equity securitiesare used to further diversify the equity portfolio and may include investments in both developed and emerging international markets.Fixed income securities include primarily corporate bonds from a diversified range of companies, US Treasuries and agencysecurities and money market instruments. Our investment strategy for fixed income investments is to maintain a high gradeportfolio of securities which assist us in managing the volatility and magnitude of plan contributions and expense while maintainingsufficient cash and short-term investments to pay near-term benefits and expenses.The target asset allocation ranges of pension plan investments by asset category are as follows:Asset Category:US equitiesInternational equitiesFixed incomeTargetAllocationRanges8%- 14%6%- 12%74%- 86%Fair Value Measurement of Pension Plan AssetsAt December 31,2012, pension plan assets measured at fair value (see Note 11) on a recurring basis consisted of the following:Asset Category:Interest-bearing cashEquity securities:USInternationalFixed income securities:Corporate bonds (a)US TreasuriesOther (b)Total assetsLevel I Level 2 Level 3 Total$ -$ (4) $ -$ (4)1713544717135447-- 24 -24$ -$ 151 $ -$ 151(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.(b) Other consists primarily of municipal bonds.157 Table of ContentsAt December 31, 2011, pension plan assets measured at fair value on a recurring basis consisted of the following:Asset Category:Interest-bearing cashEquity securities:USInternationalFixed income securities:Corporate bonds (a)US TreasuriesOther (b)Preferred securitiesTotal assetsLevel I Level 2 Level 3 Total$ -$ 94 $ -$ 9441123884784953161,34153961,3415396--14 14$ 649 $ 1,746 $ 14 $ 2,409(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.(b) Other consists primarily of US agency securities.Assets previously classified as Level 3 were transferred to the Oncor Plan at December 31, 2012.Detailed Information Regarding Postretirement Benefits Other Than PensionsThe following OPEB information is based on December 31, 2012, 2011 and 2010 measurement dates (includes amountsrelated to Oncor):Year Ended December 31,2012 2011 2010Assumptions Used to Determine Net Periodic Benefit Cost:Discount rateExpected return on plan assetsComponents of Net Postretirement Benefit Cost:Service costInterest costExpected return on assetsAmortization of net transition obligationAmortization of prior service cost/(credit)Amortization of net actuarial lossNet periodic OPEB costOther Changes in Plan Assets and Benefit Obligations Recognized in OtherComprehensive Income:Prior service creditNet (gain) lossAmortization of net gainAmortization of prior service creditTotal loss recognized in other comprehensive incomeTotal recognized in net periodic benefit cost and other comprehensiveincomeAssumptions Used to Determine Benefit Obligations at Period End:Discount rate4.95%6.80%5.55%7.10%5.90%7.60%$ 9 $ 14 $ 1344 65 61(12) (14) (15)1 1 1(32) (1) (1)15 29 21$ 25 $ 94 $ 80$ -- $17(1)(77) $(15)(2)14(1)11 --$ 27 $ (94) $ 13$ 52 $ -$ 934.10%4.95%5.55%158 Table of ContentsYear Ended December 31,2012 2011Change in Postretirement Benefit Obligation:Benefit obligation at beginning of yearService costInterest costParticipant contributionsMedicare Part D reimbursementPlan amendmentsActuarial (gain) lossBenefits paidBenefit obligation at end of yearChange in Plan Assets:Fair value of assets at beginning of yearActual return on assetsEmployer contributionsParticipant contributionsBenefits paidFair value of assets at end of yearFunded Status:Benefit obligationFair value of assetsFunded status at end of year (a)Amounts Recognized on the Balance Sheet Consist of"Other current liabilitiesOther noncurrent liabilitiesNet liability recognizedAmounts Recognized in Accumulated Other Comprehensive Income Consist of"Prior service creditNet lossNet amount recognizedAmounts Recognized by Oncor as Regulatory Assets Consist of"Net lossPrior service creditNet transition obligationNet amount recognizedS 916 $944171,1911465174 7-- (204)111 (112)(69) (62)$ 1,032 $ 916$ 200 $25181721182617(69) (62)$ 191 $ 200$ (1,032) $ (916)191 200$ (841) $ (716)$ (6) $ (5)(835) (711)$ (841) $ (716)$ (65) $ (77)34 19$ (31) $ (58)$ 246 $(111)178(131)$ 135 $ 48(a) 2012 amount includes $724 million for which Oncor is contractually responsible, substantially all of which is expected tobe recovered in Oncor's rates.159 Table of ContentsThe following tables provide information regarding the assumed health care cost trend rates.December 31,2012 2011Assumed Health Care Cost Trend Rates-Not Medicare EligibleHealth care cost trend rate assumed for next year 8.50% 9.00%Rate to which the cost trend is expected to decline (the ultimate trend rate) 5.00% 5.00%Year that the rate reaches the ultimate trend rate 2022 2022Assumed Health Care Cost Trend Rates-Medicare Eligible:Health care cost trend rate assumed for next year 7.50% 8.00%Rate to which the cost trend is expected to decline (the ultimate trend rate) 5.00% 5.00%Year that the rate reaches the ultimate trend rate 2022 20221-Percentage Point 1-Percentage PointIncrease DecreaseSensitivity Analysis ofAssumed Health Care Cost Trend Rates:Effect on accumulated postretirement obligation $ 117 $ (103)Effect on postretirement benefits cost $ 6 $ (5)OPEB Plan Investment Strategy and Asset AllocationsOur investment objective for the OPEB plan primarily follows the objectives of the Retirement Plan discussed above, whilemaintaining sufficient cash and short-term investments to pay near-term benefits and expenses. The actual amounts at December 31,2012 provided below are consistent with the company's asset allocation targets.Fair Value Measurement of OPEB Plan AssetsAt December 31, 2012, OPEB plan assets measured at fair value on a recurring basis consisted of the following:Asset Category: Level I Level 2 Level 3 TotalInterest-bearing cash $ -$ 10 $ -$ 10Equity securities:US 50 6 -56International 31 --31Fixed income securities:Corporate bonds (a) -42 -42US Treasuries -4 -4Other (b) 45 3 -48Total assets $ 126 $ 65 $ -$ 191(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.(b) Other consists primarily of US agency securities.160 Table of ContentsAt December 31, 2011, OPEB plan assets measured at fair value on a recurring basis consisted of the following:Asset Category:Interest-bearing cashEquity securities:USInternationalFixed income securities:Corporate bonds (a)US TreasuriesOther (b)Preferred securitiesTotal assetsLevel I Level 2 Level 3 Total$ -$ 10 S -$ 10532343572655249552346$- -1 1 1$ 122 $ 77 $ 1 $ 200(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.(b) Other consists primarily of US agency securities.There was no significant change in the fair values of Level 3 assets in the periods presented.Expected Long-Term Rate of Return on Assets AssumptionThe Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes acomprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. Thestudy incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset classreturns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account thediversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.Retirement PlanExpected Long-TermAsset Class: Rate of ReturnUS equity securities 7.7%International equity securities 9.3%Fixed income securities 4.1%Weighted average 5.4%OPEB PlanPlan Type:401(h) accountsLife Insurance VEBAUnion VEBANon-Union VEBAWeighted averageExpected Long-TermReturns7.4%6.4%6.4%3.2%6.7%VEBA refers to Voluntary Employee Beneficiary Association, a form of trust fund permitted under federal tax laws with thesole purpose of providing employee benefits.161 Table of ContentsSignificant Concentrations of RiskThe plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize returnon investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capitalmarket conditions and other factors specific to us. While we recognize the importance of return, investments will be diversifiedin order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are alsovarious restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings forcertain investment securities to assist in the mitigation of the risk of large losses.Assumed Discount RateWe selected the assumed discount rate using the Aon Hewitt AA Above Median yield curve, which is based on corporatebond yields and at December 31, 2012 consisted of 332 corporate bonds with an average rating of AA using Moody's, S&P andFitch ratings.Amortization in 2013We estimate amortization of the net actuarial loss and prior service cost for the defined benefit pension plan from accumulatedother comprehensive income into net periodic benefit cost will be immaterial. We estimate amortization of the net actuarial lossand prior service credit for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will total$30 million and a $31 million credit, respectively.Contributions in 2012 and 2013Our cash contributions in 2012 related to our retirement benefit plans totaled $366 million related to the pension plans, ofwhich $93 million was funded by Oncor, and $18 million related to the OPEB plans, of which $11 million was funded by Oncor.Estimated funding for calendar year 2013 totals $7 million for the pension plans, including amounts related to nonqualified plans,and $18 million for the OPEB plan, with approximately $17 million to be funded by Oncor for pension and OPEB plans.Future Benefit PaymentsEstimated future benefit payments to beneficiaries, including amounts related to nonqualified plans, are as follows:2013 2014 2015 2016 2017 2018-22Pension benefits $ 7 $ 8 $ 10 $ 12 $ 13 $ 91OPEB $ 51 $ 53 $ 56 $ 59 $ 62 $ 336Thrift PlanOur employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed definedcontribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under theterms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highlycompensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% oftheir regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than suchthreshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in anamount equal to 100% of the first 6% of employee contributions for employees who are not covered by the Retirement Plan orwho are covered under the Cash Balance Formula of the Retirement Plan, and 75% of the first 6% of employee contributions foremployees who are covered under the Traditional Retirement Plan Formula of the Retirement Plan. Employer matchingcontributions are made in cash and may be allocated by participants to any of the plan's investment options. Our contributions tothe Thrift Plan totaled $21 million, $20 million and $19 million for the years ended December 31,2012,2011 and 2010, respectively.162 Table of Contents14. STOCK-BASED COMPENSATIONEFH Corp. 2007 Stock Incentive PlanIn December 2007, we established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007SIP). Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFHCorp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferredshares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in wholeor in part by reference to, or are otherwise based on the fair market value of EFH Corp.'s shares of common stock. The 2007 SIPpermits the grant of awards for 72 million shares of common stock, subject to adjustments under applicable laws for certain events,such as a change in control, and no such grants may be issued after December 26, 2017. Shares related to grants that are forfeited,terminated, cancelled, expire unexercised, withheld to satisfy tax withholding obligations, or are repurchased by the Company areavailable for new grants under the 2007 SIP.Stock-based compensation expense recorded for the years ended December 31, 2012, 2011 and 2010 was as follows:Year Ended December 31,Type of award 2012 2011 2010Restricted stock units granted to employees $ 6 $ 3 $ -Stock options granted to employees 5 7 17Other share and share-based awards -3 2Total compensation expense 11 $ 13 $ 19Restricted Stock Units -Restricted stock unit activity in 2012 consisted of grants of 4.1 million units and forfeitures of0.8 million units. Restricted stock unit activity in 2011, consisted of the issuance of 20.5 million units in exchange for stockoptions as discussed below, grants of 4.7 million units and forfeitures of 1.0 million units. Restricted stock units vest as commonstock of EFH Corp, upon the earlier of September 2014 or a change of control, or on a prorated basis upon certain defined eventssuch as termination of employment. Compensation expense per unit is based on the estimated value of EFH Corp. stock at thegrant date, less a marketability discount factor. To determine expense related to units issued in exchange for stock options, theunit value is further reduced by the fair value of the options exchanged. At December 31, 2012, there was approximately $14.5million of unrecognized compensation expense related to nonvested restricted stock units expected to be recognized throughSeptember 2014.Stock Options -No options were granted to employees in 2012 or 2011. Options to purchase 3.8 million shares of EFHCorp. common stock were granted to certain management employees in 2010. Of the options granted in 2010, 1.6 million weregranted in exchange for previously granted options. The exercise period for vested awards was 10 years from grant date. Theoptions initially provided the holder the right to purchase EFH Corp. common stock for $5.00 per share. The terms of the optionswere fixed at grant date. One-half of the options initially granted were to vest solely based upon continued employment over aspecific period of time, generally five years, with the options vesting ratably on an annual basis over the period (Time-BasedOptions). One-half of the options initially granted were to vest based upon both continued employment and the achievement oftargeted five-year EFH Corp. EBITDA levels (Performance-Based Options). Prior to vesting, expenses were recorded if theachievement of the EBITDA levels was probable, and amounts recorded were adjusted or reversed if the probability of achievementof such levels changed. Probability of vesting was evaluated at least each quarter. The stock option expense presented in the tableabove relates to Time-Based Options except for $3 million in 2010 related to Performance-Based Options.In October 2009, in consideration of the then recent economic dislocation and the desire to provide incentives for retention,grantees of Performance-Based Options (excluding named executive officers and a small group of other employees) were providedan offer, which substantially all accepted, to exchange their unvested Performance-Based Options granted under the 2007 SIPwith a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options (Cliff-VestingOptions) with a strike price of $3.50 per share (the then most recent market valuation of each share), with one-half of these optionsto vest in September 2012 and one-half of these options to vest in September 2014. Additionally, certain named executive officersand a small group of other employees were granted an aggregate 3.1 million Cliff-Vesting Options with a strike price of $3.50 pershare, to vest in September 2014, and substantially all of these employees also accepted an offer to exchange half of their unvestedPerformance-Based Options with a strike price of $5.00 per share and a vesting schedule through December 2012 for new time-based stock options with a strike price of $3.50 per share, to vest in September 2014.163 Table of ContentsIn December 2010, in consideration of the desire to enhance retention incentives, EFH Corp. offered employee grantees ofall stock options (excluding named executive officers and a limited number of other employees) the right to exchange their vestedand unvested options for restricted stock units payable in shares (at a ratio of two options for each stock unit). The exchange offerclosed in February 2011, and substantially all eligible employees accepted the offer, which resulted in the issuance of 9.4 millionrestricted stock units in exchange for 16.1 million time-based options (including 5.2 million that were vested) and 2.8 millionperformance-based options (including 2.0 million that were vested).In October 2011, in consideration of the desire to enhance retention incentives, EFH Corp. offered its named executiveofficers and a limited number of other officers the right to exchange their vested and unvested options for restricted stock unitspayable in shares on terms largely consistent with offers made in December 2010 to other employee grantees of stock options.The exchange offer closed in October 2011, and all eligible employees accepted the offer, which resulted in the issuance of 11.1million restricted stock units in exchange for 16.7 million time-based options (including 6.2 million that were vested) and 5.5million performance-based options (including 3.5 million that were vested).The fair value of all options granted was estimated using the Black-Scholes option pricing model and the assumptions notedin the table below. Since EFH Corp. is a private company, expected volatility was based on actual historical experience ofcomparable publicly-traded companies for a term corresponding to the expected life of the options. The expected life representsthe period of time that options granted were expected to be outstanding and was calculated using the simplified method prescribedby the SEC StaffAccounting Bulletin No. 107. The simplified method was used since EFH Corp. did not have stock option historyupon which to base the estimate of the expected life and data for similar companies was not reasonably available. The risk-freerate was based on the US Treasury security with terms equal to the expected life of the option at the grant date.The weighted average grant-date fair value of the Time-Based Options granted in 2010 was $1.16 per option.Assumptions supporting the fair values were as follows:Year EndedDecember 31, 2010Time-BasedAssumptions: OptionsExpected volatility 30% 35%Expected annual dividend --Expected life (in years) 6.1 7.3Risk-free rate 2.69% -3.20%Compensation expense for Time-Based Options is based on the grant-date fair value and recognized over the original vestingperiod as employees perform services. At December 31, 2012, there was no unrecognized compensation expense related tononvested Time-Based Options granted to employees. The exchange of time-based options for restricted stock units was considereda modification of the option award for accounting purposes.164 Table of ContentsA summary of Time-Based Options activity is presented below:Time-Based Options Activity in 2012:Total outstanding at beginning of periodGrantedExercisedForfeitedTotal outstanding at end of period (weighted average remaining term of 5 -10 years)Exercisable at end of period (weighted average remaining term of 5 -10 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 5 -10 years)Time-Based Options Activity in 2011:Total outstanding at beginning of periodGrantedExercisedForfeitedExchangedTotal outstanding at end of period (weighted average remaining term of 6 -10 years)Exercisable at end of period (weighted average remaining term of 6 -10 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 6 -10 years)Time-Based Options Activity in 2010:Total outstanding at beginning of periodGrantedExercisedForfeitedTotal outstanding at end of period (weighted average remaining term of 7 -10 years)Exercisable at end of period (weighted average remaining term of 7 -10 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 7 -10 years)2012WeightedAverageGrant-Options Date Fair OptionsNonvested Time-Based Options Activity: (millions) Value (millions)Total nonvested at beginning of period -$ -23.0Granted -$ --Vested -- --Forfeited -$ -(1.6Exchanged -$ -(21.4Total nonvested at end of period -$ --WeightedOptions Average(millions) Exercise Price1.5 $ 4.67(0.4) $ 4.331.1 $ 4.93(1.1) $ 4.93WeightedOptions Average(millions) Exercise Price37.2 $ 4.31(2.9) $ 4.01(32.8) $ 4.321.5 $ 4.67(1.5) $ 4.67WeightedOptions Average(millions) Exercise Price35.6 $ 4.423.8 $ 3.41(2.2) $ 4.5337.2 $ 4.31(4.8) $ 4.71(0.1) $ 5.0032.3 $ 4.252011 2010Weighted WeightedAverage AverageGrant- Grant-Date Fair Options Date FairValue (millions) ValueI $ 1.59 26.2 $ 1.67-$ -- 3.8 $ 1.16-$ -- (4.8) $ 1.635) $ 1.24 (2.2) $ 1.70,)$ 1.54 -$ --$ -23.0 $ 1.59Compensation expense for Performance-Based Options was based on the grant-date fair value and recognized over therequisite performance and service periods for each tranche of options depending upon the achievement of financial performance.165 Table of ContentsAt December 31,2012, there was no unrecognized compensation expense related to nonvested Performance-Based Optionsbecause the options are no longer expected to vest as a result of exchanges. A total of 4.8 million of the 2008 and 2.0 million ofthe 2009 Performance-Based Options had vested.A summary of Performance-Based Options activity is presented below:Performance-Based Options Activity in 2012:Outstanding at beginning of periodGrantedExercisedForfeitedTotal outstanding at end of period (weighted average remaining term of 5 -7 years)Exercisable at end of period (weighted average remaining term of 5 -7 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 5 -7 years)WeightedOptions Average(millions) Exercise Price1.8 $ 5.00(0.8) $ 5.001.0 $(1.0) $ 5.00WeightedOptions Average(millions) Exercise Price11.1 $ 4.89Performance-Based Options Activity in 2011:Outstanding at beginning of periodGrantedExercisedForfeitedExchangedTotal outstanding at end of period (weighted average remaining term of 6 -8 years)Exercisable at end of period (weighted average remaining term of 6- 8 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 6 -8 years)(1.0) $(8.3) $1.8 $(1.8) $--5.004.895.005.00Performance-Based Options Activity in 2010:Outstanding at beginning of periodGrantedExercisedForfeitedTotal outstanding at end of period (weighted average remaining term of 7 -10 years)Exercisable at end of period (weighted average remaining term of 7 -10 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 7 -10 years)WeightedOptions Average(millions) Exercise Price12.5 $ 4.90(1.4) $ 5.0011.1 $ 4.89(2.0) $ 5.009.1 $ 4.87Performance-Based Nonvested OptionsActivity:Total nonvested at beginning of periodGrantedVestedForfeitedExchangedTotal nonvested at end of period2012 2011 2010Options Grant-Date Options Grant-Date Options Grant-Date(millions) Fair Value (millions) Fair Value (millions) Fair Value0.5 $1.92 -$2.01 4.3 $1.16 -$2.1.1 7.7 $1.16 -$2.11(0.5) $1.92 -$2.01-____ $- -_$ ------ (2.0) $1.62 -$1.871.0) $1.66 -$2.01 (1.4) $1.60 -$1.87((2.8)0.5$1.16 -$2.11$1.92 -$2.014.3$1.16 -$2.11166 Table of ContentsOther Share and Share-BasedAwards -In 2008, we granted 2.4 million deferred share awards, each of which representsthe right to receive one share of EFH Corp. stock, to certain management employees who agreed to forego share-based awardsthat vested at the Merger date. The deferred share awards are fully vested and are payable in cash or stock upon the earlier of achange of control or separation of service. An additional 1.2 million deferred share awards were granted to certain managementemployees in 2008, approximately half of which are payable in cash or stock and the balance payable in stock; all of these awardshave since vested or have been surrendered upon termination of employment. No expense was recognized in 2012. Expensesrecognized in 2011 and 2010 related to these grants totaled $0.1 million and $0.4 million, respectively. Deferred share awardsthat are payable in cash or stock are accounted for as liability awards; therefore, the effects of changes in the estimated value ofEFH Corp. shares are recognized in earnings. As a result of the decline in estimated value of EFH Corp. shares, share-basedcompensation expense in 2012, 2011 and 2010 was reduced by $1.0 million, $3.5 million and $3.3 million, respectively.Directors and other nonemployees were granted 1.0 million shares of EFH Corp. stock in 2012, 7.5 million shares in 2011and 2.7 million shares in 2010. The shares vest over periods of one to two years, and a portion may be settled in cash. Expenserecognized in 2012, 2011 and 2010 related to these grants totaled $1.3 million, $6.8 million and $4.7 million, respectively.In addition, options to purchase 5.0 million shares of EFH Corp. common stock were granted to a director in 2012. Theoptions provide the holder the right to purchase EFH Corp. common stock for $0.50 per share. At December 31, 2012, there wasapproximately $0.7 million of unrecognized compensation expense related to these options which is expected to be recognizedratably over a remaining weighted-average period of approximately one to three years.167 Table of Contents15. RELATED PARTY TRANSACTIONSThe following represent our significant related-party transactions.* We pay an annual management fee under the terms of a management agreement with the Sponsor Group, which wereported in SG&A expense totaling $38 million, $37 million and $37 million for the years ended December 31, 2012,2011 and 2010, respectively.In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders.These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of eachmember ofthe Sponsor Group have from time to time engaged in commercial banking transactions with us and/orprovidedfinancial advisory services to us, in each case in the normal course of business.In January 2013, fees paid to Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners for services relatedto debt exchanges totaled $2 million, described as follows: (i) Goldman acted as a dealer manager for the offers by EFIHand EFIH Finance to exchange new EFIH 10% Notes for EFH Corp. 9.75% Notes, EFH Corp. 10% Notes and EFIH9.75% Notes (collectively, the Old Notes) and as a solicitation agent in the solicitation of consents by EFH Corp. andEFIH and EFIH Finance to amendments to the Old Notes and indentures governing the Old Notes and (ii) Goldman actedas a dealer manager for the offers by EFIH and EFIH Finance to exchange EFIH Toggle Notes for EFH Corp. 10.875%Notes and EFH Corp. Toggle Notes. See Note 8 for further discussion of these exchange offers.For the year ended December 31, 2012, fees paid to Goldman related to debt issuances totaled $10 million, described asfollows: (i) Goldman acted as a joint book-running manager and initial purchaser in the February 2012 issuance of $1.15billion principal amount of EFIH 11.750% Senior Secured Second Lien Notes (see Note 8) for which it received feestotaling $7 million, and (ii) Goldman acted as joint book-running manager and initial purchaser in the August 2012issuance of $600 million principal amount of 11.750% Senior Secured Second Lien Notes and $250 million principalamount of EFIH 6.875% Senior Secured Notes (see Note 8) for which it received fees totaling $3 million. In the October2012 issuance of $253 million principal amount of EFIH 6.875% Notes, Goldman acted as joint book-running managerand initial purchaser for which it was paid $1 million. A broker-dealer affiliate of KKR served as a co-manager and initialpurchaser and an affiliate of TPG served as an adviser in all of these transactions, for which they each received a total of$4 million.For the year ended December 31, 2011, fees paid to Goldman related to debt issuances, exchanges, amendments andextensions totaled $26 million, described as follows: (i) Goldman acted as a joint lead arranger and joint book-runnerin the April 2011 amendment and extension of the TCEH Senior Secured Facilities (see Note 8) and received fees totaling$17 million and (ii) Goldman acted as ajoint book-running manager and initial purchaser in the issuance of $1.750 billionprincipal amount of TCEH Senior Secured Notes as part of the April 2011 amendment and extension and received feestotaling $9 million. Affiliates of KKR and TPG served as advisers to these transactions, and each received $5 million ascompensation for their services.For the year ended December 31, 2010, fees paid to Goldman related to debt issuances and exchanges totaled $11 million,described as follows: (i) Goldman acted as an initial purchaser in the issuance of $500 million principal amount of EFHCorp. 10% Notes in January 2010 for which it received fees totaling $3 million; (ii) Goldman acted as a dealer managerand solicitation agent in EFH Corp. and EFIH debt exchange offers completed in August 2010 for which it received feestotaling $7 million; (iii) Goldman also acted as an initial purchaser in the issuance of $350 million principal amount ofTCEH 15% Senior Secured Second Lien Notes (Series B) in October 2010 and received fees totaling $1 million." Affiliates of GS Capital Partners are parties to certain commodity and interest rate hedging transactions with us in thenormal course of business." Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issuedby us in open market transactions or through loan syndications.168 Table of ContentsTCEH has made loans to EFH Corp. in the form of demand notes (TCEH Demand Notes) that have been pledged ascollateral under the TCEH Senior Secured Facilities for (i) debt principal and interest payments and (ii) other generalcorporate purposes (SG&A Note) for EFH Corp. The TCEH Demand Notes are eliminated in consolidation in theseconsolidated financial statements. The TCEH Demand Notes totaled $698 million and $1.592 billion at December 31,2012 and 2011, respectively, including $233 million in the SG&A Note at both dates. The reduction of the balance ofthe TCEH Demand Notes for the year ended December 31, 2012 was funded by debt issued by EFIH. EFH Corp. settledthe balance of the TCEH Demand Notes in January 2013. See Note 8 for additional discussion.As part of EFH Corp.'s liability management program, EFH Corp. (parent entity) and EFIH have purchased, or receivedin exchanges, certain debt securities of EFH Corp. and TCEH, which they have held. Principal and interest paymentsreceived by EFH Corp. and EFIH on these investments have been used, in part, to service their outstanding debt. Theseinvestments are eliminated in consolidation in these consolidated financial statements. At December 31, 2012, EFIHheld $6.377 billion principal amount of EFH Corp. debt and $79 million principal amount ofTCEH debt. At December 31,2012, EFH Corp. held $303 million principal amount of TCEH debt. After the transactions in early 2013 discussed inNote 8, including EFIH's distribution of EFH Corp. debt as a dividend to EFH Corp., EFIH held $1.361 billion principalamount of affiliate debt.TCEH's retail operations pay Oncor for services it provides, principally the delivery of electricity. Expenses recordedfor these services totaled $1.0 billion, $1.0 billion and $1.1 billion for the years ended December 31, 2012, 2011 and2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets atDecember 31, 2012 and 2011 reflect amounts due currently to Oncor totaling $53 million and $138 million, respectively(included in payables due to unconsolidated subsidiary), primarily related to these electricity delivery fees.In August 2012, TCEH and Oncor agreed to settle at a discount two agreements related to securitization (transition) bondsissued by Oncor's bankruptcy-remote financing subsidiary in 2003 and 2004 to recover generation-related regulatoryassets. Under the agreements, TCEH had been reimbursing Oncor as described immediately below. Under the settlement,TCEH paid, and Oncor received, $159 million in cash. The settlement was executed by EFIH acquiring the right toreimbursement under the agreements from Oncor and then selling these rights for the same amount to TCEH. Thetransaction resulted in a $2 million (after tax) decrease in investment in unconsolidated subsidiary in accordance withaccounting rules for related party transactions.Oncor collects transition surcharges from its customers to recover the transition bond payment obligations. Oncor'sincremental income taxes related to the transition surcharges it collects had been reimbursed by TCEH quarterly undera noninterest bearing note payable to Oncor that was to mature in 2016. The note balance at the August 2012 settlementdate totaled $159 million. TCEH's payments on the note totaled $20 million, $39 million and $37 million for the yearsended December 31, 2012, 2011 and 2010, respectively.Under an interest reimbursement agreement, TCEH had reimbursed Oncor on a monthly basis for interest expense onthe transition bonds. The remaining interest to be paid through 2016 under the agreement totaled $53 million at theAugust 2012 settlement date. Only the monthly accrual of interest under this agreement was reported as a liability. Thisinterest expense totaled $16 million, $32 million and $37 million for the years ended December 31,2012, 2011 and 2010,respectively." Oncor pays EFH Corp. subsidiaries for financial and other administrative services and shared facilities at cost. Suchamounts reduced reported SG&A expense by $35 million, $38 million and $40 million and for the years endedDecember 31, 2012, 2011 and 2010, respectively." Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facilityis funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to TCEH forcontribution to the trust fund with the intent that the trust fund assets, reported in other investments in our balance sheet,will ultimately be sufficient to fund the actual future decommissioning liability, reported in noncurrent liabilities in ourbalance sheet. The delivery fee surcharges remitted to TCEH totaled $16 million, $17 million and $16 million for theyears ended December 31, 2012, 2011 and 2010, respectively. Income and expenses associated with the trust fund andthe decommissioning liability incurred by TCEH are offset by a net change in a receivable/payable that ultimately willbe settled through changes in Oncor's delivery fee rates. At December 31, 2012 and 2011, the excess of the trust fundbalance over the decommissioning liability resulted in a payable totaling $284 million and $225 million, respectively,included in noncurrent liabilities.169 Table of Contents" We file a consolidated federal income tax return that includes Oncor Holdings' results. Oncor is not a member of ourconsolidated tax group, but our consolidated federal income tax return includes our portion of Oncor's results due to ourequity ownership in Oncor. We also file a consolidated Texas state margin tax return that includes all of Oncor Holdings'and Oncor's results. However, under a tax sharing agreement, Oncor Holdings' and Oncor's federal income tax and Texasmargin tax expense and related balance sheet amounts, including our income taxes payable to or receivable from OncorHoldings and Oncor, are recorded as if Oncor Holdings and Oncor file their own corporate income tax returns. Ourcurrent amount receivable from Oncor Holdings and Oncor related to income taxes totaled $34 million and $2 millionat December 31,2012 and 2011, respectively. EFH Corp. received income tax payments from Oncor Holdings and Oncortotaling $35 million for the year ended December 31, 2012, issued net income tax refunds to Oncor Holdings and Oncortotaling $89 million (net of $20 million in tax payments from Oncor Holdings) for the year ended December 31, 2011and received income tax payments from Oncor Holdings and Oncor totaling $107 million for the year ended December 31,2010." Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of anyREP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility.Under these tariffs, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateralsupport in an amount equal to estimated transition charges over specified time periods. Accordingly, at December 31,2012 and 2011, TCEH had posted letters of credit in the amount of $11 million and $12 million, respectively, for thebenefit of Oncor." As a result of the pension plan actions discussed in Note 13, in December 2012, Oncor became the sponsor of a newpension plan (the Oncor Plan), the participants in which consist of all of Oncor's active employees and all retirees andterminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Oncor hadpreviously contractually agreed to assume responsibility for pension and OPEB liabilities that are recoverable by Oncorunder regulatory rate-setting provisions. As part of the pension plan actions, EFH Corp. fully funded the nonrecoverablepension liabilities under the Oncor Plan. After the pension plan actions, the remaining participants in the EFH Corp.pension plan consist of active employees under collective bargaining agreements (union employees). Oncor continuesto be responsible for the recoverable portion of pension obligations to these union employees. EFH Corp. is the sponsorof the OPEB plan and remains liable for the majority of the OPEB plan obligations. Accordingly, EFH Corp.'s balancesheet reflects unfunded pension and OPEB liabilities related to plans that it sponsors, including recoverable andnonrecoverable amounts, but also reflects a receivable from Oncor for that portion of the unfunded liabilities for whichOncor is contractually responsible, substantially all ofwhich is expected to be recovered in Oncor's rates. At December 3 1,2012 and 2011, the receivable amounts totaled $825 million and $1.235 billion, respectively, classified as noncurrent.Under ERISA, EFH Corp. and Oncor remain jointly and severally liable for the funding of the EFH Corp. and Oncorpension plans. We view the risk of the retained liability under ERISA related to the Oncor Plan to be not significant." Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstandingissues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter ofcredit in an amount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred,two or more rating agencies downgrade Oncor's credit rating below investment grade.16. SEGMENT INFORMATIONOur operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. Thesegments are managed separately because they are strategic business units that offer different products or services and involvedifferent risks.The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesaleenergy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and businesscustomers, all largely in Texas. These activities are conducted by TCEH.The Regulated Delivery segment consists largely of our investment in Oncor. Oncor is engaged in regulated electricitytransmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary. See Note 2 for discussion of the reporting of Oncor Holdings and, accordingly, the Regulated Deliverysegment, as an equity method investment. See Note 15 for discussion of material transactions with Oncor, including payment toOncor of electricity delivery fees, which are based on rates regulated by the PUCT.170 Table of ContentsCorporate and Other represents the remaining nonsegment operations consisting primarily of discontinued businesses,general corporate expenses and interest on EFH Corp. (parent entity), EFIH and EFCH debt.The accounting policies of the business segments are the same as those described in the summary of significant accountingpolicies in Note 1. We evaluate performance based on net income (loss). We account for intersegment sales and transfers as ifthe sales or transfers were to third parties, that is, at current market prices or regulated rates.Operating revenues (all Competitive Electric)Depreciation and amortizationCompetitive ElectricCorp. and OtherConsolidatedEquity in earnings of unconsolidated subsidiaries (net of tax) (all RegulatedDelivery)Interest incomeCompetitive ElectricCorp. and OtherEliminationsConsolidatedInterest expense and related chargesCompetitive ElectricCorp. and OtherEliminationsConsolidatedIncome tax expense (benefit)Competitive ElectricCorp. and OtherConsolidatedNet income (loss):Competitive ElectricRegulated DeliveryCorp. and OtherConsolidatedInvestment in equity investeesCompetitive ElectricRegulated DeliveryConsolidatedTotal assetsCompetitive ElectricRegulated DeliveryCorp. and OtherEliminationsConsolidatedCapital expendituresCompetitive ElectricCorp. and OtherConsolidatedYear Ended December 31,2012 2011 2010$ 5,636 $ 7,040 $ 8,235$ 1,344 $ 1,471 $ 1,38029 28 27$ 1,373 $ 1,499 $ 1,407$ 270 $ 286 $ 277$ 46 $ 87 $ 91143 139 151(187) (224) (232)$ 2 $ 2 $ 10$ 2,892 $ 3,830 $ 2,957803 688 829(187) (224) (232)$ 3,508 $ 4,294 $ 3,554$ (954) $ (963) $ 359(278) (171) 30$ (1,232) $ (1,134) $ 389$ (3,063) $ (1,825) $ (3,463)270 286 277(567) (374) 374$ (3,360) $ (1,913) $ (2,812)$ 8$ -$ -5,842 5,720 5,544$ 5,850 $ 5,720 $ 5,544$ 33,002 $ 37,409 $ 39,2025,842 5,720 5,5444,861 4,394 5,045(2,735) (3,446) (3,403)$ 40,970 $ 44,077 $ 46,388$ 630 $529 $79634 23 42$ 664 $ 552 $ 838171 Table of Contents17. SUPPLEMENTARY FINANCIAL INFORMATIONInterest Expense and Related ChargesYear Ended December 31,2012 2011 2010Interest paid/accrued (including net amounts settled/accrued under interestrate swaps) 3,269 $ 3,027 $ 2,681Accrued interest to be paid with additional toggle notes (Note 8) 209 219 446Unrealized mark-to-market net (gain) loss on interest rate swaps (a) (172) 812 207Amortization of interest rate swap losses at dedesignation of hedgeaccounting 8 27 87Amortization of fair value debt discounts resulting from purchaseaccounting 44 52 63Amortization of debt issuance, amendment and extension costs anddiscounts 186 188 130Capitalized interest (36) (31) (60)Total interest expense and related charges $ 3,508 $ 4,294 $ 3,554(a) Year ended December 31, 2012 amount includes net gains totaling $166 million related to TCEH swaps (see Note 8) andnet gains totaling $6 million related to EFH Corp. swaps substantially closed through offsetting positions.Restricted CashAmounts in escrow to settle TCEH Demand Notes (Notes8 and 15)Amounts related to margin deposits heldAmounts related to TCEH's Letter of Credit Facility (Note8)Total restricted cashDecember 31, 2012 December 31, 2011Noncurrent NoncurrentCurrent Assets Assets Current Assets Assets$ 680 $ -$ -$ ---129 --947 -947$ 680 $ 947 $ 129 $ 947Inventories by Major CategoryMaterials and suppliesFuel stockNatural gas in storageTotal inventoriesDecember 31,2012 2011$ 201 $ 177168 20324 38$ 393 $ 418172 Table of ContentsOther InvestmentsDecember 31,2012 20115; 654 $ 574Nuclear plant decommissioning trustAssets related to employee benefit plans, including employee savings programs, net ofdistributionsLandMiscellaneous otherTotal other investments704190412 4767 $ 709Nuclear Decommissioning Trust- Investments in a trust that will be used to fund the costs to decommission the ComanchePeak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as adelivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trustfund are offset by a corresponding change in a receivable/payable that will ultimately be settled through changes in Oncor's deliveryfees rates (see Note 15). A summary of investments in the fund follows:December 31, 2012Debt securities (b)Equity securities (c)TotalFair marketCost (a) Unrealized gain Unrealized loss value$ 246$ 16 $ (1) $ 261245 161 (13) 393$ 491 $ 177 $ (14) $ 654December 31,2011Debt securities (b)Equity securities (c)TotalFair marketCost (a) Unrealized gain Unrealized loss value$ 231 $ 13 $ (2) $ 242230 121 (19) 332$ 461 $ 134 $ (21) $ 574(a) Includes realized gains and losses on securities sold.(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio ratingof AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with municipal bonds. Thedebt securities had an average coupon rate of 4.38% at both December 31, 2012 and 2011, and an average maturity of 6years at both December 31, 2012 and 2011.(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.Debt securities held at December 31, 2012 mature as follows: $94 million in one to five years, $55 million in five to tenyears and $112 million after ten years.The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and lossesfrom such sales.Realized gainsRealized lossesProceeds from sales of securitiesInvestments in securitiesYear Ended December 31,2012 2011 2010$ 1$ 1 $ 1$ (2) $ (3) $ (2)$ 106 $ 2,419 $ 974$ (122) $ (2,436) $ (990)173 Table of ContentsProperty, Plant and EquipmentCompetitive Electric:Generation and miningNuclear fuel (net of accumulated amortization of $941 and $776)Other assetsCorporate and OtherTotalLess accumulated depreciationNet of accumulated depreciationConstruction work in progress:Competitive ElectricCorporate and OtherTotal construction work in progressProperty, plant and equipment -netDecember 31,2012 2011$ 23,564 $ 23,006361 32035 41217 21224,177 23,5795,937 4,80318,240 18,77644464221 9465 651$ 18,705 $ 19,427Depreciation expense totaled $1.247 billion, $1.345 billion and $1.255 billion for the years ended December 31, 2012, 2011and 2010, respectively.Assets related to capital leases included above totaled $70 million and $69 million at December 31, 2012 and 2011,respectively, net of accumulated depreciation.Asset Retirement and Mining Reclamation ObligationsThese liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining,removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is noearnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through theregulatory process as part of Oncor's delivery fees.The following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrentliabilities and deferred credits in the balance sheet, for the years ended December 31, 2012 and 2011:Mining LandNuclear Plant Reclamation andDecommissioning Other TotalLiability at January 1, 2011 $ 329 $ 164 $ 493Additions:AccretionIncremental reclamation costs (a)Reductions:PaymentsLiability at December 31, 2011Additions:AccretionIncremental reclamation costs (a)Reductions:PaymentsLiability at December 31, 2012Less amounts due currentlyNoncurrent liability at December 31, 2012(a) Reflecting additional land to be reclaimed.1929674867-(72) (72)$ 348 $ 188 $ 5362037365736-(93) (93)368 168 536-(84) (84)$ 368 $ 84 $ 452174 Table of ContentsOther Noncurrent Liabilities and Deferred CreditsThe balance of other noncurrent liabilities and deferred credits consists of the following:Uncertain tax positions (including accrued interest)Retirement plan and other employee benefits (a)Asset retirement and mining reclamation obligationsUnfavorable purchase and sales contractsNuclear decommissioning cost over-recovery (Note 15) (b)OtherTotal other noncurrent liabilities and deferred creditsDecember 31,2012 2011$ 2,005 $ 1,9721,035 1,664452 505620 647284 22530 28S 4,426 $ 5,041(a) Includes $825 million and $1.235 billion at December 31, 2012 and 2011, respectively, representing pension and OPEBliabilities related to Oncor (see Note 15).(b) Balance at December 31, 2011 was previously classified as a liability due to unconsolidated subsidiary. Because Oncor onlyacts as collection agent to balance the amounts ultimately collected from its customers with the actual future cost todecommission the nuclear plant, the classification as a liability due Oncor was corrected.Unfavorable Purchase and Sales Contracts -Unfavorable purchase and sales contracts primarily represent the extent towhich contracts on a net basis were unfavorable to market prices at the date of the Merger. These are contracts for which: (i)TCEH has made the "normal" purchase or sale election allowed or (ii) the contract did not meet the definition of a derivative underaccounting standards related to derivative instruments and hedging transactions. Under purchase accounting, TCEH recorded thevalue at October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is primarilyon a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of purchasedpower costs as appropriate. The amortization amount totaled $27 million, $26 million and $27 million for the years endedDecember 31,2012,2011 and 2010, respectively. See Note 3 for intangible assets related to favorable purchase and sales contracts.The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:Year Amount2013 $ 262014 $ 252015 $ 252016 $ 252017 $ 25175 Table of ContentsSupplemental Cash Flow InformationCash payments (receipts) related to:Interest paid (a)Capitalized interestInterest paid (net of capitalized interest) (a)Income taxesNoncash investing and financing activities:Principal amount of toggle notes issued in lieu of cash interest (Note 8)Construction expenditures (b)Debt exchange transactionsCapital leasesGain on termination of long-term power sales contract (Note 6)Year Ended December 31,2012 2011 2010$ 3,151 $ 2,958 $ 2,693$ (36) $ (31) $ (60)$ 3,115 $ 2,927 $ 2,633$ 71 $ 37 $ 64$ 235 $$ 50 $$ 457 $$ 15 $$ .- $206 $67 $34 $1 $--399841,6419(116)(a) Net of interest received on interest rate swaps.(b) Represents end-of-period accruals.176 Table of ContentsItem 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURENone.Item 9A. CONTROLS AND PROCEDURESAn evaluation was performed under the supervision and with the participation of our management, including the principalexecutive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls andprocedures in effect at December 31,2012. Based on the evaluation performed, our management, including the principal executiveofficer and principal financial officer, concluded that the disclosure controls and procedures were effective.There has been no change in our internal control over financial reporting during the most recently completed fiscal quarterthat has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.ENERGY FUTURE HOLDINGS CORP.MANAGEMENT'S ANNUAL REPORT ONINTERNAL CONTROL OVER FINANCIAL REPORTINGThe management of Energy Future Holdings Corp. is responsible for establishing and maintaining adequate internal control overfinancial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company.Energy Future Holdings Corp.'s internal control over financial reporting is designed to provide reasonable assurance regardingthe reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent ordetect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in condition or the deterioration of compliance with procedures or policies.The management of Energy Future Holdings Corp. performed an evaluation as of December 31, 2012 of the effectiveness of thecompany's internal control over financial reporting based on the Committee of Sponsoring Organizations of the TreadwayCommission's (COSO's) Internal Control -Integrated Framework. Based on the review performed, management believes that asof December 31, 2012 Energy Future Holdings Corp.'s internal control over financial reporting was effective.The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statementsof Energy Future Holdings Corp. has issued an attestation report on Energy Future Holdings Corp.'s internal control over financialreporting./s/ JOHN F. YOUNG /s/ PAUL M. KEGLEVICJohn F. Young, President and Paul M. Keglevic, Executive Vice PresidentChief Executive Officer and Chief Financial OfficerFebruary 19, 2013177 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and Shareholders of Energy Future Holdings Corp.Dallas, TexasWe have audited the internal control over financial reporting of Energy Future Holdings Corp. and subsidiaries ("EFH Corp.") asof December 31, 2012, based on criteria established in Internal Control -Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission. EFH Corp.'s management is responsible for maintaining effective internalcontrol over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included inthe accompanying Management's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to expressan opinion on EFH Corp.'s internal control over financial reporting based on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal controlover financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal controlover financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operatingeffectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary inthe circumstances. We believe that our audit provides a reasonable basis for our opinion.A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principalexecutive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors,management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles. A company's internalcontrol over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonableassurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timelydetection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financialstatements.Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or impropermanagement override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subjectto the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.In our opinion, EFH Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31,2012, based on the criteria established in Internal Control -Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission.We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), theconsolidated financial statements and financial statement schedule at and for the year ended December 31, 2012 of EFH Corp.and our report dated February 19, 2013 expressed an unqualified opinion on those financial statements and financial statementschedule, and included an emphasis of a matter paragraph related to EFH Corp.'s continued net losses, substantial indebtednessand significant cash interest requirements, as well as EFH Corp.'s ability to satisfy its obligations in October 2014, which includethe maturities of $3.8 billion ofTCEH Term Loan Facilities, being dependent upon the completion of one or more actions describedin Note I to the consolidated financial statements.Is/ Deloitte & Touche LLPDallas, TexasFebruary 19, 2013Item 9B. OTHER INFORMATIONNone.178 Table of ContentsPART 1I1.Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEDirectorsThe names of EFH Corp.'s directors and information about them, as furnished by the directors themselves, are set forthbelow:NameArcilia C. Acosta (1)(3)David BondermanDonald L. Evans (2)(3)Thomas D. FergusonBrandon A. FreimanAge47Served AsDirectorSince2008Business ExperienceArcilia C. Acosta has served as a Director of EFH Corp. since May 2008. Ms.Acosta is the founder, President and CEO of CARCON Industries &Construction, L.L.C. (CARCON) and its subsidiaries. She is also the founder,President and CEO of Southwestern Testing Laboratories, L.L.C. (STL).CARCON's principal business is commercial, institutional and transportation,design and build construction. STL's principal business is geotechnicalengineering, construction materials testing and environmental consultingservices. Ms. Acosta is a former Chair of the State of Texas Hispanic Chambersorganization known as the Texas Association of Mexican American Chambersof Commerce (TAMACC) and the Greater Dallas Hispanic Chamber ofCommerce. Ms. Acosta serves on the Board of Directors of EFCH, TCEH, theDallas Citizens Council, U.T. Southwestern Board of Visitors, The Texas TechAlumni Association National Board of Directors and The Dallas EducationFoundation.70 2007 David Bonderman has served as a Director of EFH Corp. since October 2007.He is a founding partner of TPG Capital, L.P. (TPG). Mr. Bonderman serves onthe boards of the following companies: Caesars Entertainment Corporation(formerly Harrah's Entertainment), CoStar Group, Inc., General MotorsCompany, JSC VTB Bank, and Ryanair Holdings plc, for which he serves asChairman of the Board. During the past five years, Mr. Bonderman also servedon the boards of Armstrong World Industries, Inc., Burger King Holdings, Inc.,Gemalto N.V., Univision Communications, Inc. and Washington Mutual, Inc..66 2007 Donald L. Evans has served as a Director and Non-Executive Chairman of EFHCorp. since October 2007. He is also a Senior Partner at Quintana EnergyPartners, L.P. He was CEO of the Financial Services Forum from 2005 to 2007,after serving as the 34th secretary of the U.S. Department of Commerce. Beforeserving as Secretary of Commerce, Mr. Evans was the former CEO of TomBrown, Inc., a large independent energy company. He also previously served asa member and chairman of the Board of Regents of the University of TexasSystem. Mr. Evans is a director of Genesis Energy, L. P.59 2008 Thomas D. Ferguson has served as a Director of EFH Corp. since December2008. He is a Managing Director of Goldman, Sachs & Co., having joined thefirm in 2002. Mr. Ferguson heads the asset management efforts for the merchantbank's U.S. real estate and infrastructure investment activity. He currently serveson the board of American Golf, for which he serves as the company's non-executive Chairman, Agriculture Company of America, EFIH and Oncor. Heformerly held board seats at Associated British Ports, the largest port companyin the UK, Carrix, one of the largest private container terminal operators in theworld, as well as Red de Carreteras, a toll road concessionaire in Mexico.31 2012 Brandon A Freiman has served as a Director of EFH Corp. since June 2012. Hehas been with KKR since 2007 where he is a director. He has been directlyinvolved in several ofthe firm's investments including El Paso Midstream Group,Accelerated Oil Technologies, LLC, Del Monte Foods, Fortune CreekMidstream, Westbrick Energy, LTD and Bayonne Water JV and has portfoliocompany responsibilities for Rockwood Holdings, Inc. Mr. Freiman is a directorof Fortune Creek Midstream, Westbrick Energy, LTD, Accelerated OilTechnologies, LLC and Bayonne Water JV.179 Table of ContentsNameScott LebovitzMarc S. Lipschultz (3)Michael MacDougall (2)Kenneth Pontarelli (2)(3)William K. ReillyJonathan D. Smidt (2)Served AsDirectorAge Since37 2007Business ExperienceScott Lebovitz has served as a Director of EFH Corp. since October 2007. Hehas been a Managing Director of Goldman, Sachs & Co. in its PrincipalInvestment Area since 2007 having joined Goldman, Sachs & Co. in 1997. Mr.Lebovitz serves on the boards of both public and private companies, includingAssociated Asphalt Partners, LLC, EdgeMarc Energy Holdings, LLC, EF EnergyHoldings, LLC, EW Energy Holdings, LLC, Cobalt International Energy, Inc.,EFCH and TCEH. During the past five years, Mr. Lebovitz also served on theboard of CVR Energy, Inc.44 2007 Marc S. Lipschultz has served as a Director of EFH Corp. since October 2007.Hejoined KKR in 1995 and is the global head of KKR's Energy and Infrastructurebusiness. Mr. Lipschultz serves on KKR's Infrastructure Investment Committeeand its Oil & Gas Investment Committee.42 2007 Michael MacDougall has served as a Director of EFH Corp. since October 2007.He is a partner ofTPG. Mr. MacDougall leads the firm's global energy and naturalresources investing efforts. Prior to joining TPG in 2002, Mr. MacDougall wasa vice president in the Principal Investment Area of the Merchant BankingDivision of Goldman, Sachs & Co., where he focused on private equity andmezzanine investments. Mr. MacDougall is a director of both public and privatecompanies, including Copano Energy, L.L.C., Graphic Packaging HoldingCompany, Harvester Holdings, LLC and its two subsidiaries, Petro HarvesterOil and Gas, LLC and 2CO Energy Limited, Maverick American Natural Gas,LLC, Nexeo Solutions Holdings, LLC, Northern Tier Energy, LLC, EFCH, andTCEH and is a director of the general partner of Valerus Compression Services,L.P. During the past five years, he also served on the boards ofAleris Internationaland Kraton Performance Polymers Inc. Mr. MacDougall is also a member of theboards of directors of Islesboro Affordable Property, The Opportunity Networkand the University of Texas Development Board.42 2007 Kenneth Pontarelli has served as a Director of EFH Corp. since October 2007.He is a Managing Director of Goldman, Sachs & Co. in its Principal InvestmentArea. He transferred to the Principal Investment Area in 1999 and was promotedto Managing Director in 2004. Mr. Pontarelli serves as a director of both publicand private companies, including Tervita Corporation, Cobalt InternationalEnergy, L.P., EFIH, and Expro International Group Ltd. During the past fiveyears, he also served on the boards of CVR Energy, Inc. and Kinder Morgan,Inc.73 2007 William K. Reilly has served as a Director of EFH Corp. since October 2007.He is a Senior Advisor to TPG and a founding partner of Aqua InternationalPartners, an investment group that invests in companies that serve the water andrenewable energy sectors, having previously served as the seventh Administratorof the EPA. Mr. Reilly is a director of the following public companies:ConocoPhillips and Royal Caribbean International. During the past five years,he also served on the boards of Eden Springs, Ltd. of Israel and E.1 DuPont deNemours and Company. Before serving as EPA Administrator, Mr. Reilly wasPresident ofWorld Wildlife Fund and President ofThe Conservation Foundation.He previously served as Executive Director of the Rockefeller Task Force onLand Use and Urban Growth, a senior staff member of the President's Councilon Environmental Quality, Associate Director of the Urban Policy Center andthe National Urban Coalition and Co-Chairman of the National Commission onEnergy Policy. Mr. Reilly was appointed by the President to serve as Co-Chairof the National Commission on the Deepwater Horizon Oil Spill and OffshoreDrilling.40 2007 Jonathan D. Smidt has served as a Director of EFH Corp. since October 2007.He has been with KKR since 2000, where he is a partner and senior memberof the firm's Energy and Infrastructure team and leads KKR NaturalResources, the firm's platform to acquire and operate oil and natural gasassets. Currently, he is a director of Laureate Education Inc., EFCH andTCEH.180 Table of ContentsServed AsDirectorSinceNameJohn F. Young (2)Kneeland Youngblood (1)Age562008Business ExperienceJohn F. Young has served as a Director and President and Chief Executive ofEFH Corp. since January 2008. Before joining EFH Corp., Mr. Young served inmany leadership roles at Exelon Corporation from March 2003 to January 2008including Executive Vice President of Finance and Markets and Chief FinancialOfficer of Exelon Corporation; President of Exelon Generation; and Presidentand Chief Operating Officer of Exelon Power. Prior to joining ExelonCorporation, Mr. Young was Senior Vice President of Sierra Pacific ResourcesCorporation. Mr. Young is also a director of EFCH, EFIH, TCEH, Luminant,Nuclear Electric Insurance Limited and USAA.Kneeland Youngblood has served as a Director of EFH Corp. since October2007. He is a founding partner of Pharos Capital Group, a private equity firmthat focuses on providing growth and expansion capital to businesses intechnology, business services and health care services. During the last five years,Mr. Youngblood served on the boards of Burger King Holdings, Inc., StarwoodHotels and Resorts Worldwide, Inc. and Gap Inc. Mr. Youngblood is a directorof EFIH and a member of the Council on Foreign Relations.57 2007(1) Member of Audit Committee.(2) Member of Executive Committee.(3) Member of Organization and Compensation CommitteeThere is no family relationship between any of the above-named directors.Director QualificationsIn October 2007, David Bonderman, Donald L. Evans, Scott Lebovitz, Marc S. Lipschultz, Michael MacDougall, KennethPontarelli, William K. Reilly, Jonathan D. Smidt, and Kneeland Youngblood were elected to EFH Corp.'s board of directors (theBoard). Arcilia C. Acosta, Thomas D. Ferguson and John F. Young joined the Board in 2008 and Brandon A. Freiman joined theboard in 2012. Messrs. Bonderman, Ferguson, Freiman, Lebovitz, Lipschultz, MacDougall, Pontarelli, and Smidt are collectivelyreferred to as the "Sponsor Directors." Ms. Acosta and Messrs. Evans, Reilly, Young, and Youngblood are collectively referred toas the "Non-Sponsor Directors."Each of the Sponsor Directors was elected to the Board pursuant to the Limited Partnership Agreement of Texas EnergyFuture Holdings Limited Partnership, the holder of a majority of the outstanding capital stock of EFH Corp. Pursuant to thisagreement, Messrs. Freiman, Lipschultz and Smidt were appointed to the Board as a consequence of their relationships withKohlberg Kravis Roberts & Co.; Messrs. Bonderman and MacDougall were appointed to the Board as a consequence of theirrelationships with TPG Capital, L.P., and Messrs. Ferguson, Lebovitz and Pontarelli were appointed to the Board as a consequenceof their relationships with GS Capital Partners.When considering whether the Board's directors and nominees have the experience, qualifications, attributes and skills, takenas a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of EFH Corp.'s business and structure,the Board focused primarily on the qualifications summarized in each of the Board member's biographical information set forthabove. In addition, EFH Corp. believes that each of its directors possesses high ethical standards, acts with integrity, and exercisescareful judgment. Each is committed to employing his/her skills and abilities in the long-term interests of EFH Corp and itsstakeholders. Finally, our directors are knowledgeable and experienced in business, governmental, and civic endeavors, furtherqualifying them for service as members of the Board.The Sponsor Directors possess experience in owning and managing privately held enterprises and are familiar with corporatefinance and strategic business planning activities of highly-leveraged companies such as EFH Corp. Some of the Sponsor Directorsalso have experience advising and overseeing the operations of large industrial, manufacturing or retail companies similar to ourbusinesses. Finally, several of the Sponsor Directors possess substantial expertise in advising and managing companies in segmentsof the energy industry, including, among others, power generation, oil and gas, and energy infrastructure and transportation.As a group and individually, the Non-Sponsor Directors possess extensive experience in governmental and civic endeavorsand in the business community, in each case, in the markets where our businesses operate.181 Table of ContentsMr. Young's employment agreement provides that he will serve as a member of the Board during the time he is employedby EFH Corp. Before joining EFH Corp. as President and Chief Executive Officer, he held various senior management positionsat other companies in the energy industry over twenty years, including, most recently, his role as Executive Vice President ofFinance and Markets and Chief Financial Officer of Exelon Corporation.Ms. Acosta manages the operations of a large commercial construction company in Texas and has significant experiencewithin the local Hispanic business community, having served as the chair of the Greater Dallas Hispanic Chamber of Commerceand the Texas Association of Mexican American Chambers of Commerce. Her experience and expertise in financial matters qualifyher to serve as EFH Corp's "audit committee financial expert." Mr. Evans has demonstrated ability and achievement in both theprivate and public sectors, serving as U.S. Secretary of Commerce during the Bush Administration, and both before and after hisgovernment service, acting as Chairman and Chief Executive Officer of a publicly-owned energy company, Tom Brown, Inc. Mr.Reilly possesses a distinguished record of public service and extensive policy-making experience as a former administrator of theEPA, lectures extensively on environmental issues facing companies operating in the energy industry and has served as Co-Chairman of the National Commission on Energy Policy. Mr. Youngblood has served on numnerous boards for large publiccompanies, has extensive experience managing and advising companies in his capacity as a partner in a private equity firm (notaffiliated with the Sponsor Group), is highly knowledgeable of federal and state political matters, and has served on the board ofdirectors of the United States Enrichment Corporation, a company that contracts with the US Department of Energy to produceenriched uranium for use in nuclear power plants.Executive OfficersThe names and information regarding EFH Corp.'s executive officers are set forth below:Name of OfficerJohn F. YoungJames A. BurkeStacey H. Dor6Positions and OfficesAge Presently Held56 President and ChiefExecutive Officer ofEFH Corp.44 Executive VicePresident of EFH Corp..and President and ChiefExecutive of TXUEnergy40 Executive VicePresident and GeneralCounsel of EFH Corp.Date First Electedto Present OfficesJanuary 2008August 2005February 2013Business Experience(Preceding Five Years)John F. Young was elected President and ChiefExecutive Officer of EFH Corp. in January 2008.Before joining EFH Corp., Mr. Young served inmany leadership roles at Exelon Corporationfrom March 2003 to January 2008, includingExecutive Vice President of Finance andMarkets and Chief Financial Officer of ExelonCorporation; President of Exelon Generation;and President and Chief Operating Officer ofExelon Power. Prior to joining ExelonCorporation, Mr. Young was Senior VicePresident of Sierra Pacific ResourcesCorporation.James A. Burke was elected Executive VicePresident of EFH Corp. in February 2013 andPresident and Chief Executive of TXU Energyin August 2005. Previously, Mr. Burke wasSenior Vice President Consumer Markets ofTXU Energy.Stacey H. Dord was elected Executive VicePresident and General Counsel of EFH Corp. inFebruary 2013 having previously served asSenior Vice President and General Counsel ofEFH Corp. from April 2012 to February 2013.Ms. Dor6 was Vice President and GeneralCounsel of Luminant from November 2011 toMarch 2012 having previously served as VicePresident and Associate General Counsel ofEFHCorp. from July 2008 to November 2011. Priorto joining EFH Corp., she was an attorney atVinson & Elkins LLP, where she engaged in abusiness litigation practice.182 Table of ContentsPositions and OfficesName of Officer Age Presently HeldPaul M. Keglevic 59 Executive VicePresident and ChiefFinancial Officer ofEFH Corp.Date First Electedto Present OfficesJuly 2008Business Experience(Preceding Five Years)Paul M. Keglevic was elected Executive VicePresident and Chief Financial Officer of EFHCorp. in July 2008. Before joining EFH Corp.,he was an audit partner atPricewaterhouseCoopers. Mr. Keglevic wasPricewaterhouseCoopers' Utility Sector Leaderfrom 2002 to 2008 and Clients and SectorAssurance Leader from 2007 to 2008.Carrie L. Kirby was elected Executive VicePresident of EFH Corp. in February 2013 havingpreviously served as Senior Vice President ofEFH Corp. from April 2012 to February 2013and oversees human resources. Previously shewas Vice President offHuman Resources of TXUEnergy.Carrie L. KirbyM. A. McFarlandJohn D. O'Brien45 Executive VicePresident of EFH Corp.43 Executive VicePresident of EFH Corp.and President and ChiefExecutive of Luminant52 Executive VicePresident of EFH Corp.February 2013July 2008 M. A. McFarland was elected President andChief Executive of Luminant in December 2012and Executive Vice President of EFH Corp. inJuly 2008. He previously served as ExecutiveVice President and Chief Commercial Officer ofLuminant. Before joining Luminant, Mr.McFarland served as Senior Vice President ofMergers, Acquisitions and Divestitures and as aVice President in the wholesale marketing andtrading division power team at ExelonCorporation.February 2013John D. O'Brien was elected Executive VicePresident of EFH Corp. in February 2013 havingpreviously served as Senior Vice President ofEFH Corp. from October 2011 to February 2013.Before joining EFH, he served as Senior VicePresident of Government and Regulatory Affairsat NRG Energy from 2007 to 2011 and VicePresident of Environmental and RegulatoryAffairs at Exelon Power, a subsidiary of ExelonCorporation, from 2004 to 2007.There is no family relationship between any of the above-named executive officers.Audit Committee Financial ExpertThe Board has determined that Arcilia C. Acosta is an "Audit Committee Financial Expert" as defined in Item 407(d)(5) ofSEC Regulation S-K and Ms. Acosta is independent under the New York Stock Exchange's audit committee independencerequirements for issuers of debt securities.Code of ConductEFH Corp. maintains certain corporate governance documents on EFH Corp's website at www.energyfutureholdings.com.EFH Corp.'s Code of Conduct can be accessed by selecting "Investor Relations" on the EFH Corp. website. EFH Corp.'s Code ofConduct applies to all of its employees, officers (including the Chief Executive Officer, Chief Financial Officer and PrincipalAccounting Officer) and directors. Any amendments to the Code of Conduct will be posted on EFH Corp.'s website. Printed copiesof the corporate governance documents that are posted on EFH Corp.'s website are also available to any investor upon request tothe Secretary of EFH Corp. at 1601 Bryan Street, Dallas, Texas 75201-3411.183 Table of ContentsProcedures for Shareholders to Nominate Directors; Arrangement to Serve as DirectorsThe Amended and Restated Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC, thegeneral partner of Texas Holdings, generally requires that the members of Texas Energy Future Capital Holdings LLC take allnecessary action to ensure that the persons who serve as its managers also serve on the EFH Corp. Board. In addition, Mr. JohnYoung's employment agreement provides that he will be elected as a member of the Board during the time he is employed by EFHCorp.Because of these requirements, together with Texas Holdings' controlling ownership of EFH Corp.'s outstanding commonstock, there is no policy or procedure with respect to shareholder recommendations for nominees to the EFH Corp. Board.184 Table of ContentsItem 11. EXECUTIVE COMPENSATIONOrganization and Compensation CommitteeThe Organization and Compensation Committee (the "O&C Committee") of EFH Corp.'s Board of Directors (the "Board")is comprised of four non-employee directors: Arcilia C. Acosta, Donald L. Evans, Marc S. Lipschultz and Kenneth Pontarelli.The primary responsibility of the O&C Committee is to:* determine and oversee the compensation program of EFH Corp. and its subsidiaries (other than the Oncor Ring-FencedEntities), including making recommendations to the Board with respect to the adoption, amendment or termination ofcompensation and benefits plans, arrangements, policies and practices;" evaluate the performance of EFH Corp.'s Chief Executive Officer (the "CEO") and the other executive officers of EFHCorp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) (collectively, the "executive officers"), includingJohn F. Young, President and Chief Executive Officer of EFH Corp.; Paul M. Keglevic, Executive Vice President andChief Financial Officer of EFH Corp.; David A. Campbell, former President and Chief Executive Officer of Luminant;James A. Burke, President and Chief Executive Officer of TXU Energy and Executive Vice President of EFH Corp.;and M.A. McFarland, President and Chief Executive Officer of Luminant and Executive Vice President of EFH Corp.(collectively, the "Named Executive Officers"), and" approve executive compensation based on those evaluations.Compensation Risk AssessmentOur management team initiates EFH Corp.'s internal risk review and assessment process for our compensation policies andpractices by assessing, among other things, (1) the mix of cash and equity payouts at various compensation levels; (2) theperformance time horizons used by our plans; (3) the use of multiple financial and operational performance metrics that are readilymonitored and reviewed; (4) the equity investment that most of our senior and middle management employees have in EFH Corp.common stock; (5) the lack of an active trading market and other impediments to liquidity associated with EFH Corp. commonstock; (6) the incorporation of both operational and financial goals and individual performance modifiers; (7) the inclusion ofmaximum caps and other plan-based mitigants on the amount of certain of our awards; and (8) multiple levels of review andapproval of awards (including approval of our O&C Committee with respect to awards to executive officers and awards to otheremployees that exceed monetary thresholds). Following their assessment, our management team prepares a report, which isprovided to EFH Corp.'s Audit Committee for review. After review and adjustment, if any, as determined by EFH Corp.'s AuditCommittee, the Audit Committee provides the report to the O&C Committee. EFH Corp.'s management and Audit Committeehave determined that the risks arising from EFH Corp.'s compensation policies and practices are not reasonably likely to have amaterial adverse effect on EFH Corp.Compensation Discussion and AnalysisExecutive SummaryResignation of David Campbell/Promotion of M.A. McFarlandEffective January 1, 2013, Mr. Campbell resigned as President and Chief Executive Officer of Luminant. Following Mr.Campbell's resignation, EFH Corp. promoted Mr. McFarland, who has served as Executive Vice President and Chief CommercialOfficer of Luminant since July 2008, to the position of President and Chief Executive Officer of Luminant, effective January 1,2013. In connection with his promotion, Mr. McFarland entered into an amended and restated employment agreement, as describedmore fully herein.185 Table of ContentsSignificant Executive Compensation ActionsEFH Corp.'s executive compensation programs are designed to implement our pay-for-performance compensationphilosophy, which places an emphasis on pay-at-risk. As a result, our compensation programs balance long-term and short-termobjectives and generally consist of salary, bonuses, equity, benefits and perquisites. In December 2012, following a review of ourbusinesses' strong performance in 2012 despite the sustained decline in ERCOT wholesale electricity prices (primarily as a resultof lower forward natural gas prices), the increased environmental regulatory requirements of the electricity generation industry,our position as a highly-leveraged, privately-owned company, and the analysis of our compensation practices and plans andaccompanying discussions with an independent consultant, the O&C Committee approved an increase in the base salaries forcertain of our Named Executive Officers, and an increase in the annual cash bonus opportunity for Mr. Young to better align thecompensation of our Named Executive Officers with the compensation of similarly performing executive officers in companieswe consider our peer group. These adjustments, which became effective January 1, 2013, are described more fully herein.Significant Business Activities in 2012Liability Management ProgramIn 2009, we initiated a liability management program designed to reduce debt, capture debt discount and extend debt maturitiesthrough debt exchanges, repurchases and extensions. As part of the program, in December 2012, we initiated a request to extendup to $645 million of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016, which resultedin the extension of all such commitments. Additionally in December 2012, we launched a number of exchanges, which streamlinedour capital structure. The debt exchanges, which closed in December 2012 and January 2013, resulted in the capture ofapproximately $470 million of debt discount. The TCEH Revolving Credit Facility extension and these debt exchanges are morefully described in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -SignificantActivities and Events and Items Influencing Future Performance" and Note 8 to Financial Statements in this Form 10-K. Sinceinception, the program has resulted in the capture of approximately $2.5 billion of debt discount and the extension of approximately$25.7 billion of debt maturities to 2017-2021.Regulatory EnvironmentDuring 2012, EFH Corp. continued to balance Texas' energy requirements while facing new and evolving environmentalregulatory changes. In 2012, the PUCT and the ERCOT Board of Directors implemented or approved several changes to ERCOTprotocols designed to establish minimum offer floors for wholesale power offers during deployment of certain reliability-relatedservices, including non-spinning reserve, responsive reserve, reliability unit commitment, and other services. In addition, in Juneand October 2012 the PUCT approved rules that, among other things, increased the system-wide offer cap that applies to wholesalepower offers in ERCOT for the stated purpose of sending appropriate price signals to encourage development of generationresources in ERCOT. Additionally, in June 2012, the Brattle Group, an independent consultant engaged by ERCOT to assess theincentives for generation investment in the ERCOT market, issued a report on potential next steps for addressing generationresource adequacy. In August 2012, a three judge panel of the U.S. Court of Appeals for the District of Columbia Circuit ("D.C.Circuit Court") vacated the CSAPR and in January 2013, the D.C. Circuit denied the EPA's petitions for rehearing and rehearingen banc. In December 2011 the EPA published the final MATS rule, and in April 2012, EFH Corp. subsequently filed a petitionfor review challenging the rule in the D.C. Circuit Court. See Item 7 "Management's Discussion and Analysis of Financial Conditionand Results of Operations" and Items I and 2 "Business and Properties -Environmental Regulations and Related Considerations"in this Form 10-K for a detailed discussion of resource adequacy, CSAPR and MATS.Operational Performance2012 was a strong year for operational and financial performance at both TXU Energy and Luminant. TXU Energyreached organizational highs in customer satisfaction and retention metrics, achieved a year over year 42% improvement inresidential attrition rates, reduced bad debt expense to its lowest level since before competition started in 2002 and achieved recordlow customer complaints, continuing top tier PUC complaint performance. Luminant achieved record summer generation reliabilitywhile realizing its lowest fossil safety incident rate.186 Table of ContentsCompensation PhilosophyWe have a pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk. In other words, asignificant portion of an executive officer's compensation is comprised of variable, at-risk incentive compensation. Ourcompensation program is intended to attract and motivate top-talent executive officers as leaders and compensate executive officersappropriately for their contribution to the attainment of our financial, operational and strategic objectives. In addition, we believeit is important to retain our executive officers and strongly align their interests with our stakeholders by emphasizing long-termincentive compensation. Given the competitive nature of the unregulated market in ERCOT, the evolving regulatory environment,and our substantial leverage, we believe such retention of talent is critical to our continued success.To achieve the goals of our compensation philosophy, we believe that:* compensation plans should balance both long-term and short-term objectives;* the overall compensation program should emphasize variable compensation elements that have a direct link to overallcorporate performance and stakeholder value;* the overall compensation program should place an increased emphasis on pay-at-risk with increased responsibility;* the overall compensation program should attract, motivate and retain top talent executive officers to serve in key roles;and* an executive officer's individual compensation level should be based upon an evaluation of the financial and operationalperformance of that executive officer's business unit or area of responsibility as well as the executive officer's individualperformance.We believe our compensation philosophy supports our businesses by:" aligning performance measures with our business objectives to drive the financial and operational performance of EFHCorp. and its business units;" rewarding business unit and individual performance by providing compensation levels consistent with the level ofcontribution and degree of accountability;" attracting and retaining the best performers, and* effectively aligning the correlation between the long-term interests of our executive officers and stakeholders.Elements of CompensationThe material elements of our executive compensation program are:* a base salary;* the opportunity to earn an annual performance-based cash bonus based on the achievement of specific corporate, businessunit and individual performance goals, and* long-term incentive awards, primarily in the form of long-term cash incentive awards and restricted stock units("Restricted Stock Units") under and subject to the terms of the 2007 Stock Incentive Plan for Key Employees of EFHCorp. and Affiliates (the "2007 Stock Incentive Plan").In addition, executive officers generally have the opportunity to participate in certain of our broad-based employee benefitplans, including our Thrift (401 (k)) Plan and health and welfare plans, and to receive certain perquisites.Compensation of the CEOIn determining the compensation of the CEO, the O&C Committee annually follows a thorough and detailed process. Atthe end of each year, the O&C Committee reviews a self-assessment prepared by the CEO regarding his performance and theperformance of our businesses and meets (with and without the CEO) to evaluate and discuss his performance and the performanceof our businesses.While the O&C Committee tries to ensure that the bulk of the CEO's compensation is directly linked to his performance andthe performance of our businesses, the O&C Committee also seeks to set his compensation in a manner that is competitive withcompensation for similarly performing executive officers with similar responsibilities in companies we consider our peers.187 Table of ContentsCompensation of Other Executive OfficersIn determining the compensation of each of our executive officers (other than the CEO), the O&C Committee seeks the inputof the CEO. At the end of each year, the CEO reviews a self-assessment prepared by each executive officer and assesses theexecutive officer's performance against business unit (or area of responsibility) and individual goals and objectives. The O&CCommittee and the CEO then review the CEO's assessments and, in that context, the O&C Committee approves the compensationfor each executive officer.Assessment of Compensation ElementsWe design the majority of our executive officers' compensation to be linked directly to corporate and business unit (or areaof responsibility) performance. For example, each executive officer's annual performance-based cash bonus is primarily basedon the achievement of certain corporate and business unit financial and operational targets (such as management EBITDA, asdiscussed herein, cost management, generation output, customer satisfaction, etc.). In addition, each executive officer's long-termcash incentive award is based on achievement of certain operational and financial performance metrics. We also try to ensure thatour executive compensation program is competitive with our peer companies in order to effectively motivate and retain ourexecutive officers.The following is a detailed discussion of the principal compensation elements provided to our executive officers and theamendments made thereto in 2012. Additional detail about each of the elements can be found in the compensation tables, includingthe footnotes and the narrative discussion following certain of the tables.2012 Executive Compensation Evaluation and AdjustmentIn October 2012, the O&C Committee engaged Towers Watson & Co. ("Towers Watson"), an independent compensationconsultant to review the compensation practices we implemented in February 2011 and to confirm whether such practices continueto be aligned with our compensation philosophy. In December 2012, Towers Watson delivered to the O&C Committee its report,which included market data for a peer group composed of the following companies:Allegheny Energy, Inc. Ameren Corp. American Electric Power Co. IncCalpine Corp. Constellation Energy Group Inc. Dominion Resources Inc.Duke Energy Corp. Edison International Entergy Corp.Exelon Corp. FirstEnergy Corp. PPL Corp.NextEra Energy, Inc. NRG Energy, Inc.01) Southern Co.Progress Energy Inc. Public Service Enterprise Group Inc.Xcel Energy Inc.(1) NRG Energy, Inc. is the successor by merger to GenOn Energy, Inc.In December 2012, after a comprehensive review of the performance of our businesses in 2012, and taking into considerationthe review of our compensation practices and plans by Towers Watson and their subsequent market analysis, the sustained declinein ERCOT wholesale electricity prices (primarily as a result of lower forward natural gas prices), the increased environmentalregulatory requirements of the electricity generation industry, and our position as a highly-leveraged, privately-owned company,the O&C Committee approved increases to the base salaries for certain of our Named Executive Officers as more fully describedin the paragraph entitled "Base Salary" below and an increase in the target annual cash bonus opportunity of Mr. Young to 125%of his base salary, effective January 1, 2013. The O&C Committee implemented these changes to provide a total executivecompensation package comparable to the executive compensation packages of similarly performing executives of our peers andto maintain a strong alignment between our Named Executive Officers and our stakeholders.In connection with the adjustment to Mr. Young's target annual cash bonus opportunity and Mr. McFarland's promotion toPresident and Chief Executive Officer of Luminant, we entered into amended and restated employment agreements, with Mr.Young and Mr. McFarland. Mr. Young's amended and restated employment agreement, effective December 26, 2012, incorporateshis increase in base salary and the amendment to his target annual cash bonus opportunity. Mr. McFarland's amended and restatedemployment agreement, effective January 1, 2013, reflects his position as President and Chief Executive Officer of Luminant.In July 2012, Mr. Keglevic's Amended Deferred Share Agreement was amended. Pursuant to the terms of the SecondAmendment to the Deferred Share Agreement, Mr. Keglevic received a cash payment of $3,200,000 (the "Deferred Amount") andpayment of certain related taxes, upon his continued employment with EFH Corp. on September 30, 2012.188 Table of ContentsBase SalaryBase salary should reward executive officers for the scope and complexity of their position and the level of responsibilityrequired. We believe that a competitive level of base salary is required to attract, motivate and retain qualified talent.The O&C Committee annually reviews base salaries and periodically uses independent compensation consultants to ensurethe base salaries are market-competitive. The O&C Committee may also review an executive officer's base salary from time totime during a year, including if the executive officer is given a promotion or if his responsibilities are significantly modified.We want to ensure our cash compensation is competitive and sufficient to incent executive officers to remain with us,recognizing our high performance expectations across a broad set of operational, financial, customer service and community-oriented goals and objectives and the higher risk levels associated with being a significantly-leveraged company. Although basesalaries did not change from 2011 to 2012, in December 2012, in connection with the assessment of the compensation of ourexecutive officers and following the analysis of our compensation practices and plans by, and discussions with, Towers Watson,the O&C Committee determined the base salaries for certain of the Named Executive Officers should increase in 2013. BeginningJanuary 2013, Mr. Young's base salary was increased to $1,350,000, Mr. Keglevic's base salary was increased to $735,000, Mr.Burke's base salary was increased to $675,000, and Mr. McFarland's base salary was increased to $675,000.Annual Performance-Based Cash Bonus -Executive Annual Incentive PlanThe Executive Annual Incentive Plan ("EAIP") provides an annual performance-based cash bonus for the successfulattainment of certain annual financial and operational performance targets that are established annually at each of the corporateand business unit levels by the O&C Committee. Under the terms of the EAIP, performance against these targets, which aregenerally set at levels to incent high performance (while at the same time balancing the needs for safety and investment in ourbusiness), drives bonus funding. As a general matter, target level performance is based on EFH Corp.'s board-approved financialand operational plan (the "Financial Plan") for the upcoming year. The O&C Committee's expectation when setting target levelperformance is that the business will achieve the target level of performance during the upcoming year. Threshold and superiorlevels are for performance levels that are below or above expectations. Based on the level of attainment of these performancetargets, an aggregate EAIP funding percentage amount for all participants is determined.Our financial performance targets typically include "management" EBITDA, a non-GAAP financial measure. When theO&C Committee reviews management EBITDA for purposes of determining our performance against the applicable managementEBITDA target, it includes our net income (loss) before interest, taxes, depreciation and amortization plus transaction, managementand/or similar fees paid to the Sponsor Group, together with such adjustments as the O&C Committee shall determine appropriatein its discretion after good faith consultation with our CEO and Chief Financial Officer, including adjustments consistent withthose included in the comparable definitions in TCEH's Senior Secured Facilities (to the extent considered appropriate for executivecompensation purposes). Our management EBITDA targets are also adjusted for acquisitions, divestitures or major capitalinvestment initiatives to the extent that they were material and not contemplated in our Financial Plan. The management EBITDAtargets are intended to measure achievement of the Financial Plan and the adjustments to management EBITDA described aboveprimarily represent elements of our performance that are either beyond the control of management or were not predictable at thetime the Financial Plan was approved. Given our Named Executive Officer's business unit responsibilities, our managementEBITDA calculations for Messrs. Young and Keglevic include Oncor, while management EBITDA calculations for the remainingNamed Executive Officers exclude Oncor. Under the terms of the EAIP, the O&C Committee has broad authority to make theseor any other adjustments to EBITDA that it deems appropriate in connection with its evaluation and compensation of our executiveofficers. Management EBITDA is an internal measure used only for performance management purposes, and EFH Corp. doesnot intend for management EBITDA to be an alternative to any measure of financial performance presented in accordance withGAAP. Management EBITDA is calculated similarly to Adjusted EBITDA, which is disclosed elsewhere in this Form 10-K anddefined in the glossary to this Form 10-K, and reflects substantially all the computational elements of Adjusted EBITDA.189 Table of ContentsFinancial and Operational Performance TargetsThe following table provides a summary of the weight given to the various business unit scorecards, which constitute theperformance targets, for each of the Named Executive Officers.WeightEFH Business LuminantEFH Corp. Services Luminant TXU Energy EnergyManagement Scorecard Scorecard Scorecard ScorecardEBITDAt2) Multiplier Multiplier Multiplier Multiplier Total Payout50% 50% 100% 126%NameJohn F. Young(t)Paul M. Keglevic(l)David A. CampbellJames A. BurkeM.A. McFarland50%25%25%25%50%25%75%25%100%100%100%100%126%132%143%140%75%25%(1) Mr. Young and Mr. Keglevic are measured on EFH Corp. Management EBITDA (including Oncor) while the remainingNamed Executive Officers are measured on EFH Corp. Management EBITDA (excluding Oncor).(2) The targeted EFH Corp. Management EBITDA (including Oncor) for the fiscal year ended December 31, 2012 was $5.099billion. The targeted EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2012 was$3.277 billion. The actual EFH Corp. Management EBITDA (including Oncor) for the fiscal year ended December 31, 2012was $5.215 billion, which was above target. The actual EFH Corp. Management EBITDA (excluding Oncor) for the fiscalyear ended December 31, 2012 was $3.414 billion, which was above target.The following table provides a summary of the performance targets included in the EFH Business Services ScorecardMultiplier.EFHl Business Services Scorecard MultiplierEFH Corp. Management EBITDA (excluding Oncor)(2)Luminant Scorecard MultiplierS3)TXU Energy Scorecard Multiplier(3)EFH Corp. (excluding Oncor) Total SpendEFH Business Services CostsTotalWeight PerformanceMi Payout20% 135% 27%20% 130% 26%20% 145% 29%20%20%100%130% 26%120% 24%132%(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount isachieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between thresholdand target or target and superior, as applicable, with a maximum performance payout for any particular metric being equalto 200%.(2) The targeted EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2012 was $3.277billion. The actual EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2012 was$3.414 billion, which was above target.(3) The performance targets included in the Luminant Scorecard Multiplier and the TXU Energy Scorecard Multiplier aresummarized below.190 Table of ContentsThe following table provides a summary of the performance targets included in the Luminant Scorecard Multiplier.Luminant Scorecard MultiplierLuminant Management EBITDALuminant Available Generation -Coal (June-Sept. 15)Luminant Available Generation -Coal (Jan.-May, Sept. 16-Dec.)Luminant Available Generation -NuclearLuminant O&M/SG&ALuminant Capital ExpendituresLuminant Fossil Fuel CostsTotalWeight Performance"1' Payout37.5% 136% 51%10.0% 200% 20%10.0% 80% 8%7.5% 62% 5%15.0% 128% 19%10.0% 110% 16%10.0% 165% 11%100.0% 130%(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount isachieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between thresholdand target or target and superior, as applicable, with a maximum performance payout for any particular metric being equalto 200%.The following table provides a summary of the performance targets included in the TXU Energy Scorecard Multiplier.TXU Energy Scorecard MultiplierTXU Energy Management EBITDATXU Energy Total CostsContribution MarginResidential Customer CountCustomer SatisfactionAverage Days Sales OutstandingTXU Energy Energizing Event SuccessTXU Energy Customer Satisfaction (Complaints)TXU Energy System Availability (Downtime)TotalWeight Performance"' Payout40.0% 130% 52%20.0% 160% 32%15.0% 153% 23%10.0% 110% 11%3.0% 200% 6%3.0% 200% 6%3.0% 100% 3%3.0% 200% 6%3.0% 200% 6%100.0% 145%(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount isachieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between thresholdand target or target and superior, as applicable, with a maximum performance payout for any particular metric being equalto 200%.The following table provides a summary of the performance targets included in the Luminant Energy Scorecard Multiplier.Luminant Energy Scorecard MultiplierLuminant Management EBITDALuminant Energy SG&AIncremental Value CreatedLiquidity UtilizationTotalWeight Performance") Payout45.0% 136% 61%15.0% 172% 26%30.0% 182% 55%10.0% 200% 20%100.0% 162%(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount isachieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between thresholdand target or target and superior, as applicable, with a maximum performance payout for any particular metric being equalto 200%.191 Table of ContentsIndividual Performance ModifierAfter approving the actual performance against the applicable targets under the EAIP, the O&C Committee and/or the CEOreviews the performance of each of our executive officers on an individual and comparative basis. Based on this review, whichincludes an analysis of both objective and subjective criteria, as determined by the O&C Committee in its sole discretion, includingthe CEO's recommendations (with respect to all executive officers other than himself), the O&C Committee approves an individualperformance modifier for each executive officer. Under the terms of the EAIP, the individual performance modifier can rangefrom an outstanding rating (150%) to an unacceptable rating (0%). To calculate an executive officer's final annual cash incentivebonus, the executive officer's corporate/business unit payout percentages are multiplied by the executive officer's target incentivelevel, which is computed as a percentage of annualized base salary, and then by the executive officer's individual performancemodifier.Actual AwardThe following table provides a summary of the 2012 performance-based cash bonus for each Named Executive Officerunder the EAIP.Target Target AwardName (% of salary) ($ Value) Actual AwardJohn F. Young (I 100% $ 1,200,000 $ 2,268,000Paul M. Keglevic (2) 85% $ 552,500 $ 1,009,418David A. Campbell (3) 85% $ 595,000 $ 785,400James A. Burke (4) 85% $ 535,500 $ 1,033,783M.A. McFarland (5) 85% $ 510,000 $ 963,900(1) Mr. Young's incentive award is based on the successful achievement of the financial performance targets for EFH Corp.(including Oncor) and EFH Business Services and the financial and operational performance targets for Luminant and TXUEnergy and an individual performance modifier. In 2012, Mr. Young successfully led EFH Corp. to exceed managementEBITDA targets while maintaining the company's strong safety record, shaped our environmental and legislative strategiesand worked effectively with regulators at the state and federal level to implement these strategies, and cultivated a capableand respected management team despite the challenges facing EFH Corp. Given these and other significant achievements,the O&C Committee approved an individual performance modifier that increased Mr. Young's incentive award.(2) Mr. Keglevic's incentive award is based on the successful achievement of the financial performance targets for EFH Corp.(including Oncor) and EFH Business Services and the financial and operational performance targets for Luminant and TXUEnergy and an individual performance modifier. In 2012, Mr. Keglevic led our liability management program, including anextension of $645 million in commitments under the TCEH Revolving Credit Facility and the streamlining of our capitalstructure. Mr Keglevic continued to focus on liquidity management and creating efficiencies across EFH Corp. and itssubsidiaries. Given these and other significant achievements, the O&C Committee approved and individual performancemodifier that increased Mr. Keglevic's incentive award.(3) Although Mr. Campbell resigned, effective January 1, 2013, under the terms of his employment agreement, he is entitled toreceive his entire annual cash incentive award with a target level individual performance modifier for 2012. Mr. Campbell'sincentive award is based on the successful achievement of a financial performance target for EFH Corp. (excluding Oncor)and the financial and operational performance targets for Luminant in 2012. In 2012, Mr. Campbell successfully led Luminantto record summer generation reliability while attaining its lowest fossil safety incident rate since the Company has maintainedsuch records. In addition, Mr Campbell led Luminant's successful response to the CSAPR.(4) Mr. Burke's incentive award is based on the successful achievement ofa financial performance target for EFH Corp. (excludingOncor) and the financial and operational performance targets for TXU Energy and an individual performance modifier. In2012, TXU Energy's focus on product innovation and customer satisfaction resulted in record low levels of PUC complaints,record high levels of customer satisfaction, and low customer attrition. Under his leadership, TXU Energy achieved strongfinancial performance in a competitive market, including significantly lowering bad debt expense during 2012. Given thesesignificant accomplishments and other achievements (including his continued commitment to foster TXU Energy's brandand reputation with its customers and stakeholders), the O&C Committee approved an individual performance modifier thatincreased Mr. Burke's incentive award.192 Table of Contents(5) Mr. McFarland's incentive award is based on the successful achievement of the financial performance targets for EFH Corp.(excluding Oncor) and EFH Business Services, the financial and operational performance targets for Luminant and LuminantEnergy and an individual performance modifier. In 2012, Mr. McFarland delivered strong financial results despite decliningwholesale power prices, managed our hedging program, developed our resource adequacy program and was instrumental inour response to the CSAPR. Given these significant accomplishments and other achievements (including his restructuringof our operations team at Luminant), the O&C Committee approved an individual performance modifier that increased Mr.McFarland's incentive award.Discretionary Cash BonusesThe O&C Committee, in its discretion, may from time to time provide special awards to our executive officers, includingthe Named Executive Officers in connection with their contribution to our achievements. In February 2012, in recognition ofMr. Campbell's and Mr. McFarland's performance in connection with EFH Corp. and its subsidiaries' strategic and operationalresponses to federal environmental regulations and activities, the O&C Committee approved discretionary cash bonuses for eachin the amount of $500,000 and $150,000, respectively, which were paid in March 2012. In September 2012, Mr. Keglevicreceived $500,000 as the second and fimal payment ofa discretionary cash bonus he was granted in connection with his contributionto our liability management program.193 Table of ContentsLong- Term Incentive AwardsLong-Term Cash IncentiveOur long-term cash incentive awards are designed to provide incentive to our Named Executive Officers to achieve topoperational and financial performance because the awards are based on either a percentage of the executive officer's annualperformance-based cash bonus or the achievement of management EBITDA targets. The following long-term cash incentiveawards currently affect our Named Executive Officers' total compensation for 2012:Initial LTI Award -granted in 2009 and earned by each of our Named Executive Officers in 2011, the Initial LTI Award("Initial LTI Award") entitled each Named Executive Officer to receive on September 30,2012, if such Named ExecutiveOfficer remained employed by EFH Corp. on such date a one-time, lump-sum cash payment equal to 75% (100% withrespect to Mr. Young) of the aggregate annual cash incentive award received by such Named Executive Officers forfiscal years 2009, 2010, and 2011;2011 LT] Award -granted in 2011 and earned by each of our Named Executive Officers in 2011, the 2011 LTI Award("2011 LTI Award") entitled each Named Executive Officer to receive an amount between $650,000 and $1,300,000($750,000 and $1,500,000 with respect to Mr. Young) based upon the amount of management EBITDAactually achievedby EFH Corp. as compared to the management EBITDA threshold and target amounts previously set by the O&CCommittee for the 2011 fiscal year, one-half of which was paid on September 30, 2012, and one-half of which will bepaid on September 30, 2013 if such Named Executive Officer remains employed by EFH Corp. on such date (withexceptions in limited circumstances); and2015 LTI Award -granted in 2011, provides each Named Executive Officer the opportunity to earn between $500,000and $1,000,000 ($1,350,000 and $2,700,000 with respect to Mr. Young) in each of 2012,2013, and 2014, with the amountof the award for each year to be determined based upon the amount of management EBITDA actually achieved by EFHCorp. as compared to the management EBITDA threshold and target amounts previously set by the O&C Committee,in each case, for the years ended December 31, 2012, 2013, and 2014. Payment of the 2015 LTI Award will be deferreduntil March 2015 and is conditioned upon the Named Executive Officer's continued employment with EFH Corp. onsuch date (with exceptions in limited circumstances).The table below sets forth the Initial LTI Award and 2011 LTI Award earned by each Named Executive Officer in 2011, andthe amounts paid on September 30, 2012 and to be paid September 30, 2013, respectively, in connection therewith if such NamedExecutive Officer remains employed by EFH Corp. on such date (with exceptions in limited circumstances) as well as the portionof the 2015 LTI Award earned by each Named Executive Officer in 2012, and the amounts to be paid in March 2015 if such NamedExecutive Officer remains employed by EFH Corp. on such date (with exceptions in limited circumstances):2012 Portion of Amount Amount To Be Amount To BeInitial LTI 2011 LTI Award LTI Award Distributed Distributed DistributedName Award Earned Earned Earned 9/30/2012 9/30/2013") 3/2015John F. Young $5,240,600 $1,500,000 $2,700,000 $5,990,600 $750,000 $2,700,000Paul M. Keglevic $1,795,144 $1,300,000 $1,000,000 $2,445,144 $650,000 $1,000,000David A. Campbell2ý $1,887,638 $1,300,000 $1,000,000 $2,537,638 $0 $0James A. Burke $1,901,293 $1,300,000 $1,000,000 $2,551,293 $650,000 $1,000,000M.A. McFarland $1,832,765 $1,300,000 $1,000,000 $2,482,765 $650,000 $1,000,000(1) The amount to be distributed is subject, in limited circumstances, to pro-ration in the event of the Named Executive Officer'stermination without "cause" or resignation for "good reason" (including following a change of control of EFH Corp.), or inthe event of such Named Executive Officer's death or disability, as described in greater detail in the Named Executive Officer'semployment agreement.(2) Because Mr. Campbell resigned voluntarily, effective January 1, 2013, he forfeited the 2011 LTI Award to be distributedSeptember 30, 2013 and the 2015 LTI Award in its entirety.In connection with the grant of the 2011 LTI Award and 2015 LTI Award, and in consideration of the retention incentive thatthe 2011 LTI Award and the 2015 LTI Award provide to our Named Executive Officers, the O&C Committee approved the provisionof irrevocable standby letters of credit under the terms of the TCEH Senior Secured Credit Facilities to each Named ExecutiveOfficer. These letters of credit support EFH Corp.'s payment obligations under the 2011 LTI Award and 2015 LTI Award.194 Table of ContentsLong- Term Equity IncentivesWe believe it is important to strongly align the interests of our executive officers and stakeholders through equity-basedcompensation. The purpose of the 2007 Stock Incentive Plan, which was previously approved by our Board, is to:" promote our long-term financial interests and growth by attracting and retaining management and other personnel withthe training, experience and ability to make a substantial contribution to our success;" motivate management and other personnel by means of growth-related incentives to achieve long-range goals; and" align the long-term interests of our stakeholders and the interests of our executive officers through opportunities for stock(or stock-based) ownership in EFH Corp.Because we are a privately-held company, our 2007 Stock Incentive Plan does not contain provisions, and we do not haveany equity grant practices in place, designed to coordinate the granting of equity awards with the public release of materialinformation. Please refer to the Grants of Plan-Based Awards -2012 table, including the footnotes thereto, and the OutstandingEquity Awards at Fiscal Year-End-2012 table, including the footnotes thereto, for a more detailed description of the outstandingRestricted Stock Units held by each of the Named Executive Officers.Annual Grant of Restricted Stock Units:Pursuant to the terms of their employment agreements, each Named Executive Officer is entitled to an annual grant ofRestricted Stock Units ("Annual RSUs"), which cliff vest in 2014. The O&C Committee approved the Annual RSU grant for2012 on February 15, 2012, which resulted in each Named Executive Officer receiving 500,000 Restricted Stock Units (1,500,000with respect to Mr. Young and 666,667 with respect to Mr. Campbell) on February 29, 2012. The award of Annual RSUs for 2013is expected to be made following, and in connection with, the February meeting of the O&C Committee. In the future, we maymake additional discretionary grants of equity-based compensation to reward high performance or achievement. Please refer tothe Grants of Plan-Based Awards -2012 table, and the Outstanding Equity Awards at Fiscal Year-End-2012 table, including thefootnotes to these tables, for a more detailed description of the RSUs granted to and held by each of the Named Executive Officersduring, and at the end of, our last fiscal year.195 Table of ContentsOther Elements of CompensationGeneralOur executive officers generally have the opportunity to participate in certain of our broad-based employee compensationplans, including our Thrift (401 (k)) Plan, and health and welfare plans. In August 2012, EFH Corp. approved certain amendmentsto its retirement plan that resulted in the splitting off of, termination, vesting in, and distribution of all accrued benefits for certainparticipants under the Retirement Plan, including certain of our Named Executive Officers. Please refer to the footnotes to theSummary Compensation table for a more detailed description of our Thrift Plan, and the narrative that follows the Pension Benefitstable for a more detailed description of the modifications to our Retirement Plan and Supplemental Retirement Plan.PerquisitesWe provide our executives with certain perquisites on a limited basis. Those perquisites that exist are generally intended toenhance our executive officers' ability to conduct company business. These benefits include financial planning, preventive healthmaintenance, reimbursement for certain club memberships and certain spousal travel expenses. Expenditures for the perquisitesdescribed below are disclosed by individual in footnote 7 to the Summary Compensation Table. The following is a summary ofperquisites offered to our Named Executive Officers that are not available to all employees:Executive Financial Planning: We pay for our executive officers to receive financial planning services. This service isintended to support them in managing their financial affairs, which we consider especially important given the high level of timecommitment and performance expectation required of our executive officers. Furthermore, we believe that such service helpsensure greater accuracy and compliance with individual tax regulations by our executive officers.Health Services: We pay for our executive officers to receive annual physical health exams. Also, in 2012, we purchasedan annual membership for Messrs. Young and Keglevic to participate in a comprehensive health plan that provides anytime personaland private physician access and health care. The health of our executive officers is important given the vital leadership role theyplay in directing and operating the company. Our executive officers are important assets of EFH Corp., and these benefits aredesigned to help ensure their health and long-term ability to serve our stakeholders.Club Memberships: We reimburse certain of our executives for the cost of golf and social club memberships, providedthat the club membership provides for a business-use opportunity, such as client networking and entertainment. The clubmembership reimbursements are provided to assist the executives in cultivating business relationships.Spouse Travel Expenses: From time to time, we pay for an executive officer's spouse to travel with the executive officerwhen taking a business trip.Payments Contingent Upon a Change of Control of EFH Corp.We have entered into employment agreements with each of our Named Executive Officers. Each of the employmentagreements provides that certain payments and benefits will be paid upon the expiration or termination of the agreement undervarious circumstances, including termination without cause, resignation for good reason and termination of employment withina fixed period of time following a change in control of EFH Corp. We believe these provisions are important in order to attract,motivate, and retain the caliber of executive officers that our business requires and provide incentive for our executive officers tofully consider potential changes that are in our and our stakeholders' best interest, even if such changes could result in the executiveofficers' termination of employment. For a description of the applicable provisions in the employment agreements of our NamedExecutive Officers see "Potential Payments upon Termination or Change in Control."OtherUnder the terms of Mr. Young's employment agreement, we have purchased a 10-year term life insurance policy (to be paidto a beneficiary of his choice) in an insured amount equal to $10,000,000. In addition, under the terms of Mr. Young's employmentagreement we have agreed to provide a supplemental retirement plan, with a value of $3,000,000 if Mr. Young remains employedby EFH Corp. through December 31, 2014 (with customary exceptions for death, disability and leaving for "good reason" ortermination "without cause"). Each of these benefits was included as a part of Mr. Young's compensation package to set hiscompensation in a manner that is competitive with compensation for chief executive officers in companies we consider our peers.196 Table of ContentsAccounting and Tax ConsiderationsAccounting ConsiderationsBecause our common stock is not registered or publicly traded, the O&C Committee does not generally consider the effectof accounting principles when making executive compensation decisions.Income Tax ConsiderationsSection 162(m) of the Code limits the tax deductibility by a publicly held company of compensation in excess of $1 millionpaid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer.Because EFH Corp. is a privately-held company, Section 162(m) will not limit the tax deductibility of any executive compensationfor 2012, and the O&C Committee does not take it into account when making executive compensation decisions.Organization and Compensation Committee ReportThe O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth inthis Form 10-K. Based on this review and discussions, the committee recommended to the Board that the Compensation Discussionand Analysis be included in this Form 10-K.Organization and Compensation CommitteeDonald L. Evans, ChairArcilia C. AcostaMarc S. LipschultzKenneth Pontarelli197 Table of ContentsSummary Compensation Table-2012The following table provides information for the fiscal years ended December 31, 2012, 2011 and 2010 regarding theaggregate compensation paid to our Named Executive Officers.Change inNon- Pension ValueEquity andIncentive Non-qualifiedPlan Deferred All OtherStock Option Compen- Compensation Compen-Name and Principal Salary Bonus Awards Awards sation Earnings sation TotalPosition Year (M) ($) ($)(4) (M) (s)(5) ($)16) (s)(7) (S)John F. Young 2012 1,200,000 -525,000 -4,968,000 4,337 72,848 6,770,185President & CEO of 2011 1,200,000 -5,347,500 -8,468,600 3,123 105,484 15,124,707EFH Corp. 2010 1,200,000 --3,405,000 2.043,600 2,761 210,826 6,862,187Paul M. Keglevice') 2012 650,000 50,000 175,000 -2,009,418 4,403 4,326,288 7,215.109EVP & Chief 2011 650,000 1,050,000 1,782.500 -3,890,744 3,788 73,437 7,450,469Financial Officer of 2010 650,000 50,000 --933.,725 3,185 39,416 1,676,326EFH Corp.David A. Campbellt2) 2012 700,000 500,000 233,333 -1,785,400 102,048 30,693 3,351,474Former President & 2011 700,000 -2,728.000 -4,080,138 118,810 40,223 7,667,171CEO of Lurninant 2010 700,000 --981,750 76,485 17,911 1,776,146James A. Burke 2012 630,000 -175,000 -2,033,783 82,916 32,977 2,954,676EVP-EFH Corp. & 2011 630,000 -1,637,250 -3,946,709 89,310 55,298 6,358,567President & CEO of 2010 630,000 ---932,841 76,713 17,305 1,656,859TXU EnergyM.A. McFarland (3) 2012 600,000 150,000 175,000 -1,963,900 -43,406 2,932,306EVP-EFH Corp. & 2011 600,000 350,000 1,519,000 -3,940,605 -63,602 6,473,207President & Chief 2010 600,000 ---948,090 -17,418 1,565,508Executive Officer ofLuminant(1) Mr. Keglevic's employment agreement provides that we pay him a signing bonus equal to $550,000 as follows: (i) $250,000payable in July 2008; (ii) $150,000 payable in July 2009 and (iii) $50,000 payable in July 2010, 2011 and 2012. Theamount for 2012 reported as "Bonus" for Mr. Keglevic represents the 2012 portion of his signing bonus. The amountreported as "Bonus" in 2011 includes the discretionary cash bonus Mr. Keglevic was granted in 2011 in connection withhis contributions to our liability management program, half of which was paid in 2011 and half of which was paid inSeptember 2012.(2) In December 2012, Mr. Campbell notified us of his resignation, which was effective January 1,2013. The amount reportedas "Bonus" for Mr. Campbell represents a $500,000 special award granted in connection with his contribution to Luminant'sstrategic and operational responses to federal environmental regulations and activities, which was paid in March 2012.(3) On January 1,2013, Mr. McFarland assumed the role of President and Chief Executive Officer of Luminant. The amountfor 2012 reported as "Bonus" for Mr. McFarland represents a S 150,000 special award granted in connection with hiscontribution to Luminant's strategic and operational responses to federal environmental regulations and activities, whichwas paid in March 2012.(4) The amounts reported as "Stock Awards" represent the grant date fair value of the 2012 Annual RSUs. These awardscliff vest in September of 2014. The expense for these awards will be recognized in accordance with FASB ASC Topic718. Additional assumptions relating to the valuation are described in the footnotes to the Grants of Plan-Based AwardsTable.(5) The amounts in 2012 reported as "Non-Equity Incentive Plan Compensation" were earned by the executive officers in2012 under the EAIP, and the 2015 LTI Award. In December 2012, the O&C Committee approved the payment of, andwe paid, 80% of the target EAIP bonus for each EAIP participant, including the Named Executive Officers. The remainingportion of each participant's EAIP bonus will be based on our annual financial and operational performance and theindividual performance of each EAIP participant and will be paid in March of 2013. Though a portion of the 2015 LTIAward was earned in 2012, it will not be paid until March 2015 and is conditioned upon the Named Executive Officer'scontinued employment (with exceptions in limited circumstances). The amounts for each Named Executive Officer areas follows: (a) for Mr. Young, $2,268,000 for the EAIP and $2,700,000 for the 2015 LTI Award; (b) for Mr. Keglevic$1,009,418 for the EAIP and $1,000,000 for the 2015 LTI Award; (c) for Mr. Campbell, $785,400 for the EAIP and$1,000,000 for the 2015 LTI Award; (d) for Mr. Burke $1,033,783 for the EAIP and $1,000,000 for the 2015 LTI Award;(e) for Mr. McFarland $963,900 for the EAIP and $1,000,000 for the 2015 LTI Award. The deferred amounts of the 2015LTI Awards are reported in the table entitled "Nonqualified Deferred Compensation -2012" under the headings "RegistrantContributions in Last FY" and "Aggregate Balance at Last FYE." Mr. Campbell will receive $785,400 in connection withhis EAIP pursuant to the terms of his employment agreement; however, he will not receive the $1,000,000 he earned inconnection with his 2015 LTI Award.198 Table of Contents(6) The amounts in 2012 reported under "Change in Pension Value and Nonqualified Deferred Compensation Earnings"include the aggregate increase in actuarial value of the EFH Retirement Plan and Supplemental Retirement Plan. For amore detailed description of EFH Corp.'s retirement plans, including the transfers of certain assets and liabilities fromthe Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan,please refer to the narrative that follows the table entitled "Pension Benefits -2012". There are no above-market earningsfor nonqualified deferred compensation that is deferred under the Salary Deferral Program.(7) The amounts for 2012 reported as "All Other Compensation" are attributable to the Named Executive Officer's receiptof compensation as described in the following table:Perquisites(.)Matching PremiumContribut Payments Taxableion to Cost of on Life Personal ReimbursThrift Letter of Attorney's Insurance Physical Financial Country Executive ement forName Plan bI Credit"0 Fees Policy Careldl Planning4e" Club Dues Physical Spouse Other TotalJohn F.Young $15,000 $11,968 $17,185() $10,000 $10,730 $7,779 $186 $72,848Paul M.Keglevic $14,729 $5,264 $3,93819 $15,000 $22,7$1,522 $4,263,123(" $4,326,288David A.Campbell $12,667 $5,124 $10,730 $2,172 $30,693James A.Burke $14,638 $5,264 $9,410 $3,665 $32,977M.A.McFarland $15,000 $5,264 $20,6380j $2,504 $43,406(a) For purposes of preparing this table, all perquisites are valued on the basis of the actual cost to EFH Corp.(b) Our Thrift Plan allows participating employees to contribute a portion of their regular salary or wages to the plan. Underthe EFH Thrift Plan, EFH Corp. matches a portion of an employee's contributions. This matching contribution is 100%of each Named Executive Officer's contribution up to 6% of the named Executive Officer's salary up to the IRS annualcompensation limit. All matching contributions are invested in Thrift Plan investments as directed by the participant.(c) For a discussion of the Letters of Credit received by our Named Executive Officers, please see "Compensation Discussionand Analysis -Long-Term Incentive Awards -Long-Term Cash Incentive."(d) For a discussion of the Personal Physical Care received by certain of our Named Executive Officers, please see"Compensation Discussion and Analysis -Other Elements of Compensation -Perquisites -Health Services."(e) For a discussion ofthe Financial Planning received by certain of our Named Executive Officers, please see "CompensationDiscussion and Analysis -Other Elements of Compensation -Perquisites -Executive Financial Planning."(f) For further discussion of the life insurance policy purchased for Mr. Young pursuant to the terms of his employmentagreement, please see "Compensation Discussion and Analysis -Other Elements of Compensation -Other."(g) The amounts received by Mr. Keglevic in 2012 for attorneys' fees represent the attorneys' fees incurred in connectionwith the Second Amendment to his Deferred Share Agreement and paid on his behalf by us.(h) The amounts received by Mr. Keglevic in 2012 for the cost of his country club membership include a pro-rated portionof his initiation fee.(i) The amounts reported in the "Other" column for Mr. Keglevic include $3,200,000 paid pursuant to his Second Amendmentto Deferred Share Agreement and $1,063,123 in additional taxes under Section 409A of the Code associated with thispayment.(j) The amounts received by Mr. McFarland in 2012 for the cost of his country club membership include a pro-rated portionof his initiation fee.199 Table of ContentsGrants of Plan-Based Awards -2012The following table sets forth information regarding grants ofcompensatory awards to our Named Executive Officers duringthe fiscal year ended December 31, 2012.All OtherStock Grant DateAwards: # Fair ValueEstimated Possible Payouts Under of Shares of of StockNon-Equity Incentive Plan Stock or Unit and OptionAwards (#) Awards(3)Date ofGrant Board Threshold Target MaximumName Date Action (S) (M) (s)John F. Young 2/15/2012") 600,000 1,200.000 2,400,0002/29/2012 2/15/2012 1,500.000(2) 525,000Paul M. Keglevic 2/15/2012(') 276,250 552,500 1,105,0002/29/2012 2/15/2012 500,000(2) 175,000David A. Campbell'4) 2/1 5/2012(') 297,500 595,000 1,190,0002/29/2012 2/15/2012 666,667() 233,333James A. Burke 2/15/2012... 267,750 535,500 1,071,000 (2)2/29/2012 2/15/2012 500,000- 175,000M.A. McFarland 2/15/2012(') 255,000 510,000 1,020,000 00,2/29/2012 2/15/2012 500,00- 175,000(1) Represents the threshold, target and maximum amounts available under the EAIP for each Named Executive Officer. Amountsrepresenting 80% of the estimated target awards for the 2012 plan year were paid in December 2012. The remaining portionof the actual awards are expected to be paid in March 2013. Each payment is reported in the Summary Compensation Tableunder the heading "Non-Equity Incentive Plan Compensation," and is described above under the section entitled "AnnualPerformance Bonus -EAIP".(2) Represents grants ofAnnual RSUs, which cliff-vest September 30,2014, as described above under the section entitled "Long-Term Equity Incentives." The vesting of the Annual RSUs is contingent upon the Named Executive Officer's continuedemployment with EFH Corp. on September 30, 2014, subject, in limited circumstances, to pro-ration in the event of theNamed Executive Officer's termination without "cause" or resignation for "good reason," or in the event of such NamedExecutive Officer's death or disability, each as described in greater detail in the Named Executive Officer's employmentagreement, and complete vesting in the event of a change in control (as that term is defined in the 2007 Stock Incentive Plan)of EFH Corp., such that all ungranted Annual RSUs that would have been granted to the Named Executive Officer in eachof 2012 and 2013 will be immediately granted and vested.(3) The amounts reported under "Grant Date Fair Value of Stock and Option Awards" represent the grant date fair value ofrestricted stock units related to the grant of Annual RSUs.(4) Because Mr. Campbell voluntarily resigned, effective January 1, 2013, he forfeited his Annual RSUs as described in thistable. However, in accordance with the terms of his employment agreement as more fully described above under the sectionentitled "Annual Performance Bonus -EAIP, Actual Award", Mr. Campbell will receive the remaining portion of his EAIPaward in March 2013.For a discussion of certain material terms of the employment agreements with the Named Executive Officers, please see"Assessment of Compensation Elements" and "Potential Payments upon Termination or Change in Control."200 Table of ContentsOutstanding Equity Awards at Fiscal Year-End- 2012# of Shares or Units of Stock That Market Value of Shares or Units ofName Have Not Vested") Stock That Have Not Vested (3)John F. Young 7,500,000 $3,000,000Paul M. Keglevic 2,500,000 $1,000,000David A. Campbell(2) 3,733,334 $1,493,334James A. Burke 2,325,000 $930,000M.A. McFarland 2,200,000 $880,000(1) The amounts reported for each Named Executive Officer in the "# of Shares or Units of Stock that Have Not Vested" columninclude Restricted Stock Units ("RSUs") granted pursuant to our 2007 Stock Incentive Plan. The RSUs are scheduled tocliff vest on September 30, 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp.through that date (with exceptions in limited circumstances) as described above in the section entitled "Long-Term EquityIncentives."(2) Because Mr. Campbell voluntarily resigned, effective January 1, 2013, he forfeited his RSUs.(3) There is no established public market for our common stock. Our board of directors values our common stock on an annualbasis (in December of each year). The valuation is primarily done to set the exercise or base price of awards granted underthe 2007 Stock Incentive Plan. In determining the valuation of our common stock, our Board, with the assistance of thirdparty valuation experts, utilizes several valuation techniques, including discounted cash flow and comparable companyanalysis. The amount reported above under the heading "Market Value of Shares or Units of Stock That Have Not Vested"reflects the fair market value (as determined by our Board) of our common stock as of December 31, 2012.201 Table of ContentsPension Benefits -2012The table set forth below illustrates present value on December 31, 2012 of each Named Executive Officer's RetirementPlan benefit and benefits payable under the Supplemental Retirement Plan, based on their years of service and remunerationthrough December 31, 2012:Number of Years PV of Accumulated Payments DuringName Plan Name Credited Service (#)(1) Benefit (S) Last Fiscal Year ($)('2)John F. Young Retirement Plan --168,173Supplemental Retirement Plan ---Paul M. Keglevic Retirement Plan --143,874Supplemental Retirement Plan ---David A. Campbell(2) Retirement Plan 7.3333 -203,382Supplemental Retirement Plan 10.2500 243,861 -James A. Burke Retirement Plan 6.9167 -189,886Supplemental Retirement Plan 6.9167 197,117 -M.A. McFarland Retirement Plan --Supplemental Retirement Plan(1) Because they were hired after October 1,2007, Messrs. Young, Keglevic and McFarland are generally not eligible to participatein our Retirement Plan. However, Messrs. Young and Keglevic participate in the cash balance component of the RetirementPlan solely with respect to amounts that were transferred from the Salary Deferral Program and/or the Supplemental RetirementPlan in 2009 and in 2012.(2) The amounts reported as "Payments During Last Fiscal Year" reflect the balance in each Named Executive Officer's RetirementPlan account, which was distributed in December 2012 in accordance with the amendments to the Retirement Plan discussedbelow.Until the fourth quarter of 2012, EFH Corp. and its participating subsidiaries maintained the Retirement Plan for certain ofour Named Executive Officers and other non-union eligible employees, which was intended to be qualified under applicableprovisions of the Code and covered by ERISA. The Retirement Plan contained both a traditional defined benefit component anda cash balance component. Only employees hired before January 1, 2002 were eligible to participate in the traditional definedbenefit component. Because none of our Named Executive Officers were hired before January 1, 2002, no Named ExecutiveOfficer participated in the traditional defined benefit component. Employees hired after January 1, 2002 and before October 1,2007 were eligible to participate in the cash balance component and receive monthly contribution credits based on age and yearsof accredited service. In addition, effective December 31, 2009 and September 20, 2012, certain assets and liabilities under theSalary Deferral Program and the Supplemental Retirement Plan were transferred to the cash balance component of the RetirementPlan. Because they were hired in 2004, Messrs. Campbell and Burke participated in the cash balance component of the RetirementPlan. Following the December 2009 transfers under the Salary Deferral Program and Supplemental Retirement Plan, Messrs.Young and Keglevic also participated in the cash balance component of the Retirement Plan.Under the cash balance component of the Retirement Plan, hypothetical accounts were established for participants andcredited with monthly contribution credits equal to a percentage of the participant's compensation (3.5%, 4.5%, 5.5% or 6.5%depending on the participant's combined age and years of accredited service), contribution credits equal to the amounts transferredfrom the Salary Deferral Program and/or the Supplemental Retirement Plan in 2009 and 2012, and interest credits on all of suchamounts based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year.In August 2012, EFH Corp. approved certain amendments to the Retirement Plan. These amendments resulted in: (1) thesplitting off of assets and liabilities under the Retirement Plan associated with employees of Oncor and all retirees and terminatedvested participants of EFH Corp. and its subsidiaries (including discontinued businesses) to a new plan sponsored and administeredby Oncor (the Oncor Plan); (2) the maintaining of assets and liabilities associated with union employees of EFH Corp.'s competitivebusinesses under the current plan; (3) the splitting off of assets and liabilities under the plan associated with active employees ofEFH Corp.'s competitive businesses other than union employees to a terminating plan, freezing benefits and vesting all accruedplan benefits for these participants; and (4) the termination of, distributions of benefits under, and settlement of, all of EFH Corp.'sliabilities under the terminating plan. Because Messrs. Young, Keglevic, Campbell and Burke participated in the cash balancecomponent of the Retirement Plan, each was entitled to a distribution of the balance in his account under the Retirement Plan inDecember 2012.202 Table of ContentsThe Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited bythe Code or the definition of earnings under the Retirement Plan. The benefits under the Supplemental Retirement Plan werefrozen in September, 2012. Under the Supplemental Retirement Plan, retirement benefits are calculated in accordance with thesame formula used under the cash balance component ofthe Retirement Plan. Participation in EFH Corp.'s Supplemental RetirementPlan was limited to employees of all of its businesses other than Oncor, who were employed by EFH Corp. (or its participatingsubsidiaries) on or before October 1, 2007. In connection with the freezing of benefits under the Supplemental Retirement Plan,no additional contributions will be made under the Supplemental Retirement Plan; however, the amounts existing thereunder willbe paid out in accordance with the terms of the Supplemental Retirement Plan.Benefits accrued under the Supplemental Retirement Plan after December 31,2004, are subject to Section 409A of the Code.Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirementsof Section 409A and related guidance.The present value of the accumulated benefit for the Retirement Plan (the cash balance component) was calculated as thevalue of their cash balance account projected to age 65 at an assumed growth rate of 3.75% and then discounted back to December31, 2012 at 4.3%. No mortality or turnover assumptions were applied.203 Table of ContentsNonqualified Deferred Compensation -2012")The following table sets forth information regarding plans that provide for the deferral of the Named Executive Officers'compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2012:Registrant Aggregate AggregateContributions in Aggregate Earninps Withdrawals/ Balance atName Last FY ($).Z. in Last FY ($)43 Distributions ($)(4) Last FYE ($)"'John F. Young $2,700,000 $41,544 ($5,990,600) $3,668,736Paul M. Keglevic $1,000,000 $434 ($2,995,144) $1,650,000David A. Campbell() $1,000,000 $14,191 ($2,635,073) $1,950,814James A. Burke $1,000,000 $32,940 ($2,614,336) $2,032,947M.A. McFarland $1,000,000 $- ($2,482,765) $1,650,000(1) The amounts reported in the Nonqualified Deferred Compensation table include deferrals and the company match under theSalary Deferral Program. Under EFH Corp.'s Salary Deferral Program each employee of EFH Corp. and its participatingsubsidiaries who is in a designated job level and whose annual salary is equal to or greater than an amount established underthe Salary Deferral Program ($115,000 for the program year beginning January 1, 2012) may elect to defer up to 50% ofannual base salary, and/or up to 85% of the annual incentive award, for a maturity period of seven years, for a maturity periodending with the retirement of such employee, or for a combination thereof. EFH Corp. provided no matching contributionsfor 2012. Deferrals are credited with earnings or losses based on the performance of investment alternatives under the SalaryDeferral Program selected by each participant. At the end of the applicable maturity period, the trustee for the Salary DeferralProgram distributes the deferred compensation, any vested matching awards and the applicable earnings in cash as a lumpsum or in annual installments at the participant's election made at the time of deferral. EFH Corp. is financing the retirementoption portion of the Salary Deferral Program through the purchase of corporate-owned life insurance on the lives ofparticipants. The proceeds from such insurance are expected to allow EFH Corp. to fully recover the cost of the retirementoption. Since 2010, certain executive officers, including the Named Executive Officers, are not eligible to participate in theSalary Deferral Program, and beginning in 2013, no employee, other than Oncor employees, will be eligible to participatein the Salary Deferral Program. As of December 2012, Messrs. Young, Campbell and Burke had balances in the SalaryDeferral Program, which will be distributed according to the terms of the plan.(2) The amounts reported as "Registrant Contributions in Last FY" include the portion of the 2015 LTI Award based on 2012management EBITDA, which will be paid in March 2015 (subject to certain conditions and exceptions in limitedcircumstances) for all Named Executive Officers.(3) The amounts reported as "Aggregate Earnings in Last FY" include the interest earnings on the Salary Deferral Programamounts for each Named Executive Officer.(4) The amounts reported as "Aggregate Withdrawals/Distributions" (i) include the Initial LTI Award and one-half of the 2011LTI Award for all Named Executive Officers, which were paid in September 2012, but (ii) exclude amounts transferred fromthe Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan asof September 20, 2012 for Messrs. Young ($124,639), Keglevic ($88,089), Campbell ($5,150) and Burke ($9,271). Theamount reported as "Aggregate Withdrawals/Distributions" for Mr. Keglevic also includes the payment of $500,000 as thesecond and final payment of a discretionary cash bonus he was granted in connection with his contributions to our liabilitymanagement program and the $50,000 portion of his signing bonus he received in July 2012. The amount reported as"Aggregate Withdrawals/Distributions" for Messrs. Campbell and Burke include distributions from the Salary Deferral Planin the amounts of $93,810 and $59,780, respectively.(5) The amounts reported as "Aggregate Balance at Last FYE" include the following for all Named Executive Officers: (i) theportion of the 2011 LTI Award, which will be paid in September 2013 (subject to exceptions in limited circumstances), (ii)the portion of the 2015 LTI Award based on 2012 management EBITDA, and (iii) any amounts contributed under the SalaryDeferral Plan. The amounts reported as "Aggregate Balance at Last FYE" for Messrs. Campbell and Burke also include thefair market value of deferred shares (492,750 shares with respect to Mr. Campbell and 443,474 shares with respect to Mr.Burke) that each is entitled to receive on the earlier to occur of their termination of employment or a change of control ofEFH Corp.(6) Because Mr. Campbell voluntarily resigned, effective January 1, 2013, he forfeited the portion of his 2011 LTI Award to bepaid in September 2013 and the portion of his 2015 LTI Award based on 2012 management EBITDA as described in footnotes2 and 5 of this Nonqualified Deferred Compensation -2012 Table. Upon his resignation, Mr. Campbell received 492,750shares of EFH Corp. common stock pursuant to the terms of his Deferred Share Agreement. Accordingly, upon his resignation,Mr. Campbell forfeited $1,650,000 of the amount reported in the "Aggregate Balance at Last FYE" column.204 Table of ContentsPotential Payments upon Termination or Change in ControlThe tables and narrative below provide information for payments to each of the Named Executive Officers (or, as applicable,enhancements to payments or benefits) in the event of his termination, including if such termination is voluntary, for cause, as aresult of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection witha change in control.The information in the tables below is presented assuming termination of employment as of December 31, 2012.Employment Arrangements with Contingent PaymentsAs of December 31, 2012, each of Messrs. Young, Keglevic, Campbell, Burke and McFarland had employment agreementswith change in control and severance provisions. With respect to each Named Executive Officer's employment agreement, achange in control is generally defined as (i) a transaction that results in a sale of substantially all of our assets or capital stock toanother person who is not an affiliate of any member of the Sponsor Group and such person having more seats on our Board thanthe Sponsor Group, (ii) a transaction that results in a person not in the Sponsor Group owning more than 50% of our commonstock and such person having more seats on our Board than the Sponsor Group or (iii) a transaction that results in the SponsorGroup owning less than 20% of our common stock and the Sponsor Group not being able to appoint a majority of the directorsto our Board.Each Named Executive Officer's employment agreement includes customary non-compete and non-solicitation provisionsthat generally restrict the Named Executive Officer's ability to compete with us or solicit our customers or employees for his ownpersonal benefit during the term of the employment agreement and 24 months (with respect to Mr. Young) or 18 months (withrespect to Messrs. Keglevic, Campbell, Burke and McFarland) after the employment agreement expires or is terminated.Each of our Named Executive Officers has been granted long-term cash incentive awards, including the 2011 LTI Awardand 2015 LTI Award, as more fully described above in "Long-Term Cash Incentive." In the event of such Named ExecutiveOfficer's termination without cause, resignation for good reason or termination due to death or disability (or in certain circumstanceswhen the Named Executive Officer's employment term is not extended) the 2011 LTI Award and 2015 Award will vest and becomepayable, to the extent earned, on a pro-rated basis. In the event of termination without cause or resignation for good reasonfollowing a change in control of EFH Corp., the 2011 LTI Award and 2015 LTI Award will vest and become payable, to the extentearned, on the same pro-rata basis; however the pro-rata calculation will include the actual management EBITDA for any earned,but unpaid, fiscal years prior to termination and the target level of management EBITDA, without regard to the actual achievementof management EBITDA, for any subsequent applicable years.Each of our Named Executive Officers received in 2012, and has the opportunity to receive in 2013, a grant ofAnnual RSUs,following the approval of the O&C Committee at its February O&C Committee meeting. In the event of such Named ExecutiveOfficer's termination without cause, resignation for good reason or termination due to death or disability, such year's Annual RSUswill vest on a pro-rata basis based on a ratio, the numerator of which is the length of time of the executive officer's employmentfrom the date of the grant of such year's Annual RSUs to his termination and the denominator of which is the length of time fromthe date of grant of the Annual RSUs to the original vesting date. In the event of a change of control of EFH Corp., all ungrantedAnnual RSUs that would have been made to the executive in 2013 will be immediately granted and vested.In 2011, each of our Named Executive Officers surrendered all of his existing stock options in exchange for a one-time lumpsum grant of Restricted Stock Units (the "Exchange RSUs") granted pursuant to our 2007 Stock Incentive Plan that cliff-vest onSeptember 30, 2014, with exceptions in limited circumstances in exchange for forfeiting all rights in respect of any and all optionsto purchase shares of EFH Corp.'s common stock that had been previously granted to the executive officers under the 2007 StockIncentive Plan. As of December 31, 2012, each of our Named Executive Officers held Exchange RSUs. Under the applicableagreements governing these Exchange RSUs, in the event of such Named Executive Officer's termination without cause orresignation for good reason (or in certain circumstances when the Named Executive Officer's employment term is not extended)following a change in control of EFH Corp., such Named Executive Officer's Exchange RSUs would immediately vest as to 100%of the shares of EFH Corp. common stock subject to such Restricted Stock Units immediately prior to the change in control ofEFH Corp. Additionally, in the event of such Named Executive Officer's termination without cause, resignation for good reasonor termination due to death or disability (or in certain circumstances when the Named Executive Officer's employment term is notextended), such Named Executive Officer's Exchange RSUs will vest on a pro rata basis based on a ratio, the numerator of whichis the length oftime of the Named Executive Officer's employment from the date of the grant of the Exchange RSU to his terminationand the denominator of which is the length of time from the date of grant of the Exchange RSUs to the original vesting date.205 Table of ContentsMessrs. Campbell and Burke are each entitled to receive shares of EFH Corp. common stock (492,750 shares with respectto Mr. Campbell and 443,474 shares with respect to Mr. Burke), pursuant to the terms of their respective deferred share agreements,on the earlier to occur of their termination for any reason or a change in control of EFH Corp.Because Mr. Campbell voluntarily resigned, effective January 1, 2013, he received 492,750 shares of EFH Corp. commonstock and forfeited the remainder of his 2011 LTI Award, his 2015 LTI Award, and his RSUs, as reflected in Table Number 3 below.Excise Tax Gross-UpsPursuant to their employment agreements, if any of our Named Executive Officers is subject to the imposition of the excisetax imposed by Section 4999 of the Code, related to the executive's employment, but the imposition of such tax could be avoidedby approval of our shareholders as described in Section 280G(b)(5)(B) of the Code, then such executive may cause EFH Corp. toseek such approval, in which case EFH Corp. will use its reasonable best efforts to cause such approval to be obtained and suchexecutive will cooperate and execute such waivers as may be necessary so that such approval avoids imposition of any excise taxunder Section 4999. If such executive fails to cause EFH Corp. to seek such approval or fails to cooperate and execute the waiversnecessary in the approval process, such executive shall not be entitled to any gross-up payment for any resulting tax under Section4999. Because we believe the shareholder approval exception to such excise tax will apply, the tables below do not reflect anyamounts for such gross-up payments.206 Table of Contents1. Mr. YoungPotential Payments to Mr. Young upon Termination as of December 31, 2012 (per employment agreement and restrictedstock agreements, each in effect as of December 31, 2012)Without Without Cause OrCause Or For Good Reason InFor Good Connection WithBenefit Voluntary For Cause Death Disability Reason Change in ControlCash Severance $ 4,800,000 $ 7,200,000EAIPt1 $552,000 $ 552,000 $ 552,000 $ 552,000Supplemental Retirement Benefit $ 3,000,000 $ 3,000,000 $ 3,000,000 $ 3,000,000LTI Cash Retention Award:-2011 LTI Award $ 750,000 $ 750,000 $ 750,000 $ 750,000-2015 LTI Award $ 2,700,000 $ 2,700,000 $ 2,700,000 $ 2,700,000LTI Equity Incentive Award:-Annual RSUs $ 511,710 $ 511,710 $ 511,710 $ 1,800,000-Exchange RSUs $ 932,628 $ 932,628 $ 932,628 $ 1,800,000Health & Welfare:-Medical/COBRA $ 36,428 $ 36,428-Dental/COBRA $ 3,088 $ 3,088Totals $552,000 $ 552,000 S 8,446,338 $ 8,446,338 $ 12,733,854 $ 17,289,516(1) The EAIP amount represents the remaining portion of Mr. Young's 2012 EAIP bonus, which is to be paid in March 2013.Mr. Young has entered into an employment agreement that provides for certain payments and benefits upon the expirationor termination of the agreement under the following circumstances:1. In the event of Mr. Young's voluntary resignation without good reason or termination with cause:a. accrued but unpaid base salary and unused vacation earned through the date of termination;b. accrued but unpaid annual bonus earned for the previously completed year;c. unreimbursed business expenses; andd. payment of employee benefits, including equity compensation, if any, to which Mr. Young may be entitled.2. In the event of Mr. Young's death or disability:a. a prorated annual incentive bonus for the year of termination;b. value of supplemental retirement benefit for Mr. Young, payment of which would commence on December 31,2014;c. the pro-rata cash retention award earned prior to the date of termination;d. the pro-rata equity incentive award earned prior to the date of termination; ande. payment of employee benefits, including equity compensation, if any, to which Mr. Young may be entitled.3. In the event of Mr. Young's termination without cause or resignation for good reason:a. a lump sum payment equal to (i) three times his annualized base salary and (ii) a prorated annual incentive bonusfor the year of termination;b. value of supplemental retirement benefit for Mr. Young, payment of which would commence on December 31,2014;c. the pro-rata cash retention award earned prior to the date of termination;d. the pro-rata equity incentive award earned prior to the date of termination;e. payment of employee benefits, including equity compensation, if any, to which Mr. Young may be entitled; andf. certain continuing health care and company benefits.4. In the event of Mr. Young's termination without cause or resignation for good reason within 24 months following achange in control of EFH Corp.:a. a lump sum payment equal to three times the sum of (i) his annualized base salary and (ii) his annual bonus target;b. value of supplemental retirement benefit for Mr. Young, payment of which would commence on December 31,2014;c. the pro-rata cash retention award earned prior to the date of termination;d. all Exchange RSUs;e. all Annual RSUs;f. payment of employee benefits, including equity compensation, if any, to which Mr. Young may be entitled; andg. certain continuing health care and company benefits.207 Table of Contents2. Mr. KeglevicPotential Payments to Mr. Keglevic upon Termination as of December 31, 2012 (per employment agreement and restrictedstock unit agreements, each in effect as of December 31, 2012)Without Without Cause OrCause Or For Good Reason InFor Good Connection WithBenefit VoluntaryM1 For Cause Death Disability Reason Change in ControlCash Severance S 1,852,500 $ 2,405,000EAIP(2) $ 254,150 $ 254,150 254,150 $ 254,150LTI Cash Retention Award:-2011 LTI Award $ 650,000 $ 650,000 $ 650,000 $ 650,000-2015 LTI Award $1,000,000 $ 1,000,000 $ 1,000,000 $ 1,000,000LTI Equity Incentive Award:-Annual RSUs $ 170,570 $ 170,570 $ 170,570 $ 600,000-Exchange RSUs $ 310,876 $ 310,876 $ 310,876 $ 600,000Health & Welfare-Dental/COBRA $ 1,642 $ 1,642Totals $ 254,150 $ 254,150 $ 2,385,596 $ 2,385,596 $ 3,985,588 $ 5,256,642(1) Pursuant to his employment agreement, if Mr. Keglevic voluntarily resigned on or before December 31, 2012, he wouldhave been required to return to EFH Corp. the $50,000 portion of his signing bonus he received in July 2012.(2) The EAIP amount represents the remaining portion of Mr. Keglevic's 2012 EAIP bonus, which is to be paid in March2013.Mr. Keglevic has entered into an employment agreement that provides for certain payments and benefits upon theexpiration or termination of the agreement under the following circumstances:I. In the event of Mr. Keglevic's voluntary resignation without good reason or termination with cause:a. accrued but unpaid base salary and unused vacation earned through the date of termination;b. accrued but unpaid annual bonus earned for the previously completed year;c. unreimbursed business expenses; andd. payment of employee benefits, including equity compensation, if any, to which Mr. Keglevic may be entitled.2. In the event of Mr. Keglevic's death or disability:a. a prorated annual incentive bonus for the year of termination;b. the pro-rata cash retention award earned prior to the date of termination;c. the pro-rata equity incentive award earned prior to the date of termination; andd. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled.3. In the event of Mr. Keglevic's termination without cause or resignation for good reason:a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus forthe year of termination;b. the pro-rata cash retention award earned prior to the date of termination;c. the pro-rata equity incentive award earned prior to the date of termination;d. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled; ande. certain continuing health care and company benefits.4. In the event of Mr. Keglevic's termination without cause or resignation for good reason within 24 months following achange in control of EFH Corp.:a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;b. the pro-rata cash retention award earned prior to the date of termination;c. all Exchange RSUs;d. all Annual RSUs;e. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled; andf. certain continuing health care and company benefits.208 Table of Contents3. Mr. CampbellPotential Payments to Mr. Campbell upon Termination as of December 31, 2012 (per employment agreement, deferredshare agreement and restricted stock unit agreements, each in effect as of December 31, 2012). Because Mr. Campbellresigned, effective January 1, 2013, Mr. Campbell forfeited certain compensation as discussed above and received theamount reflected in the "Total" cell for the "Voluntary" column below.Benefit VoluntaryCash SeveranceEAIP1) $ 309,400Distribution of Deferred Shares(2) $ 197,100LTI Cash Retention Award:-2011 LTI Award-2015 LTI AwardLTI Equity Incentive Award:-Annual RSUs-Exchange RSUsHealth & Welfare-Medical/COBRA-Dental/COBRATotals$ 506,500(1) The EAIP amount represents the remaining portion of Mr. Campbell's 2012 EAIP bonus, which is to be paid in March 2013.(2) The amount reported under the heading "Distribution of Deferred Shares" represents the fair market value of 492,750 sharesof EFH Corp. common stock as of December 31,2012, that Mr. Campbell is entitled to receive, pursuant to the terms of hisdeferred share agreement, on the earlier to occur of his termination of employment for any reason or a change in the effectivecontrol of EFH Corp.Mr. Campbell has entered into an employment agreement that provides for certain payments and benefits upon the expirationor termination of the agreement under the following circumstances:1. In the event of Mr. Campbell's voluntary resignation without good reason or termination with cause:a. accrued but unpaid base salary and unused vacation earned through the date of termination;b. accrued but unpaid annual bonus earned for the previously completed year;c. unreimbursed business expenses; andd. payment of employee benefits, including equity compensation, if any, to which Mr. Campbell may be entitled.209 Table of Contents4. Mr. BurkePotential Payments to Mr. Burke upon Termination as of December 31, 2012 (per employment agreement, deferred shareagreement and restricted stock unit agreements, each in effect as of December 31, 2012)Without Without Cause OrCause Or For Good Reason InFor Good Connection WithBenefit Voluntary For Cause Death Disability Reason Change in ControlCash Severance $ 1,795,500 $ 2,331,000EAIPI' $337,365 $ 337,365 $ 337,365 $ 337,365Distribution of Deferred Shares (2) $177,390 $ 177,390 $ 177,390 $ 177,390 $ 177,390 $ 177,390LTI Cash Retention Award:-2011 LTI Award S 650,000 $ 650,000 $ 650,000 $ 650,000-2015 LTI Award $ 1,000,000 $ 1,000,000 $ 1,000,000 $ 1,000,000LTI Equity Incentive Award:-Annual RSUs $ 170,570 $ 170,570 $ 170,570 $ 600,000-Exchange RSUs $ 274,607 $ 274,607 $ 274,607 $ 530,000Health & Welfare-Medical/COBRA $ 27,885 $ 27,885-Dental/COBRA $ 2,470 $ 2,470Totals $514,755 $ 514,755 $ 2,609,932 $ 2,609,932 $ 4,098,422 $ 5,318,745(1) The EAIP amount represents the remaining portion of Mr. Burke's 2012 EAIP bonus, which is to be paid in March 2013.(2) The amount reported under the heading "Distribution of Deferred Shares" represents the fair market value of 443,474 sharesof EFH Corp. common stock as of December 31, 2012 that Mr. Burke is entitled to receive, pursuant to the terms of hisdeferred share agreement, on the earlier to occur of his termination of employment for any reason or a change in the effectivecontrol of EFH Corp.Mr. Burke has entered into an employment agreement that provides for certain payments and benefits upon the expirationor termination of the agreement under the following circumstances.1. In the event of Mr. Burke's voluntary resignation without good reason or termination with cause:a. accrued but unpaid base salary and unused vacation earned through the date of termination;b. accrued but unpaid annual bonus earned for the previously completed year;c. unreimbursed business expenses; andd. payment of employee benefits, including equity compensation, if any, to which Mr. Burke may be entitled.2. In the event of Mr. Burke's death or disability:a. a prorated annual incentive bonus for the year of termination;b. the pro-rata cash retention award earned prior to the date of termination;c. the pro-rata equity incentive award earned prior to the date of termination; andd. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled.3. In the event of Mr. Burke's termination without cause or resignation for good reason:a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus forthe year of termination;b. the pro-rata cash retention award earned prior to the date of termination;c. the pro-rata equity incentive award earned prior to the date of termination;d. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled; ande. certain continuing health care and company benefits.4. In the event of Mr. Burke's termination without cause or resignation for good reason within 24 months following achange in control of EFH Corp.:a. a lump sum payment equal to two times the sum of(i) his annualized base salary and (ii) his annual bonus target;b. the pro-rata retention award earned prior to the date of termination;c. all Exchange RSUs;d. all Annual RSUs;e. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled; andf. certain continuing health care and company benefits.210 Table of Contents5. Mr. McFarlandPotential Payments to Mr. McFarland upon Termination as of December 31, 2012 (per employment agreement andrestricted stock unit agreements, each in effect as of December 31, 2012)Without Without Cause OrCause Or For Good Reason InFor Good Connection WithBenefit Voluntary For Cause Death Disability Reason Change in ControlCash Severance $ 1,710,000 $ 2,220,000EAIP(t1 $306,000 $ 306,000 $ 306,000 $ 306,000LTI Cash Retention Award:-2011 LTI Award $ 650,000 $ 650,000 $ 650,000 $ 650,000-2015 LTI Award S 1,000,000 S 1,000,000 $ 1,000,000 $ 1,000,000LTI Equity Incentive Award:-Annual RSUs $ 170,570 S 170,570 $ 170,570 $ 600,000-Exchange RSUs $ 248,701 $ 248,701 $ 248,701 $ 480,000Health & Welfare-Medical/COBRA $ 27,885 $ 27,885-Dental/COBRA $ 2,470 $ 2,470Totals $306,000 $ 306,000 $ 2,375,271 $ 2,375,271 $ 3,809,626 $ 4,980,355(1) The EAIP amount represents the remaining portion of Mr. McFarland's 2012 EAIP bonus, which is to be paid in March 2013.Mr. McFarland entered into an employment agreement that provides for certain payments and benefits upon the expirationor termination of the agreement under the following circumstances:1. In the event of Mr. McFarland's voluntary resignation without good reason or termination with cause:a. accrued but unpaid base salary and unused vacation earned through the date of termination;b. accrued but unpaid annual bonus earned for the previously completed year;c. unreimbursed business expenses; andd. payment of employee benefits, including equity compensation, if any, to which Mr. McFarland may be entitled.2. In the event of Mr. McFarland's death or disability:a. a prorated annual incentive bonus for the year of termination;b. the pro-rata cash retention award earned prior to the date of termination;c. the pro-rata equity incentive award earned prior to the date of termination; andd. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled.3. In the event of Mr. McFarland's termination without cause or resignation for good reason:a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus forthe year of termination;b. the pro-rata cash retention award earned prior to the date of termination;c. the pro-rata equity incentive award earned prior to the date of termination;d. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled; ande. certain continuing health care and company benefits.4. In the event of Mr. McFarland's termination without cause or resignation for good reason within 24 months followinga change in control of EFH Corp.:a. a lump sum payment equal to two times the sum of(i) his annualized base salary and (ii) his annual bonus target;b. the pro-rata cash retention award earned prior to the date of termination;c. all Exchange RSUs;d. all Annual RSUs;e. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled; andf. certain continuing health care and company benefits.211 Table of ContentsCompensation Committee Interlocks and Insider ParticipationThere are no relationships among our executive officers, members of the O&C Committee or entities whose executivesserved on the O&C Committee that required disclosure under applicable SEC rules and regulations. For a description of relatedperson transactions involving members of the O&C Committee, see Item 13, entitled "Related Person Transactions."Director CompensationThe table below sets forth information regarding the aggregate compensation paid to the members of the Board during theyear ended December 31, 2012. Directors who are officers of EFH Corp. or members of the Sponsor Group (or their respectiveaffiliates) do not receive any fees for service as a director. EFH Corp. reimburses directors for reasonable expenses incurred inconnection with their services as directors.Fees Earned or All OtherPaid in Cash Stock Awards Option Awards CompensationName (M) (M) ($) (S) Total (S)Arcilia C. Acosta (1) 187,500 100,000 --287,500David Bonderman .....Donald L. Evans (2) --748,000 2,600,000 3,348,000Thomas D. Ferguson .....Brandon Freiman (4) .....Frederick M. Goltz (3) .....James R. Huffines (1)(3) 125,000 100,000 --225,000Scott Lebovitz .....Jeffrey Liaw (3) .....Marc S. Lipschultz .....Michael MacDougall ....Lyndon L. Olson, Jr. (1)(3) 191,667 100,000 --291,667Kenneth Pontarelli .....William K. Reilly (1) 187,500 100,000 --287,500Jonathan D. Smidt .....John F. Young .....Kneeland Youngblood (1) 187,500 100,000 --287,500(1) In the second quarter of 2012, the fees Ms. Acosta and Messrs. Huffines, Olson, Reilly and Youngblood receive for theirservice as directors increased from $150,000 to $200,000 annually. Ms. Acosta and Messrs. Huffines, Olson, Reilly andYoungblood also receive an annual equity award (paid in shares of EFH Corp. common stock) valued at $100,000 (the grantdate fair value) for their service as a director. The amount for Mr. Huffines reflects the pro-rated portion of his fees receivedprior to his resignation on July 2, 2012. The amount for Mr. Olson reflects the pro-rated portion of his fees received priorto his decision not to stand for re-election in October 2012.(2) Effective January 1, 2012, we entered into a consulting agreement with Mr. Evans, pursuant to which Mr. Evans receivesan annual fee of $2,500,000. Under the terms of the consulting agreement, Mr. Evans also received (i) a grant of 4,400,000options to purchase the common stock of EFH Corp. at a strike price of $0.50 per share, which vest in four equal installmentsfrom December 2012 to December 2015, (ii) a modification of the strike price of his 600,000 vested options to purchase thecommon stock of EFH Corp. to $0.50 per share, and (iii) payment by EFH Corp. of(a) $100,000 annually for office expensesand administrative support, (b) up to $200,000 annually in salary payments to a chief of staff, and (c) executive assistantservices in Dallas and Midland, Texas. The amount reported as "All Other Compensation" includes Mr. Evan's annual fee,and annual office expenses and administrative support. The amount reported as "Option Awards" includes the grant datefair value of Mr. Evan's 4,400,000 options and the incremental fair value of his 600,000 options.(3) Messrs Goltz, Huffmes, and Liaw resigned from the Board effective May 3, 2012, July 2, 2012, and December 31, 2012,respectively. On October 26, 2012, Mr. Olson notified the Company that he declined to stand for reelection to the Board.(4) Mr. Freiman was elected to the Board pursuant to the Limited Partnership Agreement of Texas Energy Future HoldingsLimited Partnership and the Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC, itsgeneral partner, to fill the vacancy left upon the resignation of Mr. Goltz in May of 2012.212 Table of ContentsItem 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERSThe following table presents information concerning stock-based compensation plans as of December 31, 2012. (See Note14 to Financial Statements.)(c)Number of securities(b) remaining available for(a) Weighted-average future issuance underNumber of securities to exercise price of equity compensationbe issued upon exercise outstanding options, plans, excludingof outstanding options, warrants and securities reflected inwarrants and rights(" rights12) column (a)45,798,184 $ 1.85 18,526,10545,798,184 $ 1.85 18,526,105Equity compensation plans approved by security holdersEquity compensation plans not approved by securityholders(3)Total(1) Includes 19.6 million restricted stock units issued in exchange for previously issued stock options.(2) The weighted average exercise price does not take into account the shares subject to outstanding restricted stock units whichhave no exercise price.(3) See Note 14 to Financial Statements for a description of the material features of equity compensation plans.213 Table of ContentsBeneficial Ownership of Common Stock of Energy Future Holdings Corp.The following table lists the number of shares ofcommon stock of EFH Corp. beneficially owned by each director and certainexecutive officers of EFH Corp. and the holders of more than 5% of EFH Corp.'s common stock as of February 1, 2013.The amounts and percentages of shares of common stock of EFH Corp. beneficially owned are reported on the basis of SECregulations governing the determination of beneficial ownership of securities. Under SEC rules, a person is deemed to be a"beneficial owner" of a security if that person has or shares voting power or investment power, which includes the power to disposeof or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which thatperson has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are deemed to be outstandingfor purposes of computing such person's ownership percentage, but not for purposes of computing any other person's percentage.Under these rules, more than one person may be deemed to be a beneficial owner of the same securities, and a person may bedeemed to be a beneficial owner of securities as to which such person has no economic interest.NameTexas Holdings (1)(2)(3)(4)Arcilia C. Acosta (6)David Bonderman (2)Donald L. Evans (7)Thomas D. Ferguson (3)Brandon Freiman (5)Scott Lebovitz (3)Marc S. Lipschultz (5)Michael MacDougall (8)Kenneth Pontarelli (3)William K. Reilly (9)Jonathan D. Smidt (5)John F. YoungKneeland Youngblood (11)James A. Burke (10)M. A. McFarlandDavid A. CampbellPaul M. KeglevicAll directors and current executive officers as a group (20 persons)Number of Shares Percent ofBeneficially Owned Class1,657,600,000 98.48%323,529 *1,657,600,000 98.48%2,100,000 *1,657,600,000 98.48%1,657,600,0001,657,600,000453,52998.48%*1,012,222393,529443,47463,550492,750**1,662,882,58398.79%* Less than 1%.(1) Texas Holdings beneficially owns 1,657,600,000 shares of EFH Corp. The sole general partner of Texas Holdings is TexasEnergy Future Capital Holdings LLC ("Texas Capital"), which, pursuant to the Amended and Restated Limited PartnershipAgreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The TPG Funds,the Goldman Entities and the KKR Entities (each as defined below, and collectively, the "Texas Capital Funds") collectivelyown 91.08% of the outstanding units of Texas Capital. The Texas Capital Funds exercise control over Texas Capital, andeach has the right to designate and remove the managers of Texas Capital appointed by such Texas Capital Fund. Becauseof these relationships, each of the Texas Capital Funds may be deemed to have beneficial ownership of the shares of EFHCorp. held by Texas Holdings, but each disclaims beneficial ownership of such shares. The address of both Texas Holdingsand Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.214 Table of Contents(2) The TPG Funds (as defined below) beneficially own 302,923,439.752 units of Texas Capital, representing 27.01% of theoutstanding units, including (i) 271,639,218.931 units held by TPG Partners V, L.P., a Delaware limited partnership ("TPGPartners V"), whose general partner is TPG GenPar V, L.P., a Delaware limited partnership ("TPG GenPar V"), whosegeneral partner is TPG GenPar V Advisors, LLC, a Delaware limited liability company, whose sole member is TPG HoldingsI, L.P., a Delaware limited partnership ("TPG Holdings"), (ii) 29,999,994.650 units held by TPG Partners IV, L.P., a Delawarelimited partnership ("TPG Partners IV"), whose general partner is TPG GenPar IV, L.P., a Delaware limited partnership,whose general partner is TPG GenPar IV Advisors, LLC, a Delaware limited liability company, whose sole member is TPGHoldings, (iii) 710,942.673 units held by TPG FOF V-A, L.P., a Delaware limited partnership ("TPG FOF A"), whosegeneral partner is TPG GenPar V and (iv) 573,283.498 units held by TPG FOF V-B, L.P., a Delaware limited partnership("TPG FOF B" and, together with TPG Partners V, TPG Partners IV and TPG FOF A, the "TPG Funds"), whose generalpartner is TPG GenPar V. The general partner of TPG Holdings is TPG Holdings I-A, LLC, a Delaware limited liabilitycompany, whose sole member is TPG Group Holdings (SBS), L.P., a Delaware limited partnership, whose general partneris TPG Group Holdings (SBS) Advisors, Inc., a Delaware corporation ("Group Advisors"). David Bonderman and JamesG. Coulter are directors, officers and sole shareholders of Group Advisors and may therefore be deemed to beneficiallyown the units held by the TPG Funds. David Bonderman is also a manager of Texas Capital. Messrs. Bonderman andCoulter disclaim beneficial ownership of the shares of EFH Corp. held by Texas Holdings except to the extent of theirpecuniary interest therein. The address of Group Advisors and Messrs. Bonderman and Coulter is c/o TPG Capital, L.P.,301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.(3) GS Capital Partners VI Fund, L.P., GSCP VI Offshore TXU Holdings, L.P., GSCP VI Germany TXU Holdings, L.P., GSCapital Partners VI Parallel, L.P., GS Global Infrastructure Partners I, L.P., GS Infrastructure Offshore TXU Holdings, L.P.(GSIP International Fund), GS Institutional Infrastructure Partners I, L.P., Goldman Sachs TXU Investors L.P. and GoldmanSachs TXU Investors Offshore Holdings, L.P. (collectively, the "Goldman Entities") beneficially own 303,094,945.954units ofTexas Capital, representing 27.02% ofthe outstanding units. Affiliates ofThe Goldman Sachs Group, Inc. ("GoldmanSachs") are the general partner, managing general partner or investment manager of each of the Goldman Entities, and eachof the Goldman Entities shares voting and investment power with certain of their respective affiliates. Each of GoldmanSachs and the Goldman Entities disclaims beneficial ownership of such shares of common stock except to the extent of itspecuniary interest therein. Messrs. Ferguson, Lebovitz and Pontarelli are managers of Texas Capital and executives withaffiliates of Goldman Sachs. By virtue of their position in relation to Texas Capital and the Goldman Entities, Messrs.Ferguson, Lebovitz and Pontarelli may be deemed to have beneficial ownership with respect to the units of Texas Capitalheld by the Goldman Entities. Each of Messrs. Ferguson, Lebovitz and Pontarelli disclaims beneficial ownership of theshares of EFH Corp. held by Texas Holdings except to the extent of their pecuniary interest in those shares. The addressof each entity and individual listed in this footnote is c/o Goldman, Sachs & Co., 85 Broad Street, New York, New York10004.(4) KKR 2006 Fund L.P., KKR PEI Investments, L.P., KKR Partners HI, L.P., KKR North American Co-Invest Fund I L.P. andTEF TFO Co-Invest, LP (collectively, the "KKR Entities") beneficially own 415,473,419.680 units of Texas Capital,representing 37.05% ofthe outstanding units. The KKR Entities disclaim beneficial ownership of any shares of our commonstock in which they do not have a pecuniary interest. KKR & Co. L.P., as the holding company of affiliates that directlyor indirectly control the KKR Entities, other than KKR Partners III, LP., may be deemed to share voting and dispositivepower with respect to the shares beneficially owned by such KKR Entities, but disclaims beneficial ownership of suchshares except to the extent of its pecuniary interest in those shares. As the designated members of KKR Management LLC(which is the general partner of KKR & Co. L.P.) and the managing members of KKR III GP LLC (which is the generalpartner of KKR Partners III, L.P.), Henry R. Kravis and George R. Roberts may be deemed to share voting and dispositivepower with respect to the shares beneficially owned by the KKR Entities but disclaim beneficial ownership of such sharesexcept to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in thisfootnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019.(5) Messrs. Freiman, Lipschultz and Smidt are managers of Texas Capital and executives of Kohlberg Kravis Roberts & Co.L.P. and/or one or more of its affiliates. None of Messrs. Freiman, Lipschultz or Smidt have voting or investment powerover and each disclaim beneficial ownership of the units held by the KKR Entities and the shares of EFH Corp. held byTexas Holdings, except in each case to the extent of their pecuniary interest. The address of each individual listed in thisfootnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019.(6) 70,000 shares held in a family limited partnership, ACA Family LP.(7) Includes 1,700,000 shares issuable upon exercise of vested options.(8) Michael MacDougall is a TPG partner. Mr. MacDougall is a manager of Texas Capital. Mr. MacDougall does not havevoting or investment power over and disclaims beneficial ownership of the units of Texas Capital held by the TPG Fundsand the shares of EFH Corp. held by Texas Holdings. The address of Mr. MacDougall is c/o Global, LLC, 301 CommerceStreet, Suite 3300, Fort Worth, TX 76102.(9) William K. Reilly is a TPG senior advisor. Mr. Reilly does not have voting or investment power over and disclaims beneficialownership ofthe units of Texas Capital held by the TPG Funds. The address of Mr. Reilly is c/o Global, LLC, 301 CommerceStreet, Suite 3300, Fort Worth, TX 76102.215 Table of Contents(10) Shares consist of 443,474 vested deferred shares which, in accordance with the terms of the Deferred Share Agreement,will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in controlof EFH Corp.(11) 100,000 shares held in a limited partnership, Burton Hills Limited, LP.Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCEPolicies and Procedures Relating to Related Party TransactionsThe Board has adopted a related person transactions policy. Under this policy, a related person transaction shall beconsummated or shall continue only if:1. the Audit Committee of the Board approves or ratifies such transaction in accordance with the policy and determinesthat the transaction is on terms comparable to those that could be obtained in arm's length dealings with an unrelatedthird party;2. the transaction is approved by the disinterested members of the Board or the Executive Committee; or3. the transaction involves compensation approved by the Organization and Compensation Committee of the Board.For purposes of this policy, the term "related person" includes EFH Corp.'s directors, executive officers, 5% shareholders and theirimmediate family members. "Immediate family members" means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee)sharing the household of a director, executive officer or 5% shareholder.A "related person transaction" is a transaction between EFH Corp. or its subsidiaries and a related person, other than thetypes of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:1. any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K ofthe Securities Act;2. any transaction with another company at which a related person's only relationship is as an employee (other than anexecutive officer), director or beneficial owner of less than 10% of that company's ownership interests;3. any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university atwhich a related person's only relationship is as an employee (other than an executive officer) or director;4. transactions where the related person's interest arises solely from the ownership of EFH Corp.'s equity securities and allholders of that class of equity securities received the same benefit on a pro rata basis;5. transactions involving a related party where the rates or charges involved are determined by competitive bids;6. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility,as rates or charges fixed in conformity with law or governmental authority;7. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trusteeunder a trust indenture, or similar service;8. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 ofRegulation S-K of the Securities Act, if applicable);9. transactions involving less than $100,000 when aggregated with all similar transactions;10. transactions between EFH Corp. and its subsidiaries or between subsidiaries of EFH Corp.;II. transactions not required to be disclosed under Item 404 of Regulation S-K under the Securities Act of 1933, and12. open market purchases of EFH Corp.'s or its subsidiaries' debt or equity securities and interest payments on such debt.The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify relatedperson transactions. Accordingly, at least annually, management reviews related person transactions to be entered into, or previouslyentered into, by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the Board approves, ratifies ordisapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such relatedperson transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advanceof receiving approval, provided that such related person transactions are reviewed as soon as reasonably practicable by the AuditCommittee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. makes allreasonable efforts to cancel or otherwise terminate the affected transactions.216 Table of ContentsThe related person transactions described below under "Related Person Transactions -Business Affiliations," were ratifiedby the Audit Committee of the Board pursuant to the policy described above. All other related person transactions were approvedprior to the Board's adoption of this policy, but were approved by either the Board or its Executive Committee. Transactionsdescribed below under "Related Person Transactions -Transactions with Sponsor Affiliates" are not related person transactionsunder the EFH Corp. policy because they are not with a director, executive officer, 5% shareholder or any of their immediatefamily members, but are described in the interest of greater disclosure.Related Person TransactionsLimited Partnership Agreement of Texas Energy Future Holdings Limited Partnership; Limited Liability Company Agreementof Texas Energy Future Capital Holdings LLCThe Sponsor Group and certain investors who agreed to co-invest with the Sponsor Group or through a vehicle jointlycontrolled by the Sponsor Group to provide equity financing for the Merger (Co-Investors) entered into (i) a limited partnershipagreement (LP Agreement) in respect of EFH Corp.'s parent company, Texas Holdings and (ii) the LLC Agreement in respect ofTexas Holdings' sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or executeconsents with respect to any shares of EFH Corp.'s common stock owned by Texas Holdings. The LLC Agreement and LPAgreement contain agreements among the parties with respect to the election of EFH Corp.'s directors, restrictions on the issuanceor transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions(including the right to approve various corporate actions).The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managersof Texas Capital are also members of EFH Corp.'s Board. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. andaffiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman,Sachs & Co. (Goldman), an affiliate of GS Capital Partners, has the right to designate three managers of Texas Capital. Theserights are subject to maintenance of certain investment levels in Texas Holdings.Registration Rights AgreementThe Sponsor Group and the Co-Investors entered into a registration rights agreement with EFH Corp. upon completion ofthe Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares ofEFH Corp.'s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the SponsorGroup and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.'s common stockunder the Securities Act that it may undertake. Ms. Acosta and Messrs. Evans, Reilly and Youngblood, each of whom are membersof our Board, and Messrs. Young, Burke, Keglevic, McFarland, and O'Brien, each of whom are executive officers of EFH Corp.,are parties to this agreement.Management Services AgreementIn October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a managementagreement with EFH Corp. (Management Agreement), pursuant to which affiliates of the Sponsor Group provide management,consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the SponsorGroup are entitled to receive an aggregate annual management fee of $35 million, which amount increases 2% annually, andreimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the ManagementAgreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control ofEFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate theManagement Agreement. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive afee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition,merger combination and change of control transactions, as well as a termination fee based on the net present value of future paymentobligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Underterms of the Management Agreement, EFH Corp. paid $38 million, inclusive of expenses, to the Sponsor Group during 2012.217 Table of ContentsIndemnification AgreementConcurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. enteredinto an indemnification agreement (Indemnification Agreement), pursuant to which EFH Corp. and Texas Holdings agree toindemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactionsrelating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failuresto act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, Company Group), (iv) serviceas an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach offiduciary duty as a director or officer of any member of the Company Group.Sale Participation AgreementMs. Acosta and Messrs. Evans, Reilly and Youngblood, each of whom are members of our Board, and Mmes. Dord andKirby and Messrs. Young, Burke, Keglevic, McFarland, and O'Brien, each of whom are executive officers, entered into saleparticipation agreements with EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.'scommon stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Groupof shares of EFH Corp.'s common stock held by the Sponsor Group.Certain Certificate of Formation ProvisionsEFH Corp.'s restated certificate of formation contains provisions limiting our directors' obligations in respect of corporateopportunities.Management Stockholders'AgreementSubject to a management stockholders' agreement, certain members of management, including EFH Corp.'s directors,executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or commonstock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. inexchange therefore. The net aggregate amount of this investment as of December 31, 2012 is approximately $42 million. Themanagement stockholders' agreement creates certain rights and restrictions on these shares of common stock, including transferrestrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.Director Stockholders'AgreementCertain members of our Board have entered into a stockholders' agreement with EFH Corp. These stockholders' agreementscreate certain rights and restrictions on the equity, including transfer restrictions and tag-along, drag-along, put, call and registrationrights in certain circumstances.Business AffiliationsMr. Olson, a member of our board until October 26, 2012, has an ownership interest in and serves on the board of TexasMeter and Device Company (TMD), a company that conducts tests on Oncor's high voltage personal protective equipment. Mr.Olson and his brother collectively directly own approximately 24% of TMD. This entity is majority owned by its chief executiveofficer. In 2012, Oncor paid TMD approximately $795,000 for its services. The business relationship with TMD commencedseveral years prior to Mr. Olson joining the Board.Mr. Olsen has an ownership interest in and serves on the board of Metrum Technologies (MT), a company that is a subsidiaryof Texas Meter and Device Company and provides Oncor with certain technology based products for Oncor's advanced meteringdevices. Mr. Olson and his brother collectively directly own approximately 19% of MT. This entity is majority owned by its chiefexecutive officer. In 2012, Oncor paid MT approximately $565,000 for its services. The business relationship with MT commencedseveral years prior to Mr. Olson joining the Board.Mr. Olsen is chairman of the New York and Sweden offices of Hili+Knowlton Strategies (HKS). Mr. Olsen is also a memberof HKS' Global Counsel. HKS is the parent company of Public Strategies Inc. (PSI). PSI performs certain consulting servicesfor EFH Corp. and its subsidiaries, primarily in the areas of public relations and public advocacy. Mr. Olsen does not have anyownership interest in HKS or its subsidiaries. In 2012, EFH Corp. and its subsidiaries paid approximately $2.3 million to PSI forits services and approximately $64,000 to HKS for its services.218 Table of ContentsTransactions with Sponsor AffiliatesIn December 2012 and January 2013, Goldman acted as a dealer manager for the offers by EFIH to exchange EFIH 10%Senior Secured Notes due 2020 for EFH Corp. 9.75% Senior Secure Notes due 2019, EFH Corp. 10% Senior Secured Notes due2020, and EFIH 9.75% Senior Secured Notes due 2019 (collectively, the Old Notes) and as a solicitation agent in the solicitationof consents by EFH Corp. and EFIH to amendments to the Old Notes and indentures governing the Old Notes and received feestotaling approximately $1 million. In December 2012 and January 2013, Goldman acted as a dealer manager for the offers byEFIH to exchange EFIH 11.25%/12.25% Senior Toggle Notes due 2018 for EFH Corp. 10.875% Senior Notes due 2017 and EFHCorp. 11.25%/ 12.00% Senior Toggle Notes due 2017 and received fees totaling approximately $100,000.Goldman acted as ajoint book-running manager and initial purchaser in the February 2012 issuance of $1.15 billion principalamount of EFIH 11.750% Senior Secured Second Lien Notes due 2022 and received fees totaling approximately $7 million.Further, Goldman acted as ajoint book-running manager and initial purchaser in the August 2012 issuance of $250 million principalamount of EFIH 6.875% Senior Secured Notes due 2017 and $600 million principal amount of EFIH 11.750% Senior SecuredSecond Lien Notes due 2022 and received fees totaling approximately $3 million. In addition, Goldman acted as a joint book-running manager and initial purchaser in the October 2012 issuance of $253 million principal amount of EFIH 6.875% Notes due2017 and received fees totaling approximately $1 million.An affiliate of Kohlberg Kravis Roberts & Co. L.P. served as a co-manager and initial purchaser in, and an affiliate of TPGserved as an advisor in, each of the above transactions and each received fees totaling approximately $4 million.TCEH has entered into the TCEH Senior Secured Facilities, and Oncor has entered into a revolving credit facility, each withsyndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners.Affiliates of GS Capital Partners have from time to time engaged in commercial and investment banking and financialadvisory transactions with EFH Corp. in the normal course of business. Affiliates of Goldman are party to certain commodity andinterest rate hedging transactions with EFH Corp. in the normal course of business.From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiariesin open market transactions or through loan syndications.Members of the Sponsor Group and/or their respective affiliates have from time to time entered into, and may continue toenter into, arrangements with the Company to use our products and services in the ordinary course of their business, which oftenresult in revenues to the Company in excess of $120,000 annually. In addition, the Company has entered into, and may continueto enter into, arrangements with members of the Sponsor Group and/or their respective affiliates to use their products and servicesin the ordinary course of their business, which often result in revenues to members of the Sponsor Group or their respective affiliatesin excess of $120,000 annually.Director IndependenceThough not formally considered by the Board because EFH Corp.'s common stock is not currently registered under theSecurities Exchange Act of 1934, as amended, with the SEC or traded on any national securities exchange, based upon the listingstandards for issuers of equity securities on the New York Stock Exchange (NYSE), the national securities exchange upon whichEFH Corp.'s common stock was traded prior to the Merger, only Ms. Acosta and Mr. Youngblood would be considered independent.Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other directors would be consideredindependent under the NYSE listing standards for issuers of equity securities. See "Certain Relationships and Related PartyTransactions" and Item 11, "Executive Compensation -Director Compensation." Accordingly, we believe that Ms. Acosta is theonly member of the Organization and Compensation Committee who would meet the NYSE's independence requirements forissuers of equity securities. We believe that none of the members of EFH Corp.'s Executive Committee, which now functions asthe nominating/governance committee, would meet the NYSE's independence requirements for issuers of equity securities. Underthe NYSE's audit committee independence requirement for issuers of debt securities, Ms. Acosta and Mr. Youngblood, whoconstitute the Audit Committee, are considered independent.219 Table of ContentsItem 14. PRINCIPAL ACCOUNTING FEES AND SERVICESDeloitte & Touche LLP has been the independent auditor for EFH Corp. and for its Predecessor (TXU Corp.) since itsorganization in 1996.The Audit Committee of the EFH Corp. Board of Directors has adopted a policy relating to the engagement of EFH Corp.'sindependent auditor. The policy provides that in addition to the audit of the financial statements, related quarterly reviews andother audit services, and providing services necessary to complete SEC filings, EFH Corp.'s independent auditor may be engagedto provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditormust be authorized by the Audit Committee in accordance with preapproval procedures which are defined in the policy. Thepreapproval procedures require:1. The annual review and preapproval by the Audit Committee of all anticipated audit and non-audit services; and2. The quarterly preapproval by the Audit Committee of services, if any, not previously approved and the review of thestatus of previously approved services.The Audit Committee may also approve certain on-going non-audit services not previously approved in the limitedcircumstances provided for in the SEC rules. All services performed by Deloitte & Touche LLP, the member firms of DeloitteTouche Tohmatsu and their respective affiliates (Deloitte & Touche) for EFH Corp. in 2012 were preapproved by the AuditCommittee.The policy defines those non-audit services which EFH Corp.'s independent auditor may also be engaged to provide asfollows:1. Audit-related services, including:a. due diligence accounting consultations and audits related to mergers, acquisitions and divestitures;b. employee benefit plan audits;c. accounting and financial reporting standards consultation;d. internal control reviews, ande. attest services, including agreed-upon procedures reports that are not required by statute or regulation.2. Tax-related services, including:a. tax compliance;b. general tax consultation and planning;c. tax advice related to mergers, acquisitions, and divestitures, andd. communications with and request for rulings from tax authorities.3. Other services, including:a. process improvement, review and assurance;b. litigation and rate case assistance;c. forensic and investigative services, andd. training services.The policy prohibits EFH Corp. from engaging its independent auditor to provide:1. Bookkeeping or other services related to EFH Corp.'s accounting records or financial statements;2. Financial information systems design and implementation services;3. Appraisal or valuation services, fairness opinions, or contribution-in-kind reports;4. Actuarial services;5. Internal audit outsourcing services;6. Management or human resource functions;7. Broker-dealer, investment advisor, or investment banking services;8. Legal and expert services unrelated to the audit, and9. Any other service that the Public Company Accounting Oversight Board determines, by regulation, to be impermissible.In addition, the policy prohibits EFH Corp.'s independent auditor from providing tax or financial planning advice to anyofficer of EFH Corp.Compliance with the Audit Committee's policy relating to the engagement of Deloitte & Touche is monitored on behalf ofthe Audit Committee by EFH Corp.'s chief accounting officer. Reports describing the services provided by Deloitte & Toucheand fees for such services are provided to the Audit Committee no less often than quarterly.220 Table of ContentsFor the years ended December 31, 2012 and 2011, fees billed (in US dollars) to EFH Corp. by Deloitte & Touche were asfollows:2012 2011Audit Fees. Fees for services necessary to perform the annual audit, review SEC filings, fulfillstatutory and other service requirements, provide comfort letters and consentsAudit-Related Fees. Fees for services including employee benefit plan audits, due diligencerelated to mergers, acquisitions and divestitures, accounting consultations and audits inconnection with acquisitions, internal control reviews, attest services that are not required bystatute or regulation, and consultation concerning financial accounting and reporting standardsTax Fees. Fees for tax compliance, tax planning, and tax advice related to mergers andacquisitions, divestitures, and communications with and requests for rulings from taxingauthoritiesAll Other Fees. Fees for services including process improvement reviews, forensic accountingreviews, litigation assistance and training servicesTotal$ 6,449,000 $ 6,298,000628,000 445,000-19,000256,000 _S 7,333,000 $ 6,762,000221 Table of ContentsPART IV.Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES(a) Schedule I -CONDENSED FINANCIAL INFORMATION OF REGISTRANTENERGY FUTURE HOLDINGS CORP. (PARENT)SCHEDULE I -CONDENSED FINANCIAL INFORMATION OF REGISTRANTCONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(Millions of Dollars)Selling, general and administrative expensesOther incomeOther deductionsInterest incomeInterest expense and related chargesLoss before income taxes and equity in earnings of unconsolidated subsidiariesIncome tax benefitEquity in losses of consolidated subsidiariesEquity in earnings of unconsolidated subsidiaries (net of tax)Net lossOther comprehensive income (net of tax expense of $94 million, $21 millionand $23 million)Comprehensive income (loss)Year Ended December 31,2012 2011 2010(25) $ (26) $ (32)1 10 137(1) (14)164 132 178(1,115) (1,114) (1,082)(976) (1,012) (799)340 341 305(2,994) (1,528) (2,595)270 286 277(3,360) (1,913) (2,812)175 41 46$ (3,185) $ (1,872) $ (2,766)See Notes to Financial Statements.222 Table of ContentsENERGY FUTURE HOLDINGS CORP. (PARENT)SCHEDULE I -CONDENSED FINANCIAL INFORMATION OF REGISTRANTCONDENSED STATEMENTS OF CASH FLOWS(Millions of Dollars)Cash flows -operating activitiesNet lossAdjustments to reconcile net loss to cash provided by (used in)operating activities:Equity in losses of consolidated subsidiariesEquity in earnings of unconsolidated subsidiariesDeferred income tax benefit -netInterest expense on toggle notes payable in additional principalImpairment of investment in long-term debt of affiliatesAmortization of debt related costsDebt extinguishment gainsCharges related to pension plan actionsOther, netChanges in operating assets and liabilities:Distributions received from subsidiariesOther -net assetsOther -net liabilitiesCash provided by (used in) operating activitiesCash flows -financing activitiesIssuances of long-term debtRepayments/repurchases of long-term debtRepayment of note -affiliateDistributions received from subsidiariesChange in notes/advances -affiliateOther, netCash provided by (used in) financing activitiesCash flows -investing activitiesCapital contribution to subsidiaryInvestment in affiliate debtInvestment (posted with) redeemed from derivative counterpartyOther, netCash used in investing activitiesNet change in cash and cash equivalentsCash and cash equivalents -beginning balanceCash and cash equivalents -ending balanceYear Ended December 31,2012 2011 2010$ (3,360) $ (1,913) $ (2,812)2,994(270)(235)33427481,528(286)(218)3615352(3)92,595(277)(56)3334074(133)71(4)-,- 294 -328(68) (50) 67$ (439) $ (467) $ 168$(5)500(96)770950 --(871) (292) (785)-(16) (28)$ 79 $ (313) $ 361(15)(440)(105)400-11$ -$ (4) $ (145)(360) (784) 384659 1,443 1,059$ 299 $ 659 $ 1,443See Notes to Financial Statements.223 Table of ContentsENERGY FUTURE HOLDINGS CORP. (PARENT)SCHEDULE I -CONDENSED FINANCIAL INFORMATION OF REGISTRANTCONDENSED BALANCE SHEETS(Millions of Dollars)December 3 1,2012 2011ASSETSCurrent assets:Cash and cash equivalentsTrade accounts receivable -netIncome taxes receivable -netAccounts receivable from affiliatesNotes receivable from affiliatesCommodity and other derivative contractual assetsOther current assetsTotal current assetsReceivables from unconsolidated subsidiaryEquity investment in consolidated subsidiariesInvestment in long-term debt of subsidiariesOther investmentsIncome taxes receivable from affiliateNotes receivable from affiliatesAccumulated deferred income taxesOther noncurrent assets, principally unamortized issuance costsTotal assetsLIABILITIES AND EQUITYCurrent liabilities:Notes/advances from affiliatesTrade accounts payableNotes payable to affiliatesCommodity and other derivative contractual liabilitiesAccumulated deferred income taxesAccrued interestOther current liabilitiesTotal current liabilitiesNotes or other liabilities due affiliates/unconsolidated subsidiaryLong-term debt, less amounts due currentlyOther noncurrent liabilities and deferred creditsTotal liabilitiesShareholders' equityTotal liabilities and equity$ 299 $65913 1360 37222 33212 182132 1422 3940 1,069825 1,235(2,339) 1,40792 11555 58-- 11920 12970 90270 77633 $ 4,994315 $269815026311,5921663 3172 1715 51,345 2,2011,282 1,2827,895 7,6191,136 1,74411,658 12,846(11,025) (7,852)633 $ 4,994See Notes to Financial Statements.224 Table of ContentsENERGY FUTURE HOLDINGS CORP. (PARENT)SCHEDULE I -CONDENSED FINANCIAL INFORMATION OF REGISTRANTNOTES TO CONDENSED FINANCIAL STATEMENTS1. BASIS OF PRESENTATIONThe accompanying unconsolidated condensed balance sheets, statements of income (loss) and cash flows present results ofoperations and cash flows of EFH Corp. (Parent). Certain information and footnote disclosures normally included in financialstatements prepared in accordance with US GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidatedcondensed financial statements do not include all of the information and footnotes required by US GAAP, they should be read inconjunction with the financial statements and related notes of Energy Future Holdings Corp. and Subsidiaries included in Item 8of this Annual Report on Form 10-K. EFH Corp.'s subsidiaries have been accounted for under the equity method. All dollaramounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.2. INVESTMENT IN LONG-TERM DEBT OF SUBSIDIARYAs a result of debt exchanges and purchases in 2009 through 2011, EFH Corp. (Parent) holds debt securities of TCEH withcarrying values totaling $92 million and $115 million at December 31, 2012 and 2011, respectively, reported as investment inlong-term debt of subsidiaries.As of December 31, 2012 and 2011, all of these debt securities are classified as available-for-sale. In accordance withaccounting guidance for investments classified as available-for-sale, at December 31, 2012 the securities are recorded at fair valueand unrealized gains or losses are recorded in other comprehensive income unless such losses are other than temporary, in whichcase they are reported as impairments. The principal amounts, coupon rates, maturities and carrying value are as follows:December 31, 2012 December 31,2011Principal Carrying Principal CarryingAmount Value (a) Amount Value (a)Available-for-sale securities:TCEH 4.746% Term Loan Facilities maturing October 10, 2017 (b) $ 19 $ 12 $ 19 $ 16TCEH 10.25% Fixed Senior Notes due November 1, 2015 (both periodsinclude $102 million principal amount of Series B Notes) 284 80 284 99Total available-for-sale securities $ 303 $ 92 $ 303 $ 115(a) Carrying value equals fair value.(b) Interest rates in effect at December 31, 2012.Impairments -In 2012, we deemed the declines in values of the TCEH securities were other than temporary and recordeda $27 million impairment recorded as a reduction of interest income. In 2011, we deemed the declines in values of TCEH securitieswere other than temporary and recorded a $53 million impairment recorded as a reduction of interest income. We considered thatthe securities were in a loss position for more than 12 months and that declines in natural gas prices and other correspondingeffects on the profitability and cash flows of TCEH (which has below investment grade credit ratings) were unlikely to reverse inthe near term. In 2010, we recorded a $40 million impairment of TCEH securities. As a result of the impairments, no cumulativeunrealized losses were recorded in accumulated other comprehensive income at December 31, 2012, 2011 and 2010.225 Table of ContentsInterest income recorded on these investments was as follows:Year Ended December 31,2012 2011 2010Held-to-maturity securities:Interest received/accrued $ -$ $ 18PIK interest received related TCEH toggle notes --4Accretion of purchase discount --I ITotal interest income related to held-to-maturity securities --33Available-for-sale securities:Interest received/accrued 30 26 -Accretion of purchase discount 1 2 -Impairments related to issuer credit (27) (53) (40)Total interest income related to available-for-sale securities 4 (25) (40)Total interest income 4 $ (25) $ (7)We determine value under the fair value hierarchy established in accounting standards. Under the fair value hierarchy, Level2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similarsecurities, adjusted for observable differences. The fair value of our investment in long-term debt of subsidiaries is estimated atthe lesser of either the call price or the market value as determined by broker quotes and quoted market prices for similar securitiesin active markets. For the periods presented, the fair values of our investment in long-term debt of subsidiaries represent Level2 valuations.3. GUARANTEESAs discussed below, EFH Corp. (Parent) has entered into contracts that contain guarantees to unaffiliated parties that couldrequire performance or payment under certain conditions. Material guarantees are discussed below.Disposed TXU Gas Company Operations -In connection with the sale of the assets of TXU Gas Company to AtmosEnergy Corporation (Atmos) in October 2004, EFH Corp. agreed to indemnify Atmos, until October 1,2014, for up to $500 millionfor any liability related to assets retained by TXU Gas Company, including certain inactive gas plant sites not acquired by Atmos,and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximumaggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required tomake any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.Assumption ofIndebtedness -In 1990, EFCH purchased an electric co-op's minority ownership interest in the ComanchePeak nuclear generation facilities and assumed the co-op's indebtedness to the US government related to the co-op's investmentin the facilities (without the co-op being released from its obligations under such indebtedness). EFCH is making principal andinterest payments in an amount sufficient to satisfy the co-op's requirements under the indebtedness. In the event that paymentson the indebtedness are not made in a timely manner, the US government would be entitled to enforce the payment of the debtagainst EFCH. At December 31, 2012, the balance of the indebtedness on EFCH's balance sheet was $74 million with maturitiesof principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities. EFHCorp. (Parent) has guaranteed EFCH's obligation under this agreement.226 Table of Contents4. DIVIDEND RESTRICTIONSThe indenture governing the EFH Corp. Senior Notes includes covenants that, among other things and subject to certainexceptions, restrict our ability to pay dividends or make other distributions in respect of our common stock. Accordingly, our netincome is restricted from being used to make distributions on our common stock unless such distributions are expressly permittedunder these indentures and/or on a pro forma basis, after giving effect to such distribution, EFH Corp. (Parent)'s consolidatedleverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, "consolidated leverage ratio" is defined as theratio of consolidated total debt (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiariesother than Oncor Holdings and its subsidiaries. EFH Corp. (Parent)'s consolidated leverage ratio was 10.1 to 1.0 at December 31,2012.The indentures governing the EFIH Notes generally restrict EFIH from making any cash distribution to EFH Corp. for theultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend,EFIH's consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indentures governing the EFIH Notes, the term"consolidated leverage ratio" is defined as the ratio of EFIH's consolidated total debt (as defined in the indentures) to EFIH'sAdjusted EBITDA on a consolidated basis (including Oncor's Adjusted EBITDA). EFIH's consolidated leverage ratio was 7.0 to1.0 at December 31, 2012. In addition, the EFIH Notes generally restrict EFIH's ability to make distributions or loans to EFHCorp., unless such distributions or loans are expressly permitted under the indentures governing the EFIH Notes.The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companiesfor the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend,its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than6.5 to 1.0. At December 31, 2012, the ratio was 8.5 to 1.0.In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior SecuredNotes and TCEH Senior Secured Second Lien Notes generally restrict TCEH's ability to make distributions or loans to any of itsparent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior SecuredFacilities and the indentures governing such notes.Under applicable law, we are prohibited from paying any dividend to the extent that immediately following payment of suchdividend, there would be no statutory surplus or we would be insolvent.EFH Corp. (Parent) has not declared or paid any dividends since the Merger.EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $950 million and $2 million for the yearsended December 31, 2012 and 2010, respectively. EFH Corp. (Parent) did not receive any dividends from its consolidatedsubsidiaries in the year ended December 31, 2011.5. SUPPLEMENTAL CASH FLOW INFORMATIONYear Ended December 31,2012 2011 2010Cash payments (receipts) related to:Interest paid 675 $ 1,097 $ 1,022Income taxes (227) (91) (4)Noncash investing and financing activities:Debt exchange transactions -12 200Principal amount of toggle notes issued in lieu of cash 398 355 324(a) Represents end-of-period accruals.227 Table of Contents(b) Oncor Holdings Financial Statements are presented pursuant to Rules 3-09 and 3-16 of Regulation S-X as Exhibit 99(e).(c) Exhibits:EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012Previously Filed* With File AsExhibits Number Exhibit(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession2(a) 1-12833 2.1 -Agreement and Plan of Merger, dated February 25, 2007, by andForm 8-K among Energy Future Holdings Corp. (formerly known as TXU(filed February 26, 2007) Corp.), Texas Energy Future Holdings Limited Partnership and TexasEnergy Future Merger Sub Corp.(3(i)) Articles of Incorporation3(a)1-12833Form 8-K(filed October 11, 2007)3.1-Restated Certificate of Formation of Energy Future Holdings Corp.(3(ii)) By-laws3(b)1-12833Form l0-Q (Quarterended June 30, 2012)(filed July 31, 2012)3(b) -Amended and Restated Bylaws of Energy Future Holdings Corp.(4) Instruments Defining the Rights of Security Holders, Including Indentures**Energy Future Holdings Corp.4(a)4(b)4(c)4(d)4(e)4(f)4(g)4(h)4(i)1-12833Form 10-K (2007)(filed March 31, 2008)1-12833Form 8-K(filed July 7, 2010)1-12833Form 10-K (2004)(filed March 16, 2005)1-12833Form 10-K (2010)(filed February 18, 2011)1-12833Form 10-K (2004) (filedMarch 16, 2005)1-12833Form 8-K(filed December 5, 2012)1-12833Form 10-K (2004) (filedMarch 16, 2005)1-12833Form 8-K(filed December 5, 2012)1-12833Form 8-K(filed October 31, 2007)4(c)99.14(q)4(d)4(r)4.34(s)4.44.1-Indenture (For Unsecured Debt Securities Series P), dated November1, 2004, between Energy Future Holdings Corp. and The Bank ofNew York Mellon, as trustee.-Supplemental Indenture, dated July 1, 2010, to Indenture (ForUnsecured Debt Securities Series P), dated November 1, 2004.-Officers' Certificate, dated November 26, 2004, establishing theform and certain terms of Energy Future Holdings Corp.'s 5.55%Series P Senior Notes due 2014.-Indenture (For Unsecured Debt Securities Series Q), dated November1, 2004, between Energy Future Holdings Corp. and The Bank ofNew York Mellon, as trustee. Energy Future Holdings Corp.'sIndentures for its Series R Senior Notes are not filed as it issubstantially similar to this Indenture.-Officer's Certificate, dated November 26,2004, establishing the formand certain terms of Energy Future Holdings Corp.'s 6.50% SeriesQ Senior Notes due 2024.-Supplemental Indenture, dated December 5, 2012, to the indenture,dated November 1, 2004, between Energy Future Holdings Corp.and The Bank of New York Mellon, as trustee (For Unsecured DebtSecurities Series Q).-Officer's Certificate, dated November 26, 2004, establishing the formand certain terms of Energy Future Holdings Corp.'s 6.55% SeriesR Senior Notes due 2034.-Supplemental Indenture, dated December 5, 2012, to the indenture,dated November 1, 2004, between Energy Future Holdings Corp.and The Bank of New York Mellon, as trustee (For Unsecured DebtSecurities Series R).-Indenture, dated October 31, 2007, among Energy Future HoldingsCorp., the guarantors named therein and The Bank of New YorkMellon, as trustee, relating to Senior Notes due 2017 and SeniorToggle Notes due 2017.228 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit40)4(k)4(1)4(m)4(n)4(o)4(p)4(q)4(r)4(s)4(t)4(u)1-12833Form 10-K (2009)(filed February 19, 2010)1-12833Form 10-Q (Quarterended June 30, 2009)(filed August 4, 2009)1-12833Form 8-K(filed July 30, 2010)1-12833Form 10-Q (Quarterended September 30,2011) (filed October 28,2011)1-12833Form 8-K(filed November 20,2009)1-12833Form 8-K(January 30, 2013)333-171253Form S-4(filed January 24, 2011)333-165860Form S-3(filed April 1, 2010)1-12833Form 10-Q (Quarterended June 30, 2010)(filed August 2, 2010)1-12833Form 10-Q (Quarterended June 30, 2010)(filed August 2, 2010)1-12833Form 10-Q (Quarterended June 30, 2010)(filed August 2, 2010)1-12833Form I0-Q (Quarterended June 30, 2010)(filed August 2, 2010)4(f)4(a)99.14(b)4.14.14(k)40)4(a)4(b)4(c)4(d)-Supplemental Indenture, dated July 8, 2008, to Indenture, datedOctober 31, 2007.-Second Supplemental Indenture, dated August 3, 2009, to Indenture,dated October 31, 2007.-Third Supplemental Indenture, dated July 29, 2010, to Indenture,dated October 31, 2007.-Fourth Supplemental Indenture, dated October 18, 2011, to Indenturedated October 31, 2007.-Indenture, dated November 16,2009, among Energy Future HoldingsCorp., the guarantors named therein and The Bank of New YorkMellon Trust Company, N.A., as trustee, relating to 9.75% SeniorSecured Notes due 2019.-Supplemental Indenture, dated January 25, 2013, to the Indenture,dated November 16, 2009, among Energy Future Holdings Corp.,the guarantors named therein and The Bank of New York MellonTrust Company, N.A., as trustee, relating to 9.75% Senior SecuredNotes due 2019.-Indenture, dated January 12, 2010, among Energy Future HoldingsCorp., the guarantors named therein and The Bank of New YorkMellon Trust Company, N.A., as trustee, relating to 10.000% SeniorSecured Notes due 2020.-First Supplemental Indenture, dated March 16, 2010, to theIndenture, dated January 12, 2010, among Energy Future HoldingsCorp., the guarantors named therein and The Bank of New YorkMellon Trust Company, N.A., as trustee, relating to 10.000% SeniorSecured Notes due 2020.-Second Supplemental Indenture, dated April 13, 2010, to theIndenture, dated January 12, 2010, among Energy Future HoldingsCorp., the guarantors named therein and The Bank of New YorkMellon Trust Company, N.A., as trustee, relating to 10.000% SeniorSecured Notes due 2020.-Third Supplemental Indenture, dated April 14,2010, to the Indenture,dated January 12, 2010, among Energy Future Holdings Corp., theguarantors named therein and The Bank of New York Mellon TrustCompany, N.A., as trustee, relating to 10.000% Senior Secured Notesdue 2020.-Fourth Supplemental Indenture, dated May 21, 2010, to theIndenture, dated January 12, 2010, among Energy Future HoldingsCorp., the guarantors named therein and The Bank of New YorkMellon Trust Company, N.A., as trustee, relating to 10.000% SeniorSecured Notes due 2020.-Fifth Supplemental Indenture, dated July 2, 2010, to the Indenture,dated January 12, 2010, among Energy Future Holdings Corp., theguarantors named therein and The Bank of New York Mellon TrustCompany, N.A., as trustee, relating to 10.000% Senior Secured Notesdue 2020.229 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit4(v) 1-12833 4(e)Form 10-Q (Quarterended June 30, 2010)(filed August 2, 2010)4(w)4(x)333-171253Form S-4(filed January 24, 2011)1-12833Form 8-K(January 30, 2013)4(r)-Sixth Supplemental Indenture, dated July 6, 2010, to the Indenture,dated January 12, 2010, among Energy Future Holdings Corp., theguarantors named therein and The Bank of New York Mellon TrustCompany, N.A., as trustee, relating to 10.000% Senior Secured Notesdue 2020.-Seventh Supplemental Indenture, dated July 7,2010, to the Indenture,dated January 12, 2010, among Energy Future Holdings Corp., theguarantors named therein and The Bank of New York Mellon TrustCompany, N.A., as trustee, relating to 10.000% Senior Secured Notesdue 2020.-Eighth Supplemental Indenture, dated January 25, 2013, to theIndenture, dated January 12, 2010, among Energy Future HoldingsCorp., the guarantors named therein and The Bank of New YorkMellon Trust Company, N.A., as trustee, relating to 10.000% SeniorSecured Notes due 2020.4.2Oncor Electric Delivery Company LLC4(y)4(z)333-100240Form S-4(filed October 2, 2002)1-12833 Form 8-K(filed October 31, 2005)4(aa) 333-100240Form 10-Q (Quarterended March 31, 2008)(filed May 15, 2008)4(bb) 333-100240Form S-4(filed October 2, 2002)4(cc)333-100242Form S-4(filed October 2, 2002)4(dd) 333-100240Form I0-Q (Quarterended March 31, 2008)(filed May 15, 2008)4(ee) 333-100242Form S-4(filed October 2, 2002)4(a)10.14(b)4(b)4(a)4(c)4(b)4(c)4(a)4(n)10.1-Indenture and Deed of Trust, dated as of May 1,2002, between OncorElectric Delivery Company LLC and The Bank of New York Mellon,as trustee.-Supplemental Indenture No. 1, dated October 25, 2005, to Indentureand Deed of Trust, dated as of May 1, 2002, between Oncor ElectricDelivery Company LLC and The Bank of New York Mellon.-Supplemental Indenture No. 2, dated May 15, 2008, to Indenture andDeed of Trust, dated as of May 1, 2002, between Oncor ElectricDelivery Company LLC and The Bank of New York Mellon.-Officer's Certificate, dated May 6, 2002, establishing the form andcertain terms of Oncor Electric Delivery Company LLC's 6.375%Senior Notes due 2012 and 7.000% Senior Notes due 2032.-Indenture (for Unsecured Debt Securities), dated August 1, 2002,between Oncor Electric Delivery Company LLC and The Bank ofNew York Mellon, as trustee.-Supplemental Indenture No. 1, dated May 15, 2008, to Indenture andDeed of Trust, dated August 1, 2002, between Oncor ElectricDelivery Company LLC and The Bank of New York.-Officer's Certificate, dated August 30, 2002, establishing the formand certain terms of Oncor Electric Delivery Company LLC's 5%Debentures due 2007 and 7% Debentures due 2022.-Officer's Certificate, dated December 20,2002, establishing the formand certain terms of Oncor Electric Delivery Company LLC's6.375% Senior Notes due 2015 and 7.250% Senior Notes due 2023.-Deed of Trust, Security Agreement and Fixture Filing, dated May15, 2008, by Oncor Electric Delivery Company LLC, as grantor, toand for the benefit of, The Bank of New York Mellon Trust, ascollateral agent and trustee.-First Amendment, dated March 2, 2009, to Deed of Trust, SecurityAgreement and Fixture Filing, dated May 15, 2008.-Second Amendment, dated September 3, 2010, to Deed of Trust,Security Agreement and Fixture Filing, dated May 15, 2008.4(ff)333-106894Form S-4(filed July 9, 2003)4(gg) 333-100240Form I0-Q (Quarterended March 31, 2008)(filed May 15, 2008)4(hh) 333-100240Form 10-K (2008)(filed March 2, 2009)4(ii)333-100240Form 8-K(filed September 3, 2010)230 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit4(jj) 333-100240 10.1Form 8-K(filed November 15,2011)4(kk) 333-100242Form 8-K(filed September 9, 2008)4(11)333-100240Form 8-K(filed September 16,2010)4(mm) 333-100240Form 8-K(filed October 12, 2010)4(nn) 333-100240Form 8-K(filed November 23,2011)4(oo) 333-100240Form 8-K(filed November 23,2011)4(pp) 333-100240Form 8-K(filed May 18, 2012)4(qq) 333-100240Form 8-K(filed May 18, 2012)4.14.14.14.14.24.14.2-Third Amendment, dated November 10, 2011, to Deed of Trust,Security Agreement and Fixture Filing, dated May 15, 2008.-Officer's Certificate, dated September 8,2008, establishing the formand certain terms of Oncor Electric Delivery Company LLC's 5.95%Senior Secured Notes due 2013, 6.80% Senior Secured Notes due2018 and 7.50% Senior Secured Notes due 2038.-Officer's Certificate, dated September 13, 2010, establishing theform and certain terms of Oncor Electric Delivery Company LLC's5.25% Senior Secured Notes due 2040.-Officer's Certificate, dated October 8, 2010, establishing the formand certain terms of Oncor Electric Delivery Company LLC's 5.00%Senior Secured Notes due 2017 and 5.75% Senior Secured Notes due2020.-Officer's Certificate, dated November 23, 2011, establishing theterms of Oncor's 4.55% Senior Secured Notes due 2041.-Registration Rights Agreement, dated November 23, 2011, amongOncor Electric Delivery Company LLC and the representatives ofthe initial purchasers of Oncor's 4.55% Senior Secured Notes due2041.-Officer's Certificate, dated May 18, 2012, establishing the terms ofOncor's 4.10% Senior Secured Notes due 2022 and 5.30% SeniorSecured Notes due 2042.-Registration Rights Agreement, dated May 18, 2012, among OncorElectric Delivery Company LLC and the representatives of the initialpurchasers of Oncor's 4.10% Senior Secured Notes due 2022 and5.30% Senior Secured Notes due 2042.Texas Competitive Electric Holdings Company LLC4(rr) 333-108876Form 8-K(filed October 31, 2007)4(ss) 1-12833Form 8-K(filed December 12,2007)4(tt) 1-12833Form 10-Q (Quarterended June 30, 2009)(filed August 4, 2009)4(uu) 1-12833Form 8-K(filed October 8, 2010)4(vv) 1-12833Form 8-K(filed October 26, 2010)4.24.14(b)4.14.1-Indenture, dated October 31, 2007, among Texas CompetitiveElectric Holdings Company LLC and TCEH Finance, Inc., theguarantors and The Bank of New York Mellon Trust Company, N.A.,as trustee, relating to 10.25% Senior Notes due 2015.-First Supplemental Indenture, dated December 6,2007, to Indenture,dated October 31, 2007, relating to Texas Competitive ElectricHoldings Company LLC's and TCEH Finance, Inc.'s 10.25% SeniorNotes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notesdue 2016.-Second Supplemental Indenture, dated August 3, 2009, to Indenture,dated October 31, 2007, relating to Texas Competitive ElectricHoldings Company LLC's and TCEH Finance, Inc.'s 10.25% SeniorNotes due 2015, 10.25% Senior Notes due 2015, Series B, and10.50%/11.25% Senior Toggle Notes due 2016.-Indenture, dated October 6,2010, among Texas Competitive ElectricHoldings Company LLC and TCEH Finance, Inc., the guarantorsand The Bank of New York Mellon Trust Company, N.A., as trustee,relating to 15% Senior Secured Second Lien Notes due 2021.-First Supplemental Indenture, dated October 20, 2010, to theIndenture, dated October 6, 2010.231 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit4(ww) 1-12833 4.1Form 8-K (filedNovember 17, 2010)4(xx) 1-12833Form I0-Q (Quarterended September 30,2011) (filed October 28,2011)4(yy) 1-12833Form 8-K(filed October 8, 2010)4(zz) 1-12833Form 8-K(filed October 8, 2010)4(aaa) 1-12833Form 8-K(filed October 8, 2010)4(bbb) 1-12833Form 10-K (2010)(filed February 18, 2011)4(ccc) 1-12833Form 8-K(filed April 20, 2011)4(ddd) 1-12833Form 8-K(filed April 20, 2011)4(eee) 1-12833Form 8-K(filed April 20, 2011)4(fff) 1-12833Form 8-K(filed April 20, 2011)4(a)4.34.4-Second Supplemental Indenture, dated November 15, 2010, to theIndenture, dated October 6, 2010.-Third Supplemental Indenture, dated as of September 26, 2011, tothe Indenture, dated October 6, 2010.-Second Lien Pledge Agreement, dated October 6,2010, among TexasCompetitive Electric Holdings Company LLC, TCEH Finance, Inc.,the subsidiary guarantors named therein and The Bank of New YorkMellon Trust Company, N.A., as collateral agent for the benefit ofthe second lien secured parties.-Second Lien Security Agreement, dated October 6, 2010, amongTexas Competitive Electric Holdings Company LLC, TCEHFinance, Inc., the subsidiary guarantors named therein and The BankOf New York Mellon Trust Company, N.A., as collateral agent andas the initial second priority representative for the benefit of thesecond lien secured parties.4.5 -Second Lien Intercreditor Agreement, dated October 6, 2010, amongTexas Competitive Electric Holdings Company LLC, TCEHFinance, Inc., the subsidiary guarantors named therein, Citibank,N.A., as collateral agent for the senior collateral agent and theadministrative agent, The Bank ofNew York Mellon Trust Company,N.A., as the initial second priority representative.4(aaa)4.14.24.34.4-Form of Second Deed of Trust, Assignment of Leases and Rents,Security Agreement and Fixture Filing to Fidelity National TitleInsurance Company, as trustee, for the benefit of The Bank of NewYork Mellon Trust Company, N.A., as Collateral Agent and InitialSecond Priority Representative for the benefit of the Second LienSecured Parties, as Beneficiary.-Indenture, dated as of April 19, 2011, among Texas CompetitiveElectric Holdings Company LLC, TCEH Finance Inc., theGuarantors party thereto and The Bank of New York Mellon TrustCompany, N.A., as trustee, relating to 11.5% Senior Secured Notesdue 2020.-Form of Deed of Trust, Assignment of Leases and Rents, SecurityAgreement and Fixture Fling to Fidelity National Title InsuranceCompany, as trustee, for the benefit of Citibank, N.A., as CollateralAgent for the benefit of the Holders of the 11.5% Senior SecuredNotes due 2020, as Beneficiary.-Form of Deed of Trust and Security Agreement to Fidelity NationalTitle Insurance Company, as trustee, for the benefit ofCitibank, N.A.,as Collateral Agent for the benefit of the Holders of the 11.5% SeniorSecured Notes dues 2020, as Beneficiary.-Form of Subordination and Priority Agreement, among Citibank,N.A., as beneficiary under the First Lien Credit Deed of Trust, TheBank ofNew York Mellon Trust Company, N.A., as beneficiary underthe Second Lien Indenture Deed of Trust, Citibank, N.A., asbeneficiary under the First Lien Indenture Deed of Trust, TexasCompetitive Electric Holdings Company LLC and the subsidiaryguarantors party thereto.Energy Future Intermediate Holding Company LLC4(ggg) 1-12833Form 8-K (filedNovember 20, 2009)4.2 -Indenture, dated November 16, 2009, among Energy FutureIntermediate Holding Company LLC, EFIH Finance Inc. and TheBank of New York Mellon Trust Company, N.A., as trustee, relatingto 9.75% Senior Secured Notes due 2019.232 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit4(hhh) 1-12833 4.3Form 8-K(filed January 30, 2013)4(iii) 1-12833Form 8-K(filed August 18, 2010)4(ij)1-12833Form 8-K(filed January 30, 2013)4(kkk) 1-12833Form I0-Q (Quarterended March 31, 2011)(filed April 29, 2011)4(111) 1-12833Form 8-K(filed February 7, 2012)4(mmm) 1-12833Form 8-K(filed February 29, 2012)4(nnn) 1-12833Form 10-Q (Quarterended June 30, 2012)(filed July 31, 2012)4(ooo) 1-12833Form 8-K(filed August 17, 2012)4(ppp) 1-12833Form 8-K(filed August 17, 2012)4(qqq) 1-12833Form 8-K(filed October 24, 2012)4(rrr) 1-12833Form 8-K(filed December 5, 2012)4(sss) 1-12833Form 8-K(filed December 21,2012)4.14.44(e)4.14.14(a)4.24.14.14.14.1-Supplemental Indenture, dated January 25, 2013, to the indenture,dated November 16, 2009, among Energy Future IntermediateHolding Company LLC, EFIH Finance Inc. and The Bank of NewYork Mellon Trust Company, N.A., as trustee, relating to 9.75%Senior Secured Notes due 2019.-Indenture, dated August 17,2010, among Energy Future IntermediateHolding Company LLC, EFIH Finance Inc. and The Bank of NewYork Mellon Trust Company, N.A., as trustee, relating to 10.000%Senior Secured Notes due 2020.-First Supplemental Indenture, dated January 29, 2013, to theindenture, dated August 17,2010, among Energy Future IntermediateHolding Company LLC, EFIH Finance Inc. and The Bank of NewYork Mellon Trust Company, N.A., as trustee, relating to 10.000%Senior Secured Notes due 2020.-Indenture, dated as of April 25, 2011, among Energy FutureIntermediate Holding Company LLC, EFIH Finance, Inc. and TheBank of New York Mellon Trust Company, N.A., as trustee, relatingto 11% Senior Secured Second Lien Notes due 2021.-First Supplemental Indenture, dated February 6, 2012, to theindenture dated April 25, 2011, among Energy Future IntermediateHolding Company LLC, EFIH Finance Inc. and The Bank of NewYork Mellon Trust Company, N.A., as Trustee, relating to 11.750%Senior Secured Second Lien Notes due 2022.-Second Supplemental Indenture, dated February 28, 2012, to theindenture dated April 25, 2011, among Energy Future IntermediateHolding Company LLC, EFIH Finance Inc. and The Bank of NewYork Mellon Trust Company, N.A., as Trustee, relating to 11.750%Senior Secured Second Lien Notes due 2022.-Third Supplemental Indenture, dated May 31, 2012, to the indenturedated April 25, 2011, among Energy Future Intermediate HoldingCompany LLC, EFIH Finance Inc. and The Bank of New YorkMellon Trust Company, N.A., as Trustee, relating to 11.750% SeniorSecured Second Lien Notes due 2022.-Fourth Supplemental Indenture, dated August 14, 2012, amongEnergy Future Intermediate Holding Company LLC, EFIH FinanceInc. and the Bank of New York Mellon Trust Company, N.A., astrustee, relating to 11.75% Senior Secured Second Lien Notes due2022.-Indenture, dated August 14,2012, among Energy Future IntermediateHolding Company LLC, EFIH Finance Inc. and the Bank of NewYork Mellon Trust Company, N.A., as trustee, relating to 6.875%Senior Secured Notes due 2017.-First Supplemental Indenture, dated October 23, 2012, to theindenture dated August 14,2012, among Energy Future IntermediateHolding Company LLC, EFIH Finance Inc., and the Bank of NewYork Mellon Trust Company, N.A., as trustee, relating to 6.875%Senior Secured Notes due 2017.-Indenture, dated December 5, 2012, among Energy FutureIntermediate Holding Company LLC, EFIH Finance Inc., and theBank of New York Mellon Trust Company, N.A., as trustee, relatingto 11.25%/12.25% Senior Toggle Notes due 2018.-First Supplemental Indenture, dated December 19, 2012, to theindenture dated December 5, 2012, among Energy FutureIntermediate Holding Company LLC, EFIH Finance Inc., and theBank of New York Mellon Trust Company, N.A., as trustee, relatingto 11.25%/12.25% Senior Toggle Notes due 2018.233 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit4(ttt) 1-12833 4.5Form 8-K(filed January 30, 2013)4(uuu)4(vvv) 1-12833Form 10-Q (Quarterended March 31, 2011)(filed April 29, 2011)4(www) 1-12833Form 8-K(filed February 7, 2012)4(xxx) 1-12833Form 8-K(filed February 29, 2012)4(yyy) 1-12833Form 8-K(filed August 17, 2012)4(zzz) 1-12833Form 8-K(filed October 24, 2012)4(aaaa) 1-12833Form 8-K(filed December 5, 2012)4(f)4.24.24.34.24.2-Second Supplemental Indenture, dated January 29, 2013, to theindenture dated December 5, 2012, among Energy FutureIntermediate Holding Company LLC, EFIH Finance Inc., and theBank of New York Mellon Trust Company, N.A., as trustee, relatingto 11.25%/12.25% Senior Toggle Notes due 2018.-Third Supplemental Indenture, dated January 30, 2013, to theindenture, dated December 5, 2012, among Energy FutureIntermediate Holding Company LLC, EFIH Finance Inc., and theBank of New York Mellon Trust Company, N.A., as trustee, relatingto 11.25%/12.25% Senior Toggle Notes due 2018.-Junior Lien Pledge Agreement, dated as of April 25, 2011, fromEnergy Future Intermediate Holding Company LLC, as pledgor, toThe Bank of New York Mellon Trust Company, N.A., as collateraltrustee.-Registration Rights Agreement, dated February 6, 2012, amongEnergy Future Intermediate Holding Company LLC, EFIH FinanceInc. and the initial purchasers named therein, relating to 11.750%Senior Secured Second Lien Notes due 2022.-Registration Rights Agreement, dated February 28, 2012, amongEnergy Future Intermediate Holding Company LLC, EFIH FinanceInc. and the initial purchasers named therein, relating to 11.750%Senior Secured Second Lien Notes due 2022.-Registration Rights Agreement, dated August 14, 2012, amongEnergy Future Intermediate Holding Company LLC, EFIH FinanceInc. and the initial purchasers named therein.-Registration Rights Agreement, dated October 23, 2012, amongEnergy Future Intermediate Holding Company LLC, EFIH FinanceInc. and the initial purchasers named therein.-Registration Rights Agreement, dated as of December 5, 2012,among Energy Future Intermediate Holding Company LLC, EFIHFinance Inc. and the exchange holders named therein.(10)l0(a)Material ContractsManagement Contracts; Compensatory Plans, Contracts and Arrangements1-12833Form 8-K(filed May 23, 2005)10.610(p)-Energy Future Holdings Corp. Executive Change in Control Policyeffective May 20, 2005.-Amendment to the Energy Future Holdings Corp. Executive Changein Control Policy, dated December 23, 2008.10(b) 333-153529Amendment No. 2 toForm S-4 (filedDecember 23, 2008)10(c) 1-12833Form IO-K (2010)(filed February 18, 2011)10(d) 1-12833Form 8-K(filed May 23, 2005)10(e) 333-153529Amendment No. 2 toForm S-4 (filedDecember 23, 2008)10(e) -Amendment to the Energy Future Holdings Corp. Executive Changein Control Policy, dated December 20, 2010.10.710(n)10(f)-Energy Future Holdings Corp. 2005 Executive Severance Plan andSummary Plan Description.-Amendment to the Energy Future Holdings Corp. 2005 ExecutiveSeverance Plan and Summary Plan Description, dated December 23,2008.-Amendment to the Energy Future Holdings Corp. 2005 ExecutiveSeverance Plan and Summary Plan Description, dated December 10,2010.10(f)1-12833Form 1O-K (2010)(filed February 18, 2011)234 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit10(g) 1-12833Form 10-K (2007)(filed March 31, 2008)10(h) 1-12833Form 10-K (2009)(filed February 19, 2010)10(i)10(j)1-12833Form 10-K (2010)(filed February 18, 2011)1-12833Form 10-K (2008)(filed March 3, 2009)10(k) 1-12833Form 10-K (2009)(filed February 19, 2010)10(1)1-12833Form 10-K (2010)(filed February 18, 2011)10(m) 1-12833Form 10-K (2010)(filed February 18, 2011)10(n) 1-12833Form 10-K (2011)(filed February 21, 2012)10(o) 1-12833Form 10-K (2009)(filed February 19, 2010)10(a)10(ii)10(i)10(q)10(ee)10(l)10(m)10(n)10(dd)10(o)10(q)10(a)I0(b)10(a)10(b)10(f)-2007 Stock Incentive Plan for Key Employees of Energy FutureHoldings Corp. and its affiliates.-Amendment No. 1 to the 2007 Stock Incentive Plan for KeyEmployees of Energy Future Holdings Corp. and its Affiliates, datedJuly 14, 2009, effective as of December 23, 2008.-EFH Executive Annual Incentive Plan, effective as of January 1,2010.-EFH Second Supplemental Retirement Plan, effective as ofOctober 10, 2007.-Amendment to EFH Second Supplemental Retirement Plan, datedJuly 31, 2009.Second Amendment to EFH Second Supplemental Retirement Plan,dated April 9, 2010 with effect as of January 1, 2010.-Third Amendment to EFH Second Supplemental Retirement Plan,dated April 21, 2010 with effect as of January 1, 2010.-Fourth Amendment to EFH Second Supplemental Retirement Plan,dated June 17, 2011.-EFH Salary Deferral Program, effective January 1, 2010.-Amendment to EFH Salary Deferral Program, effective January 20,2011.-Second Amendment to EFH Salary Deferral Program, dated June 17,2011.-Third Amendment to the EFH Salary Deferral Program, effectiveSeptember 20, 2012.-Registration Rights Agreement, dated October 10, 2007, amongTexas Energy Future Holdings Limited Partnership, Energy FutureHoldings Corp. and the stockholders party thereto.Form of Stockholder's Agreement (for Directors) among EnergyFuture Holdings Corp., Texas Energy Future Holdings LimitedPartnership and the stockholder party thereto.-Form of Sale Participation Agreement (for Directors) between TexasEnergy Future Holdings Limited Partnership and the stockholderparty hereto.-Form of Management Stockholder's Agreement (For ExecutiveOfficers) among Energy Future Holdings Corp., Texas Energy FutureHoldings Limited Partnership and the stockholder party thereto.10(p)1-12833Form 1O-K (2010)(filed February 18, 2011)1O(q) 1-12833Form 10-K (2011)(filed February 21, 2012)10(r) 1-12833Form lO-Q (Quarterended September 30,2012)(filed October 30, 2012)10(s)10(t)1-12833Form 1O-K (2007)(filed March 31, 2008)1-12833Form I0-Q (Quarterended March 31, 2008)(filed May 15, 2008)10(u) 1-12833Form 10-Q (Quarterended March 31, 2008)(filed May 15, 2008)10(v) 1-12833Form IO-Q (Quarterended June 30, 2008)(filed August 14, 2008)235 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit10(w) 1-12833 10(g)Form IO-Q (Quarterended June 30, 2008)(filed August 14, 2008)10(x) 1-12833Form 10-K (2009)(filed February 19, 2010)10(y) 1-12833Form IO-Q (Quarterended September 30,2011) (filed October 28,2011)10(z)1-12833Form IO-K (2011)(filed February 21, 2012)10(m)10(i)10(y)10(z)10(f)10(bb)10(aa) 1-12833Form 10-K (2011)(filed February 21, 2012)10(bb) 1-12833Form 10-K (2007)(filed March 31, 2008)10(cc) 1-12833Form IO-K (2011)(filed February 21, 2012)10(dd)10(ee) 1-12833Form IO-K (2007)(filed March 31, 2008)10(ff) 1-12833Form 10-K (2007)(filed March 31, 2008)10(gg) 1-12833Form 10-Q (Quarterended September 30,2011) (filed October 28,2011)10(hh) 1-12833Form 1O-K (2010)(filed February 18, 2011)10(ii) 1-12833Form IO-Q (Quarterended September 30,2011) (filed October 28,2011)10(6j) 1-12833Form 10-Q (Quarterended June 30, 2012)(filed July 31, 2012)10(kk) 1-12833Form 10-Q (Quarterended September 30,2011) (filed October 28,2011)-Form of Sale Participation Agreement (For Executive Officers)between Texas Energy Future Holdings Limited Partnership and thestockholder party thereto.-Form of Amended and Restated Non-Qualified Stock OptionAgreement (For Executive Officers) between Energy FutureHoldings Corp. and the optionee thereto.-Form of Restricted Stock Unit Agreement between Energy FutureHoldings Corp. and the stockholder party thereto.-EFH Corp. Retention Award Plan (For Key Employees), effectiveDecember 20, 2011.-Form of Participation Agreement (For Key Employees) betweenEnergy Future Holdings Corp. and the participant party thereto.-Energy Future Holdings Corp. Non-Employee DirectorCompensation Arrangements.-Second Amended and Restated Consulting Agreement, dated January1, 2012, between Energy Future Holdings Corp. and Donald L.Evans.-Amended and Restated Employment Agreement, dated effectiveDecember 26,2012, between Energy Future Holdings Corp. and JohnYoung.-Management Stockholder's Agreement, dated February 1, 2008,anmong Energy Future Holdings Corp., Texas Energy Future HoldingsLimited Partnership and John Young.-Sale Participation Agreement, dated February 1, 2008, betweenTexas Energy Future Holdings Limited Partnership and John F.Young.-Amended and Restated Employment Agreement, dated October 17,2011, among EFH Corporate Services Company, Energy FutureHoldings Corp. and Paul M. Keglevic.-Deferred Share Agreement, dated July 1, 2008, between EnergyFuture Holdings Corp. and Paul Keglevic.-First Amendment to Deferred Share Agreement, dated October 17,2011, between Energy Future Holdings Corp. and Paul Keglevic.-Second Amendment to Deferred Share Agreement, dated July 25,2012, between Energy Future Holdings Corp. and Paul M. Keglevic.-Amended and Restated Employment Agreement, dated October 17,2011, among Luminant Holding Company LLC, Energy FutureHoldings Corp. and David A. Campbell.I10(r)10(s)I 0(b)IO(ee)I0(h)l0(a)lO(e)236 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit10(11) 1-12833Form 10-K (2007)(filed March 31, 2008)10(mm) 1-12833Form 10-K (2010)(filed February 18, 2011)10(nn) 1-12833Form 10-Q (Quarterended September 30,2011) (filed October 28,2011)10(oo) 1-12833Form IO-K (2007)(filed March 31, 2008)10(pp) 1-12833Form 10-K (2007)(filed March 31, 2008)10(qq)10(rr)10(ss) 1-12833Form 10-Q (Quarterended September 30,2011) (filed October 28,2011)10(tt) 1-12833Form 10-Q (Quarterended March 31, 2012)(filed May 1, 2012)10(uu) 1-12833Form 10-Q (Quarterended March 31, 2012)(filed May 1, 2012)10(y)10(hh)10(d)10(fo10(nn)-Additional Payment Agreement, dated October 10, 2007, amongEnergy Future Holdings Corp., Texas Energy Future HoldingsLimited Partnership, Texas Competitive Electric Holdings CompanyLLC and David Campbell.-Deferred Share Agreement, dated May 20, 2008, between EnergyFuture Holdings Corp. and David Campbell.-Amended and Restated Employment Agreement, dated October 17,2011, among TXU Retail Company LLC, Energy Future HoldingsCorp. and James A. Burke.-Additional Payment Agreement, dated October 10, 2007, amongEnergy Future Holdings Corp., Texas Energy Future HoldingsLimited Partnership, Texas Competitive Electric Holdings CompanyLLC and James Burke.-Deferred Share Agreement, dated October 9, 2007, between TexasEnergy Future Holdings Limited Partnership and James Burke.-Amended and Restated Employment Agreement, dated effectiveJanuary 1, 2013, among Luminant Holding Company LLC, EnergyFuture Holdings Corp. and Mark Allen McFarland.-Not used.-Employment Agreement, dated October 17, 2011, among EFHCorporate Services Company, Energy Future Holdings Corp., andJohn D. O'Brien, Jr.-Employment Agreement, dated April 27, 2012, among EFHCorporate Services Company, Energy Future Holdings Corp., andStacey H. Dord.-Employment Agreement, dated April 27, 2012, among EFHCorporate Services Company, Energy Future Holdings Corp., andCarrie L. Kirby.10(g)10(a)10(b)Credit Agreements and Related Agreements10(vv) 333-100240Form 8-K(filed October 11,2011)10(ww) 333-100240Form 8-K(filed May 15, 2012)10.110.1-Amended and Restated Revolving Credit Agreement, dated as ofOctober 11, 2011, among Oncor Electric Delivery Company LLC,as borrower, the lenders listed therein, JPMorgan Chase Bank, N.A.,as administrative agent for the lenders, JPMorgan Chase Bank, N.A.,as swingline lender, and JPMorgan Chase Bank, N.A., Barclays BankPLC, The Royal Bank of Scotland plc, Bank of America, N.A. andCitibank N.A., as fronting banks for letters of credit issuedthereunder.-Joinder Agreement, dated as of May 15, 2012, by and among Oncor,as Borrower, JPMorgan Chase Bank, N.A., as administrative agentunder the Credit Agreement, swingline lender and fronting bank,Barclays Bank PLC, Bank of America, N.A., Citibank, N.A. and TheRoyal Bank of Scotland PLC, as fronting banks, and each partyidentified as an "Incremental Lender" on the signature pages thereto.237 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit1O(xx) 333-171253 10(rr)Post-EffectiveAmendment #1 toForm S-4(filed February 7, 2011)IO(yy) 1-12833Form 8-K(filed August 10, 2009)10(zz) 1-12833Form 8-K(filed April 20, 2011)10(aaa) 1-12833Form 8-K(filed January 7, 2013)10(bbb) 1-12833Form 8-K(filed January 7, 2013)10(ccc) 1-12833Form 10-K (2007)(filed March 31, 2008)10(ddd) 1-12833*Form 10-K (2007)(filed March 31, 2008)10(eee) 1-12833Form 10-Q (Quarterended March 31, 2011)(filed April 29, 2011)10(ff) 1-12833Form 8-K(filed August 10, 2009)10(ggg) 1-12833Form 8-K(filed August 10, 2009)10.110.110.110.210(ss)IO(vv)10(b)10.210.3-$24,500,000,000 Credit Agreement, dated October 10, 2007, amongEnergy Future Competitive Holdings Company; Texas CompetitiveElectric Holdings Company LLC, as the borrower; the several lendersfrom time to time parties thereto; Citibank, N.A., as administrativeagent, collateral agent, swingline lender, revolving letter of creditissuer and deposit letter of credit issuer; Goldman Sachs CreditPartners L.P., as posting agent, posting syndication agent and postingdocumentation agent; JPMorgan Chase Bank, N.A., as syndicationagent and revolving letter of credit issuer; Citigroup Global MarketsInc., J.P. Morgan Securities Inc., Goldman Sachs Credit Partners L.P.,Lehman Brothers Inc., Morgan Stanley Senior Funding, Inc. andCredit Suisse Securities (USA) LLC, as joint lead arrangers andbookrunners; Goldman Sachs Credit Partners L.P., as posting leadarranger and bookrunner; Credit Suisse, Goldman Sachs CreditPartners L.P., Lehman Commercial Paper Inc., Morgan StanleySenior Funding, Inc., as co-documentation agents; and J. Aron &Company, as posting calculation agent.-Amendment No. 1, dated August 7, 2009, to the $24,500,000,000Credit Agreement.-Amendment No. 2, dated April 7,2011, to the $24,500,000,000 CreditAgreement.-December 2012 Extension Amendment, dated January 4, 2013, tothe $24,500,000,000 Credit Agreement.-Incremental Amendment No. 1, dated January 4, 2013, to the$24,500,000,000 Credit Agreement.-Guarantee, dated October 10, 2007, by the guarantors party theretoin favor of Citibank, N.A., as collateral agent for the benefit of thesecured parties under the $24,500,000,000 Credit Agreement, datedOctober 10, 2007.-Form of Deed of Trust, Assignment of Leases and Rents, SecurityAgreement and Fixture Filing to Fidelity National Title InsuranceCompany, as trustee, for the benefit ofCitibank, N.A., as beneficiary.-Form of First Amendment to Deed of Trust, Assignment of Leasesand Rents, Security Agreement and Fixture Filing to Fidelity NationalTitle Insurance Company, as trustee, for the benefit ofCitibank, N.A.,as Beneficiary.-Amended and Restated Collateral Agency and IntercreditorAgreement, dated October 10, 2007, as amended and restated as ofAugust 7, 2009, among Energy Future Competitive HoldingsCompany; Texas Competitive Electric Holdings Company LLC; thesubsidiary guarantors party thereto; Citibank, N.A., as administrativeagent and collateral agent; Credit Suisse Energy LLC, J. Aron &Company, Morgan Stanley Capital Group Inc., Citigroup EnergyInc., each as a secured hedge counterparty; and any other person thatbecomes a secured party pursuant thereto.-Amended and Restated Security Agreement, dated October 10, 2007,as amended and restated as of August 7, 2009, among TexasCompetitive Electric Holdings Company LLC, the subsidiarygrantors party thereto, and Citibank, N.A., as collateral agent for thebenefit of the first lien secured parties, including the secured partiesunder the $24,500,000,000 Credit Agreement, dated October 10,2007.238 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit10(hhh) 1-12833 10.4Form 8-K(filed August 10, 2009)10(iii) 1-12833Form 8-Kfiled November 20, 2009)10(jj) 1-12833Form 8-K(filed November 20,2009)4.34.4Other Material Contracts10(kkk) 1-12833 FormI 0-K (2003)(filed March 15, 2004)10(1ll) 1-12833Form 10-Q (Quarterended June 30, 2007)(filed August 9, 2007)10(mmm) 333-100240Form 10-K (2004)(filed March 23, 2005)10(nnn) 1-12833Form 10-K (2006)(filed March 2, 2007)10(ooo) 1-12833Form 10-K (2007)(filed March 31, 2008)lO(ppp) 1-12833Form 10-K (2007)(filed March 31, 2008)1O(qqq) 333-100240Form 1O-K (2010)(filed February 18, 2011)10(rrr) 1-12833Form IO-K (2007)(filed March 31, 2008)10(sss) 1-12833Form 10-K (2007)(filed March 31, 2008)10(ttt) 1-12833Form 10-K (2007)(filed March 31, 2008)10(qq)10.110(i)I 0(iii)I 0(eee)1 0(ffm)l 0(ae)I 0(sss)l0(ttt)I O(uuu)-Amended and Restated Pledge Agreement, dated October 10, 2007,as amended and restated as ofAugust 7,2009, among Energy FutureCompetitive Holdings Company, Texas Competitive ElectricHoldings Company LLC, the subsidiary pledgors party thereto, andCitibank, N.A., as collateral agent for the benefit first lien securedparties, including the secured parties under the $24,500,000,000Credit Agreement, dated October 10, 2007.-Pledge Agreement, dated November 16, 2009, made by EnergyFuture Intermediate Holding Company LLC and the additionalpledgers to The Bank of New York Mellon Trust Company, N.A., ascollateral trustee for the holders of parity lien obligations.-Collateral Trust Agreement, dated November 16, 2009, amongEnergy Future Intermediate Holding Company LLC, The Bank ofNew York Mellon Trust Company, N.A., as first lien trustee and ascollateral trustee, and the other secured debt representatives partythereto.-Lease Agreement, dated February 14, 2002, between State StreetBank and Trust Company of Connecticut, National Association, anowner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust,as lessor and EFH Properties Company, as Lessee (Energy PlazaProperty).-First Amendment, dated June 1, 2007, to Lease Agreement, datedFebruary 14, 2002.-Agreement, dated March 10, 2005, between Oncor Electric DeliveryCompany LLC and TXU Energy Company LLC, allocating to OncorElectric Delivery Company LLC the pension and post-retirementbenefit costs for all Oncor Electric Delivery Company LLCemployees who had retired or had terminated employment as vestedemployees prior to January 1, 2002.-Amended and Restated Transaction Confirmation by GenerationDevelopment Company LLC, dated February 2007 (subsequentlyassigned to Texas Competitive Electric Holdings Company LLC onOctober 10, 2007) (confidential treatment has been requested forportions of this exhibit).-Stipulation as approved by the PUCT in Docket No. 34077.-Amendment to Stipulation Regarding Section 1, Paragraph 35 andExhibit B in Docket No. 34077.-PUCT Order on Rehearing in Docket No. 34077.-ISDA Master Agreement, dated October 25, 2007, between TexasCompetitive Electric Holdings Company LLC and Goldman SachsCapital Markets, L.P.-Schedule to the ISDA Master Agreement, dated October 25, 2007,between Texas Competitive Electric Holdings Company LLC andGoldman Sachs Capital Markets, L.P.-Form of Confirmation between Texas Competitive Electric HoldingsCompany LLC and Goldman Sachs Capital Markets, L.P.239 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit10(uuu) 1-12833 10(vvv)Form 10-K (2007)(filed March 31, 2008)10(vvv) 1-12833Form 10-K (2007)(filed March 31, 2008)10(www) 1-12833Form 10-K (2007)(filed March 31, 2008)10(xxx) 1-12833Form 10-K (2007)(filed March 31, 2008)10(yyy) 1-12833Form 10-K (2007)(filed March 31, 2008)10(zzz) 1-12833Form 10-Q (Quarterended September 30,2008) (filed November 6,2008)10(aaaa) 333-100240Form 10-K (2008)(filed March 3, 2009)10(bbbb) 333-100240Form 10-Q (Quarterended September 30,2008) (filed November 6,2008)10(cccc) 333-100240Form 10-Q (Quarterended September 30,2008) (filed November 6,2008)l0(dddd) 333-100240Form I0-Q (Quarterended September 30,2008) (filed November 6,2008)lO(eeee) 1-12833Form IO-Q (Quarterended September 30,2012)(filed October 30, 2012)10(flff) 1-12833Form 8-K(filed December 6, 2012)10(www)1O(xxx)10(yyy)10(cccc)10(g)3(c)4(c)4(d)l0(b)10(b)10.1ISDA Master Agreement, dated October 29, 2007, between TexasCompetitive Electric Holdings Company LLC and Credit SuisseInternational.-Schedule to the ISDA Master Agreement, dated October 29, 2007,between Texas Competitive Electric Holdings Company LLC andCredit Suisse International.-Form of Confirmation between Texas Competitive Electric HoldingsCompany LLC and Credit Suisse International.-Management Agreement, dated October 10, 2007, among EnergyFuture Holdings Corp., Texas Energy Future Holdings LimitedPartnership, Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P.,Goldman, Sachs & Co. and Lehman Brothers Inc.-Indemnification Agreement, dated October 10, 2007, among TexasEnergy Future Holdings Limited Partnership, Energy FutureHoldings Corp., Kohlberg Kravis Roberts & Co., L.P., TPG Capital,L.P. and Goldman, Sachs & Co.Second Amended and Restated Limited Liability CompanyAgreement of Oncor Electric Delivery Holdings Company LLC,dated November 5, 2008.-Amendment No. 1, dated February 18, 2009, to Second Amendedand Restated Limited Liability Company Agreement of OncorElectric Delivery LLC.-Investor Rights Agreement, dated November 5, 2008, among OncorElectric Delivery Company LLC, Oncor Electric Delivery HoldingsCompany LLC, Texas Transmission Investment LLC and EnergyFuture Holdings Corp.-Registration Rights Agreement, dated November 5, 2008, amongOncor Electric Delivery Company LLC, Oncor Electric DeliveryHoldings Company LLC, Texas Transmission Investment LLC andEnergy Future Holdings Corp.-Amended and Restated Tax Sharing Agreement, dated November 5,2008, among Oncor Electric Delivery Company LLC, Oncor ElectricDelivery Holdings Company LLC, Oncor Management InvestmentLLC, Texas Transmission Investment LLC, Energy FutureIntermediate Holding Company LLC and Energy Future HoldingsCorp.-Federal and State Income Tax Allocation Agreement, effectiveJanuary 1, 2010, by and among members of the Energy FutureHoldings Corp. consolidated group.First Lien Trade Receivables Financing Agreement, dated as ofNovember 30, 2012, among TXU Energy Receivables CompanyLLC, as Borrower, TXU Energy Retail Company LLC, as CollectionAgent, certain Investors, CitiBank, N.A., as the Initial Bank, andCitiBank, N.A., as Administrative Agent and as a Group ManagingAgent.240 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit10(gggg) 1-12833 10.2Form 8-K(filed December 6, 2012)-Trade Receivables Sale Agreement, dated as of November 30, 2012,among TXU Energy Retail Company LLC, as Originator, asCollection Agent and as Originator Agent and TXU EnergyReceivables Company LLC, as Buyer, and Energy Future HoldingsCorp.(12)12(a)(21)21(a)(23)23(a)23(b)Statement Regarding Computation of Ratios-Computation of Ratio of Earnings to Fixed Charges.Subsidiaries of the Registrant-Subsidiaries of Energy Future Holdings Corp.Consent of Experts-Consent of Deloitte & Touche LLP, an independent registered publicaccounting firm, relating to the consolidated financial statements ofEnergy Future Holdings Corp.-Consent of Deloitte & Touche LLP, an independent registered publicaccounting firm, relating to the consolidated financial statements ofOncor Electric Delivery Holdings Company LLC31 Rule 13a -14(a)/15d-14(a) Certifications31(a)31(b)32 Section 1350 Certifications-Certification of John F. Young, principal executive officer of EnergyFuture Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.-Certification of Paul M. Keglevic, principal financial officer ofEnergy Future Holdings Corp., pursuant to Section 302 of theSarbanes-Oxley Act of 2002.-Certification of John F. Young, principal executive officer of EnergyFuture Holdings Corp., pursuant to 18 U.S.C. Section 1350, asadopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.-Certification of Paul M. Keglevic, principal financial officer ofEnergy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350,as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of2002.32(a)32(b)(95)95(a)(99)Mine Safety Disclosures-Mine Safety DisclosuresAdditional Exhibits99(a) 33-55408Post-EffectiveAmendment No. I toForm S-3 (filed July,1993)99(b)99(b)-Amended Agreement dated January 30, 1990, between Energy FutureCompetitive Holdings Company and Tex-La Electric Cooperative ofTexas, Inc.-Energy Future Holdings Corp. Consolidated Adjusted EBITDAreconciliation for the years ended December 31, 2012 and 2011.-Texas Competitive Electric Holdings Company LLC ConsolidatedAdjusted EBITDA reconciliation for the years ended December 31,2012 and 2011.-Energy Future Intermediate Holding Company LLC ConsolidatedAdjusted EBITDA reconciliation for the years ended December 31,2012 and 2011.99(c)99(d)241 Table of ContentsPreviously Filed* With File AsExhibits Number Exhibit99(e) -Oncor Electric Delivery Holdings Company LLC financialstatements presented pursuant to Rules 3-09 and 3-16 of RegulationS-X.XBRL Data Files101.INS -XBRL Instance Document101.SCH -XBRL Taxonomy Extension Schema Document101.CAL -XBRL Taxonomy Extension Calculation DocumentI0I.DEF -XBRL Taxonomy Extension Definition Document101.LAB -XBRL Taxonomy Extension Labels Document101.PRE -XBRL Taxonomy Extension Presentation Document* Incorporated herein by reference** Certain instruments defining the rights of holders of long-term debt of the Company's subsidiaries included in the financial statementsfiled herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10 percent of the total assetsof the Company and its subsidiaries on a consolidated basis. The Company hereby agrees, upon request of the SEC, to furnish a copy ofany such omitted instrument.242 Table of ContentsSIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Energy Future HoldingsCorp. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.ENERGY FUTURE HOLDINGS CORP.Date: February 19, 2013 By /s/ JOHN F. YOUNG(John F. Young, President and Chief Executive Officer)Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by thefollowing persons on behalf of Energy Future Holdings Corp. and in the capacities and on the date indicated.Signature/s/ JOHN F. YOUNG(John F. Young, President and Chief Executive Officer)/s/ PAUL M. KEGLEVIC(Paul M. Keglevic, Executive Vice President and Chief FinancialOfficer)/s/ STANLEY J. SZLAUDERBACH(Stanley J. Szlauderbach, Senior Vice President and Controller)/s/ DONALD L. EVANS(Donald L. Evans, Chairman of the Board)/s/ ARCILIA C. ACOSTA(Arcilia C. Acosta)/s/ DAVID BONDERMAN(David Bonderman)/s/ THOMAS D. FERGUSON(Thomas D. Ferguson)TitlePrincipal ExecutiveOfficer and DirectorPrincipal Financial OfficerPrincipal Accounting Officer/s/ BRANDON A. FREIMAN(Brandon A. Freiman)/s/ SCOTT LEBOVITZ(Scott Lebovitz)DirectorDirectorDirectorDirectorDirectorDirectorDirectorDirectorDirectorDirectorDirectorDirectorDateFebruary 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013February 19, 2013Is! MARC S LIPSCHULTZ(Marc S. Lipschultz)/s/ MICHAEL MACDOUGALL(Michael MacDougall)/s/ KENNETH PONTARELLI(Kenneth Pontarelli)/s/ WILLIAM K. REILLY(William K. Reilly)/s/ JONATHAN D. SMIDT(Jonathan D. Smidt)/s/ KNEELAND YOUNGBLOOD(Kneeland Youngblood)243 Exhibit 31(a)ENERGY FUTURE HOLDINGS CORP.Certificate Pursuant to Section 302of Sarbanes -Oxley Act of 2002I, John F. Young, certify that:I. I have reviewed this annual report on Form 10-K of Energy Future Holdings Corp.;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which such statements were made, not misleading with respect tothe period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a-I5(f) and 15d-15(f)) for the registrant and have:a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed underour supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period in which this report is being prepared;b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles;c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusionsabout the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based onsuch evaluation; andd. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during theregistrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materiallyaffected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalentfunctions):a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reportingwhich are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financialinformation; andb. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: February 19, 2013 /s/ JOHN F. YOUNGName: John F. YoungTitle: President and Chief Executive Officer Exhibit 3 1(b)ENERGY FUTURE HOLDINGS CORP.Certificate Pursuant to Section 302of Sarbanes -Oxley Act of 2002I, Paul M. Keglevic, certify that:1. I have reviewed this annual report on Form 10-K of Energy Future Holdings Corp.;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which such statements were made, not misleading with respect tothe period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a-I 5(e) and I5d-I 5(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a-15(f) and 15d-15(f)) for the registrant and have:a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed underour supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period in which this report is being prepared;b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles;c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusionsabout the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based onsuch evaluation; andd. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during theregistrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materiallyaffected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalentfunctions):a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reportingwhich are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financialinformation; andb. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: February 19, 2013 /s/ PAUL M. KEGLEVICName: Paul M. KeglevicTitle: Executive Vice President and Chief Financial Officer Exhibit 32(a)ENERGY FUTURE HOLDINGS CORP.Certificate Pursuant to Section 906of Sarbanes -Oxley Act of 2002CERTIFICATION OF CEOThe undersigned, John F. Young, President and Chief Executive Officer of Energy Future HoldingsCorp. (the "Company"), DOES HEREBY CERTIFY that, to his knowledge:I. The Company's Annual Report on Form 10-K for the period ended December 31,2012 (the "Report")fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of1934, as amended; and2. Information contained in the Report fairly presents, in all material respects, the financial conditionand results of operations of the Company.IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 19th dayof February, 2013./s/ JOHN F. YOUNGName: John F. YoungTitle: President and Chief Executive OfficerA signed original of this written statement required by Section 906 has been provided to Energy Future Holdings Corp. and willbe retained by Energy Future Holdings Corp. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)ENERGY FUTURE HOLDINGS CORP.Certificate Pursuant to Section 906of Sarbanes -Oxley Act of 2002CERTIFICATION OF CFOThe undersigned, Paul M. Keglevic, Executive Vice President and Chief Financial Officer of EnergyFuture Holdings Corp. (the "Company"), DOES HEREBY CERTIFY that, to his knowledge:1, The Company's Annual Report on Form 10-K for the period ended December 31,2012 (the "Report")fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of1934, as amended; and2. Information contained in the Report fairly presents, in all material respects, the financial conditionand results of operations of the Company.IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 19th dayof February, 2013.Is/ PAUL M. KEGLEVICName: Paul M. KeglevicTitle: Executive Vice President and Chief FinancialOfficerA signed original of this written statement required by Section 906 has been provided to Energy Future Holdings Corp. and willbe retained by Energy Future Holdings Corp. and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 95(a)Mine Safety DisclosuresSafety is a top priority in all our businesses, and accordingly, it is a key component of our focus on operational excellence,our employee performance reviews and employee compensation. Our health and safety program objectives are to prevent workplaceaccidents and ensure that all employees return home safely and comply with all regulations.We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities.These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safetyand Health Act of 1977, as amended (the Mine Act), as well as other regulatory agencies such as the RRC. The MSHA inspectsUS mines, including ours, on a regular basis and if it believes a violation of the Mine Act or any health or safety standard or otherregulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citationsand orders can be contested and appealed to the Federal Mine Safety and Health Review Commission (FMSHRC), which oftenresults in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. The number ofcitations, orders and proposed assessments vary depending on the size of the mine as well as other factors.Disclosures related to specific mines pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer ProtectionAct and Item 104 of Regulation S-K sourced from data documented at January 3, 2013 in the MSHA Data Retrieval System forthe twelve months ended December 31, 2012 (except pending legal actions, which are at December 31, 2012), are as follows:ReceivedReceived Notice of LegalTotal Dollar Total Notice of Potential ActionsSection Section Value of Number Pattern of to Have Pending Legal Legal104 104(d) MSHA of Violations Pattern at Last Actions ActionsS and S Section Citations Section Section Assessments Mining Under Under Day of Initiated ResolvedCitations 104(b) and I I0(b)(2) 107(a) Proposed Related Section Section Period During DuringMine (a) (b) Orders Orders Violations Orders (c) Fatalities 104(e) 104(e) (d) Period PeriodBeckville 2 --25 --6 2 2Big Brown 7 --6 ---3 3 2Kosse 10 --144 --5 2 -Oak Hill ---I ---2 --Sulphur Springs 4 --6 ---1 1 4Tatum 3 --5 ---2 --Three Oaks 8 -1 --76 ---3 2 ITurlington ------I I -Winfield South I --I --I I I(a) Excludes mines for which there were no applicable events.(b) Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injuryif left unabated.(c) Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in thetwelve months ended December 31, 2012, including but not limited to Sections 104, 107 and 110 citations and orders thatare not required to be reported.(d) Pending actions before the FMSHRC involving a coal or other mine. All 24 are contests of proposed penalties. Exhibit 99(b)Energy Future Holdings Corp. ConsolidatedAdjusted EBITDA Reconciliation(millions of dollars)Net lossIncome tax benefitInterest expense and related chargesDepreciation and amortizationEBITDAOncor Holdings distributions of earningsInterest incomeAmortization of nuclear fuelPurchase accounting adjustments (a)Impairment of goodwillImpairment and write-down of other assets (b)Debt extinguishment gainsEquity in earnings of unconsolidated subsidiaryUnrealized net (gain) loss resulting from commodity hedging and trading transactionsEBITDA amount attributable to consolidated unrestricted subsidiariesNoncash compensation expense (c)Transition and business optimization costs (d)Transaction and merger expenses (e)Restructuring and other (f)Charges related to pension plan actions (g)Expenses incurred to upgrade or expand a generation station (h)Adjusted EBITDA per Incurrence CovenantAdd Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)Adjusted EBITDA per Restricted Payments CovenantYear Ended December 31,2012 2011$ (3,360) $ (1,913)(1,232) (1,134)3,508 4,2941,373 1,499$ 289 $ 2,746147 116(2) (2)156 14274 2041,20048 433(51)(270) (286)1,526 (58)411 1335 3939 3715 80285100 100$ 3,657 $ 3,5131,600 1,523$ 5,257 $ 5,036(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements,environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclearfuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Adjustments in 2011include $46 million related to an asset sale.(b) Impairment of assets in 2011 includes impairment of emission allowances and certain mining assets due to EPA rule issued in July 2011.(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and excludecapitalized amounts.(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costsrelated to generation plant reliability and supply chain efficiency initiatives.(e) Transaction and merger expenses primarily represent Sponsor Group management fees.(f) Restructuring and other in 2011 includes gains on termination of a long-term power sales contract and settlement of amounts due fromhedging/trading counterparty, fees related to the amendment and extension of the TCEH Senior Secured Facilities, and reversal of certainliabilities accrued in purchase accounting.(g) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employeesof EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pensionobligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensiveincome.(h) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs. Exhibit 99(c)Texas Competitive Electric Holdings Company LLC ConsolidatedAdjusted EBITDA Reconciliation(millions of dollars)Net lossIncome tax benefitInterest expense and related chargesDepreciation and amortizationEBITDAInterest incomeAmortization of nuclear fuelPurchase accounting adjustments (a)Impairment of goodwillImpairment and write-down of other assets (b)Unrealized net (gain) loss resulting from commodity hedging and trading transactionsEBITDA amount attributable to consolidated unrestricted subsidiariesCorporate depreciation, interest and income tax expenses included in SG&A expenseNoncash compensation expense (c)Transition and business optimization costs (d)Transaction and merger expenses (e)Restructuring and other (f)Charges related to pension plan actions (g)Expenses incurred to upgrade or expand a generation station (h)Adjusted EBITDA per Incurrence CovenantExpenses related to unplanned generation station outagesPro forma adjustment for Oak Grove 2 reaching 70% capacity in Q2 2011 (i)Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (j)Adjusted EBITDA per Maintenance CovenantYear Ended December 31,2012 2011$ (2,948) $ (1,740)(894) (917)2,752 3,6991,343 1,470$ 253 $ 2,512(46) (87)156 14255 1571,2006 4301,526 (58)(4) (7)1773338141612423772141100 100$ 3,496 $ 3,36878 181-- 27-8$ 3,574 $ 3,584(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements,environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclearfuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Adjustments in 2011include $46 million related to an asset sale.(b) Impairment of assets in 2011 includes impairment of emission allowances and certain mining assets due to EPA rule issued in July 2011.(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and excludecapitalized amounts.(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costsrelated to generation plant reliability and supply chain efficiency initiatives.(e) Transaction and merger expenses primarily represent Sponsor Group management fees.(f) Restructuring and other in 2011 includes gains on termination of a long-term power sales contract and settlement of amounts due fromhedging/trading counterparty, fees related to the amendment and extension of the TCEH Senior Secured Facilities, and reversal of certainliabilities accrued in purchase accounting.(g) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employeesof EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pensionobligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensiveincome,(h) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs.(i) Pro forma adjustment for the year ended 2011 represents the annualization of the actual nine months ended December 31, 2011 EBITDAresults for Oak Grove 2, which achieved the requisite 70% average capacity factor in the second quarter 2011.(j) Primarily pre-operating expenses relating to Oak Grove and Sandow 5. Exhibit 99(d)Energy Future Intermediate Holding Company LLC ConsolidatedAdjusted EBITDA Reconciliation(millions of dollars)Net incomeIncome tax expenseInterest expense and related chargesEBITDAOncor Holdings distributions of earningsInterest incomeEquity in earnings of unconsolidated subsidiary (net of tax)Adjusted EBITDA per Incurrence CovenantAdd Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)Adjusted EBITDA per Restricted Payments CovenantYear Ended December 31,2012 2011$ 315 $ 41727 73526 348$ 868 $ 838147 116(598) (552)(270) (286)$ 147 $ 1161,600 1,523$ 1,747 $ 1,639

Enclosure

8 with TXX-13095Additional Documentation forEnergy Future Competitive Holdings Company LLCTexas Certificate of Conversion of EFCH Company to EFCH Company LLCDelaware Certificate of Conversion of EFCH Company (TX) to EFCH Company LLC (DE)Limited Liability Company Agreement of Energy Future Competitive Holdings Company LLC2012 10-K for Energy Future Competitive Holdings CompanyMarch 31, 2013 10-Q for Energy Future Competitive Holdings Company LLC Corporations SectionP.O.Box 13697Austin, Texas 78711-3697John SteenSecretary of StateOffice of the Secretary of StateCERTIFICATE OF CONVERSIONThe undersigned, as Secretary of State of Texas, hereby certifies that a filing instrument forEnergy Future Competitive Holdings CompanyFile Number: 62278000Converting it toEnergy Future Competitive Holdings Company LLCFile Number: [Entity not of Record, Filing Number Not Available]has been received in this office and has been found to conform to law. ACCORDINGLY, theundersigned, as Secretary of State, and by virtue of the authority vested in the secretary by law, herebyissues this certificate evidencing the acceptance and filing of the conversion on the date shown below.Dated: 04/15/2013Effective: 04/15/2013John SteenSecretary of StatePhone: (512) 463-5555Prepared by: Lisa SartinCome visit us on the internet at http://wwvw. sos. state. U. us!Fax: (512) 463-5709TID: 10340Dial: 7-1-1 for Relay ServicesDocument: 475847720002 Form 632 This space reserved for office use.(Revised 05/11)Return in duplicate to:Secretary of StateP.O. Box 13697 Certificate of Conversion E I --. eAustin, TX 78711-3697 of a th tee512 463-5555 kn "

• istaFAX: 512 463-5709 Corporation Converting seetalto a bR A 5 70Filing Fee: See instructions Limited Liability Company ser'VolConiverthing ntityl rinforaionThe name of the converting corporation is:Energy Future Competitive Holdings CompanyThe jurisdiction of formation of the corporation is: TexasThe date of formation of the corporation is: September 17, 1982The file number, if any, issued to the corporation by the secretary of state, is: 62278000Pla ' n o f C-6iinieion--Alternative StatementsThe corporation named above is converting to a limited liability company. The name of the limitedliability company is:Energy Future Competitive Holdings Company LLCThe limited liability company will be fonned under the laws of: DelawareEl The plan of conversion is attached.If the plan of conversion is not attached, the following statements must be completed.IZ Instead of attaching the plan of conversion, the corporation certifies to the following statements:A signed plan of conversion is on file at the principal place of business of the corporation, theconverting entity. The address of the principal place of business of the corporation is:Energy Plaza, 1601 Bryan StreetDallasTX USA 75201-3411Street or Mailing AddressCi0,Staoe Count?), Zip CodeA signed plan of conversion will be on file after the conversion at the principal place of.business ofthe limited liability company, the converted entity. The address of the principal place of business ofthe limited liability company is:Energy Plaza, 1601 Bryan StreetDallasTX USA75201-3411Street or Mailing AddressCi1,State Countmy Zip CodeA copy of the plan of conversion will be furnished on written request without cost by the convertingentity before the conversion or by the converted entity after the conversion to any owner or member ofthe converting or converted entity.Form 6324 Certificate of Formation for the Converted EntityEl The converted entity is a Texas limited liability company. The certificate of formation of theTexas limited liability company is attached to this certificate either as an attachment or exhibit to theplan of conversion, or as an attachment or exhibit to this certificate of conversion if the plan has notbeen attached to the certificate of conversion.Approval of the Plan of ConversionThe plan of conversion has been approved as required by the laws of the jurisdiction of formation andthe governing documents of the converting entity.Effectiveness of Filing (Select either A, B, or C.)A. Z] This document becomes effective when the document is accepted and filed by the secretary ofstate.B. 0l This document becomes effective at a later date, which is not more than ninety (90) days fromthe date of signing. The delayed effective date is:C. El This document takes effect upon the occurrence of the future event or fact, other than thepassage of time. The 90'h day after the date of signing is:The following event or fact will cause the document to take effect in the manner described below:Tax Certificate0] Attached hereto is a certificate from the comptroller of public accounts that all taxes under title2, Tax Code, have been paid by the corporation.In lieu of providing the tax certificate, the limited liability company as the converted entity isliable for the payment of any franchise taxes.ExecutionThe undersigned signs this document subject to the penalties imposed by law for the submission of amaterially false or fraudulent instrument.Date: 04/iE/2013Paul M. Keglevic )Signature and title of authorized person on behalf of theconverting entityFormn 6325 De(awarePAGE 1The First StateI, JEFFREY W. BULLOCK, SECRETARY OF STATE OF THE STATE OFDELAWARE DO HEREBY CERTIFY THAT THE ATTACHED IS A TRUE ANDCORRECT COPY OF THE CERTIFICATE OF CONVERSION OF A TEXASCORPORATION UNDER THE NAME OF "ENERGY FUTURE COMPETITIVEHOLDINGS COMPANY" TO A DELAWARE LIMITED LIABILITY COMPANY,CHANGING ITS NAME FROM "ENERGY FUTURE COMPETITIVE HOLDINGSCOMPANY" TO "ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC",FILED IN THIS OFFICE ON THE FIFTEENTH DAY OF APRIL, A.D. 2013,AT 2:08 O'CLOCK P.M.AUTHENTZ,9TION: 0358620DATE: 04-15-135319121 8100V130437017You may verify this certificate onlineat corp. delaware. gov/authver. shtml State of DelawareSecretary of StateDivision of CorporationsDelivered 02:08 PM 04/15/2013FILED 02:08 PM 04/15/2013SRV 130437017 -5319121 FI=ESTATE OF DELAWARECERTIFICATE OF CONVERSIONFROM A CORPORATION TO ALIMITED LIABILITY COMPANY PURSUANT TOSECTION 18-214 OF THE LIMITED LIABILITY ACT1.) The jurisdiction where the Corporation first formed is Texas2.) The jurisdiction immediately prior to filing this Certificate is Texas3.) The date the corporation first formed is September 17, 19824.) The name of the Corporation immediately prior to filing this Certificate isEnergy Future Competitive Holdings Company5.) The name of the Limited Liability Company as set forth in the Certificate ofFormation is Energy Future Competitive Holdings Company LLCIN WITNESS WHEREOF, the undersigned have executed this Certificate on the15th day of April , A.D. 2013Name:Paul M. KeglevicPrint or Type DelawarePAGE 2qhe First StateI, JEFFREY W. BULLOCK, SECRETARY OF STATE OF THE STATE OFDELAWARE DO HEREBY CERTIFY THAT THE ATTACHED IS A TRUE ANDCORRECT COPY OF CERTIFICATE OF FORMATION OF "ENERGY FUTURECOMPETITIVE HOLDINGS COMPANY LLC" FILED IN THIS OFFICE ON THEFIFTEENTH DAY OF APRIL, A.D. 2013, AT 2:08 O'CLOCK P.M.AUTHEN"TION: 0358620DATE: 04-15-135319121 8100V K9130437017You may verify this certificate onlineat Corp. delaware. gov/authver. shtml State of DelawareSecretary of StateDivision of CorporationsDelivered 02:08 PM 04/15/2013FILED 02:08 PM 04/15/2013SRV 130437017 -5319121 FMLESTATE of DELAWARELIMITED LIABILITY COMPANYCERTIFICATE of FORMATION" First: The name of the limited liability company is Energy FutureCompetitive Holdinqs Company LLC" Second: The address of its registered office in the State of Delaware is1209 Orange Street in theCityof WilmingtonZip Code 19801The name of its Registered agent at such address is The CorporationTrust Company-Third: (Insert any other matters the members determine to include herein.)The duration of the Company shall be perpetual.This Certificate of Formation shall be effective as ofits filing with the Secretary of State of the State ofDelaware.In Witness Whereof, the undersigned have executed this Certificate of Formation this15th day of April ,2013Name:Paul M. KeglevicTyped or Printed LIMITED LIABILITY COMPANY AGREEMENTOFENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCThis Limited Liability Company Agreement (this "Agreement") of Energy FutureCompetitive Holdings Company LLC, a Delaware limited liability company (the "Company"),dated this 15th day of April, 2013, is entered into by EFH2 Corp., a Texas corporation, as thesole member of the Company (the "Member"), for the purpose of governing the affairs of theCompany.WHEREAS, Energy Future Competitive Holdings Company (formerly known as TexasUtilities Electric Company) (the "Corporation") was incorporated as a Texas corporation onSeptember 17, 1982;WHEREAS, the board of directors of the Corporation adopted resolutions approving theconversion of the Corporation to the Company (the "Conversion"), and the adoption of thisAgreement, and recommending the approval of the Conversion and this Agreement to the solestockholder of the Corporation, pursuant to Section 10.101 of the Texas Business OrganizationsCode, as amended from time to time (the "TBOC");WHEREAS, by written consent, the sole stockholder of the Corporation approved theConversion and the adoption of this Agreement pursuant to Section 6.201 of the TBOC;WHEREAS, on the date hereof, the Corporation was converted to the Company pursuantto Section 18-214 of the Delaware Limited Liability Company Act (6 Del. C. § 18-101 et seq.),as amended from time to time (the "Act") and Section 10.101 of the TBOC, by the filing with theSecretary of State of the State of Delaware of a Certificate of Conversion Converting theCorporation to the Company and a Certificate of Formation of the Company (the "Certificate");andWHEREAS, pursuant to this Agreement and the Conversion, the Member, who was thesole stockholder of the Corporation immediately prior to the Conversion, is admitted as amember of the Company owning 100% of the limited liability company interests in theCompany.ARTICLE ILIMITED LIABILITY COMPANYSection 1.1 Name. The name of the Company is Energy Future Competitive HoldingsCompany LLC.Section 1.2 Principal Business Office. The principal business office of the Company shall belocated at 1601 Bryan Street, Dallas, Texas 75201, or such other location as may hereafter bedetermined by the Company.Section 1.3 Registered Office. The address of the registered office of the Company in theState of Delaware is 1209 Orange Street, Wilmington, County of Newcastle, Delaware 19801.

Section 1.4 Registered Agent. The name of the registered agent of the Company for serviceof process on the Company in the State of Delaware is The Corporation Trust Company.Section 1.5 Foreign Qualifications. An officer of the Company shall execute, deliver and fileany certificates (and any amendments and/or restatements thereof) necessary for the Company toqualify to do business in any foreign jurisdiction in which the Company may wish to conductbusiness.Section 1.6 Purpose. The purpose of the Company is to engage in any lawful business oractivity for which a limited liability company may be organized under the Act.Section 1.7 Powers. The Company (i) shall have and exercise all powers necessary,convenient or incidental to accomplish its purpose as set forth in Section 1.6 and (ii) shall haveand exercise all of the powers and rights conferred upon limited liability companies formedpursuant to the Act.Section 1.8 Capital Contributions. The Member is deemed admitted as a member of theCompany upon the Conversion. The money, property and/or services previously contributed bythe Member to the Corporation, the agreed upon value of which are recorded in the books andrecords of the Company, constitute the Member's capital contribution to the Company. Theprovisions of this Agreement, including this Section 1.8, are intended solely to benefit theMember and, to the fullest extent permitted by law, shall not be construed as conferring anybenefit upon any creditor of the Company (and no such creditor of the Company shall be a third-party beneficiary of this Agreement) and the Member shall have no duty or obligation to anycreditor of the Company to make any contribution to the Company or to issue any call for capitalpursuant to this Agreement.Section 1.9 Distributions. Distributions in any form, including cash or other assets, shall bemade to the Member at the times and in the aggregate amounts determined by the Board ofManagers. Notwithstanding any provision to the contrary contained in this Agreement, theCompany shall not be required to make a distribution to any Member on account of its interest inthe Company if such distribution would violate the Act or any other applicable law.Section 1.10 Other Business. The Member and any Affiliate of the Member may engage in orpossess an interest in other business ventures (unconnected with the Company) of every kind anddescription, independently or with others. The Company shall not have any rights in or to suchindependent ventures or the income or profits therefrom by virtue of this Agreement.Section 1.11 Tax Status. Any provision hereof to the contrary notwithstanding, solely forUnited States federal tax purposes, the Member of the Company hereby recognizes that theCompany shall be disregarded as an entity separate from the Member.When used in this Agreement, "Affiliate" means, with respect to any individual,corporation, partnership, joint venture, limited liability company, limited liability partnership,association joint-stock company, trust, unincorporated organization, or other organization,whether or not a legal entity, or any governmental authority ("Person"), any other Person directlyor indirectly Controlling or Controlled by or under direct or indirect common Control with suchPerson, and "Control" means the possession, directly or indirectly, or the power to direct or2 cause the direction, of the management or policies of a Person, whether through the ownership ofvoting securities or general partnership or managing member interests, by contract or otherwise,"Controlling" and "Controlled" have correlative meanings. Without limiting the generality ofthe foregoing, a Person shall be deemed to Control any other Person in which it owns, directly orindirectly, a majority of the ownership interests.ARTICLE IIMANAGEMENTSection 2.1 Board of Managers.(a) Management of the Company shall be vested in a Board of Managers. The Board ofManagers shall have the power to do any and all acts necessary, convenient or incidental to or forthe furtherance of the purposes described herein, including all powers, statutory or otherwise,possessed by managers of a limited liability company under the laws of the State of Delaware.The number of managers shall be determined from time to time by the Member or by theresolution of the Board of Managers. The Member hereby designates Arcilia C. Acosta, Paul M.Keglevic, Scott Lebovitz, Michael MacDougal, Jonathan D. Smidt, and John F. Young as theManagers.(b) Vacancies on the Board of Managers from whatever cause shall be filled by the remainingmanagers or, if there are no remaining managers, by the Member. Managers shall serve untilthey resign or are removed. Managers may be removed with or without cause by the Member.(c) The Board of Managers of the Company may hold meetings, both regular and special, withinor outside the State of Delaware. Regular meetings of the Board of Managers may be heldwithout notice at such times and at such places as shall from time to time be determined by theBoard of Managers. Special meetings of the Board of Managers may be called by the Chairmanof the Board, if any, or by the President on not less than twenty-four (24) hours' notice to eachManager by telephone, facsimile, mail, telegram, or any other means of communication, andspecial meetings shall be called by the President or the Secretary in like manner and with likenotice upon the written request of any one or more of the Managers.(d) At all meetings of the Board of Managers, a majority of the Managers shall constitute aquorum for the transaction of business and, except as otherwise provided in any other provisionof this Agreement, the act of a majority of the Managers present at any meeting at which there isa quorum shall be the act of the Board of Managers. If a quorum shall not be present at anymeeting of the Board of Managers, the Managers present at such meeting may adjourn themeeting from time to time, without notice other than announcement at the meeting, until aquorum shall be present. Any action required or permitted to be taken at any meeting of theBoard of Managers or of any committee thereof may be taken without a meeting if at least amajority of the members of the Board of Managers or such committee, as the case may be,consent thereto in writing, and the writing or writings are filed with the minutes of proceedingsof the Board of Managers or such committee and a copy of such writing or writings is promptlyfurnished to any member of the Board of Managers or such committee, as the case may be, whodid not sign such writing or writings.3 (e) No contract or transaction between the Company (or its subsidiaries) and one or more of itsManagers or officers, or between the Company (or its subsidiaries) and any other company,corporation, partnership, association, or other organization in which one or more of its Managersor officers, are directors, managers, partners or officers (or serve in a similar capacity), or have afinancial interest, shall be void or voidable solely for this reason, or solely because the Manageror officer is present at or participates in the meeting of the Board of Managers or committeewhich authorizes the contract or transaction, or solely because any such Manager's or officer'svotes are counted for such purpose, if:(i) The material facts as to the Manager's or officer's relationship or interest and as to thecontract or transaction are disclosed or are known to the Board of Managers or the committee,and the Board of Managers or committee in good faith authorizes the contract or transaction bythe affirmative votes of a majority of the disinterested Managers, even though the disinterestedManagers be less than a quorum; or(ii) The material facts as to the Manager's or officer's relationship or interest and as to thecontract or transaction are disclosed or are known to the Member, and the contract or transactionis specifically approved in good faith by the Member; or(iii)The contract or transaction is fair as to the Company as of the time it is authorized, approvedor ratified, by the Board of Managers, a committee or the Member.(f) Interested Managers may be counted in determining the presence of a quorum at a meeting ofthe Board of Managers or of a committee which authorizes the contract or transaction.(g) The Managers, or any committee designated by the Board of Managers, may participate in ameeting of the Board of Managers, or of such committee, by means of telephone conference orsimilar communications equipment, and such participation in a meeting shall constitute presencein person at such meeting. If all the participants are participating by telephone conference orsimilar communications equipment, the meeting shall be deemed to be held at the principal placeof business of the Company.(h) The Board of Managers may designate one or more committees, with each committee toconsist of one or more of the Managers of the Company. The Board of Managers may designateone or more Managers as alternate members of any committee, who may replace any absent ordisqualified member at any meeting of such committee. Any such committee, to the extentprovided in the resolution of the Board of Managers, shall have and may exercise all of thepowers and authority of the Board of Managers in the management of the business and affairs ofthe Company. Each committee shall have such name as may be determined from time to time byresolution adopted by the Board of Managers. Each committee shall keep regular minutes of itsmeetings and report the same to the Board of Managers when required by the Board ofManagers.Section 2.2 Officers; Delegation. The Company shall have such officers and employees asare designed within this Agreement or as subsequently designed by the Board of Managers. TheBoard of Managers may, from time to time as they deem advisable, appoint officers and assigntitles (including, without limitation, President, Vice President, Secretary, and Treasurer) to any4 such person. Unless the Board of Managers decides otherwise, if the title is one commonly usedfor officers of a business corporation formed under the Delaware General Corporation Law (the"DGCL"), the assignment of such title shall constitute the delegation to such person of theauthorities and duties that are normally associated with that office. Any delegation pursuant tothis Section 2.2 may be revoked at any time by the Member or Board of Managers.Section 2.3 Limitation of Liability. Except as otherwise expressly provided by the Act, thedebts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise,shall be the debts, obligations and liabilities solely of the Company, and no (a) Member orAffiliate of a Member or their respective members, officers, directors, employees, agents,stockholders or partners, (b) Manager, officer, employee or agent of the Company or (c) Personwho serves on behalf of the Company as a partner, manager, member, officer, director, employeeor agent of any other entity (collectively, with all such Persons that are or have been, at any timefrom and after the date of formation of the Company, among the Persons listed in subsections(a), (b), or (c), the "Covered Persons") shall be obligated personally for any such debt, obligationor liability of the Company solely by reason of being a Covered Person.(a) The failure of the Company to observe any formalities or requirements relating to theexercise of its powers or management of the Company or its affairs under this Agreement or theAct shall not be grounds for imposing personal liability on any Covered Person for liabilities ofthe Company.(b) Such protections from personal liability shall apply to the fullest extent permitted byapplicable law, as the same exists or may hereafter be amended (but, in the case of any suchamendment, only to the extent that such amendment provides greater or broader protections frompersonal liability than such law provided prior to such amendment).(c) To the extent that, at law or in equity, a Covered Person or any otherperson has duties (including fiduciary duties) to the Company or to another Member or Manageror to another person that is a party to or is otherwise bound by this Agreement, those duties arehereby eliminated to the fullest extent allowed under Delaware law and the Act, including§ 18-1101 of the Act (provided that the foregoing does not eliminate duties or liabilities basedupon fraud). All liabilities for breach of duties (including fiduciary duties) of a Covered Personor any other person to the Company or to another Member or Manager or any other person that isa party to or is otherwise bound by this Agreement are hereby eliminated to the fullest extentallowed under Delaware law and the Act, including § 18-1101 of the Act (provided that theforegoing does not eliminate duties or liabilities based upon fraud). The elimination of dutiesand liabilities set forth in this Section 2.3(c) shall be deemed to apply from and after theformation of the Company.ARTICLE IllIMEMBERSSection 3.1 Sole Member. The Member is the sole member of the Company. Themailing address of the Member is 1601 Bryan Street, Dallas, Texas 75201. Additional membersmay be admitted only by written amendment of this Agreement, executed by the Member.5 Section 3.2 Assignments. The Member may assign in whole or in part its limitedliability company interests in the Company. If the Member transfers all of its interests pursuantto this Section 3.2 the transferee shall be admitted to the Company as a member of the Companyupon its execution of an instrument signifying its agreement to be bound by the terms andconditions of this Agreement, which instrument may be a counterpart signature page to thisAgreement. Such admission shall be deemed effective immediately prior to the transfer, and,immediately following such admission, the transferor Member shall cease to be a member of theCompany.Section 3.3 Admission of Additional Members. One or more additional members ofthe Company may be admitted to the Company with the written consent of the Member.Section 3.4 Resignation. A Member may resign from the Company with the writtenconsent of all of the Members. If a Member is permitted to resign pursuant to this Section 3.4,an additional member of the Company shall be admitted to the Company, subject to Section 3.3,upon its execution of an instrument signifying its agreement to be bound by the terms andconditions of this Agreement, which instrument may be a counterpart signature page to thisAgreement. Such admission shall be deemed effective immediately prior to the resignation, and,immediately following such admission, the resigning Member shall cease to be a member of theCompany.ARTICLE IVDISSOLUTIONSection 4.1 Events of Dissolution.(a) The Company shall be dissolved, and its affairs shall be wound up uponthe first to occur of the following: (i) the retirement, resignation or dissolution of the lastremaining Member, or the occurrence of any other event which terminates the continuedmembership of the last remaining Member, in the Company unless the business of the Companyis continued in a manner permitted by the Act or (ii) the entry of a decree of judicial dissolutionunder the Act.(b) Except to the extent set forth in Section 4.1(a) of this Agreement, theoccurrence of any event that terminates the continued membership of a Member in the Companyshall not cause the dissolution of the Company, and, upon the occurrence of such an event, thebusiness of the Company shall continue without dissolution.(c) The bankruptcy (as defimed in the Act) of the Member shall not cause theMember to cease to be a member of the Company and upon the occurrence of such an event, thebusiness of the Company shall continue without dissolution.(d) In the event of dissolution, the Company shall conduct only such activitiesas are necessary to wind up its affairs (including the sale of the assets of the Company in anorderly manner), and the assets of the Company shall be applied in the manner, and in the orderof priority, set forth in the Act.6 ARTICLE VINDEMNIFICATIONSection 5.1 Right to Indemnification. Subject to the limitations and conditions asprovided in this Article V, each Covered Person who was or is made a party or is threatened tobe made a party to or is involved in any threatened, pending or completed action or otherproceeding, whether civil, criminal, administrative, arbitrative or investigative, or any appeal insuch a proceeding or any inquiry or investigation that could lead to such a proceeding (hereaftera "Proceeding"), by reason of any actions or omissions or alleged acts or omissions of suchCovered Person relating to the Company, shall be indemnified by the Company to the fullestextent permitted by applicable law, as the same exists or may hereafter be amended againstjudgments, penalties (including excise and similar taxes and punitive damages), fines,settlements and reasonable expenses (including, without limitation, attorneys' fees) (allcollectively the "Indemnification Amounts") actually incurred by such Covered Person at thetime any such Indemnification Amounts are incurred in connection with such Proceeding.Indemnification under this Article V shall continue as to a Covered Person who has ceased toserve in the capacity which initially entitled such Covered Person to indemnity hereunder.Without limiting the generality of the foregoing, it is expressly acknowledged that theindemnification provided in this Article V could involve indemnification for negligence or undertheories of strict liability.Section 5.2 Limitation on Indemnification. Subject to applicable law, notwithstandingany language in this Article V to the contrary, in no event shall any Person be entitled toindemnification pursuant to this Article V if it is established or admitted either (a) in a finaljudgment of a court of competent jurisdiction or (b) by such Person in any affidavit, swornstatement, plea arrangement or other cooperation with any government or regulatory authoritythat the Person's acts or omissions that would otherwise be subject to indemnification under thisArticle V constituted fraud.Section 5.3 Advancement of Expenses. The right to indemnification conferred in thisArticle V shall include the right to be paid or reimbursed by the Company the reasonableexpenses incurred by a Covered Person of the type entitled to be indemnified above who was, isor is threatened to be made a named defendant or respondent in a Proceeding in advance of thefinal disposition of the Proceeding, without any determination as to such Covered Person'sultimate entitlement to indemnification under, upon receipt of a written affirmation by suchCovered Person of such Covered Person's good faith belief that such Covered Person has met thestandard of conduct necessary for indemnification under applicable law and this Article V and awritten undertaking by or on behalf of such Covered Person to repay all amounts so advanced ifit shall ultimately be determined that such Covered Person is not entitled to be indemnified bythe Company under this Article V or if such indemnification is prohibited by applicable law.Section 5.4 Appearance as a Witness. Notwithstanding any other provision of thisArticle V, the Company may pay or reimburse expenses incurred by a Covered Person inconnection with his or her appearance as a witness or other participation in a Proceeding at atime when such Covered Person is not a named defendant or respondent in the Proceeding.7 Section 5.5 Non-exclusivity of Rights. The indemnification and advancement andpayment of expenses provided by this Article V shall not be deemed exclusive of any other rightsto which a Covered Person indemnified pursuant to this Article V may have or hereafter acquireunder any law (common or statutory), provision of this Agreement, any agreement or otherwise.Section 5.6 Contract Rights. The rights granted pursuant to this Article V shall bedeemed to be contract rights, and no amendment, modification or repeal of this Article V shallhave the effect of limiting or denying any such rights with respect to actions taken orProceedings arising prior to any such amendment, modification or repeal.Section 5.7 Insurance. The Company may purchase and maintain insurance oranother arrangement, at its expense, on behalf of itself, any Covered Person, any Manager,officer, employee or agent of the Company, or any Person who serves on behalf of the Companyas a partner, manager, member, officer, director, employee or agent of any other entity againstany liability, expense or loss, whether or not the Company would have the power to indemnifysuch Person against such liability, expense or loss under the provisions of this Article V.Section 5.8 Savings Clause. If this Article V or any portion of this Agreement shall beinvalidated on any ground by any court of competent jurisdiction, then the Company shallnevertheless indemnify and hold harmless each Covered Person indemnified pursuant to thisArticle V as to costs, charges and expenses (including attorneys' fees), judgments, fines andamounts paid in settlement with respect to any action, suit or proceeding, whether civil, criminal,administrative or investigative, to the fullest extent permitted by any applicable portion of thisArticle V that shall not have been invalidated and to the fullest extent permitted by applicablelaw.Section 5.9 Consultation with Counsel. The right to indemnification conferred in thisArticle V on any Covered Person shall include the right to consult with legal counsel, financialadvisors and accountants selected by such Covered Person, and any act or omission suffered ortaken by such Covered Person on behalf of the Company or in furtherance of the interests of theCompany in good faith in reliance upon and in accordance with the advice of such counsel,financial advisors or accountants will be full justification for any such act or omission, and eachsuch Covered Person will be fully protected in so acting or omitting to act; provided that suchcounsel, financial advisors or accountants were selected with reasonable care.Section 5.10 Other hIdemnities.(a) The Company acknowledges and agrees that the obligation of theCompany under this Agreement to indemnify or advance expenses to any Covered Person for thematters covered thereby shall be the primary source of indemnification and advancement of suchCovered Person in connection therewith and any obligation on the part of any Covered Personunder any Other Indemnification Agreement to indemnify or advance expenses to such CoveredPerson shall be secondary to the Company's obligation and shall be reduced by any amount thatthe Covered Person may collect as indemnification or advancement from the Company. If theCompany fails to indemnify or advance expenses to a Covered Person as required orcontemplated by this Agreement, and any Person makes any payment to such Covered Person inrespect of indemnification or advancement of expenses under any Other Indemnification8 Agreement on account of such Unpaid Indemnity Amounts, such other Person shall besubrogated to the rights of such Covered Person under this Agreement in respect of such UnpaidIndemnity Amounts.(b) The Company, as an indemnifying party from time to time, agrees that, tothe fullest extent permitted by applicable law, its obligation to indemnify Covered Persons underthis Agreement shall include any amounts expended by any other Person under any OtherIndemnification Agreement in respect of indemnification or advancement of expenses to anyCovered Person in connection with any Proceedings to the extent such amounts expended bysuch other Person are on account of any Unpaid Indemnity Amounts."Other Indemnification Agreement" means one or more certificate or articles ofincorporation, by-laws, limited liability company operating agreement, limited partnershipagreement and any other organizational document, and insurance policies maintained by anyMember or Manager or Affiliate thereof providing for, among other things, indemnification ofand advancement of expenses for any Covered Person for, among other things, the same mattersthat are subject to indemnification and advancement of expenses under this Agreement."Unpaid Indemnity Amounts" means any amount that the Company fails to indemnify oradvance to a Covered Person as required by Article V of this Agreement.For purposes of this Article V, the term "Company" shall include any predecessor of theCompany, including without limitation the Corporation, and any constituent entity (includingany constituent of a constituent) absorbed by the Company in a consolidation or merger; the termservice "on behalf of the Company" shall include service as an officer, Manager, Member oremployee of the Company which imposes duties on, or involves, services by, such officer,Manager, Member or employee with respect to an employee benefit plan, its participants orbeneficiaries; any excise taxes assessed on a Person with respect to an employee benefit planshall be deemed to be indemnifiable expenses; and action by a Person with respect to anemployee benefit plan which such Person reasonably believes to be in the interest of theparticipants and beneficiaries of such plan shall be deemed to be action not opposed to the bestinterests of the Company.ARTICLE VIEXCULPATIONSection 6.1 Exculpation. To the fullest extent permitted by applicable law, noCovered Person shall be liable or accountable in damages or otherwise to the Company or to anyMember for any loss or liability arising from any act or omission of such Covered Personrelating to the Company unless, and only to the extent that, such act or omission constitutedfraud.9 ARTICLE VIIGENERAL PROVISIONSSection 7.1 Amendment. This Agreement may not be modified, altered, supplementedor amended except by written instrument signed by the Member.Section 7.2 Applicable Law. This Agreement shall be construed in accordance withand governed by the laws of the State of Delaware.Section 7.3 Benefits of Agreement; No Third-Party Rights. None of the provisions ofthis Agreement shall be for the benefit of or enforceable by any creditor of the Company or byany creditor of any Member. Nothing in this Agreement shall be deemed to create any right inany Person (other than Covered Persons) not a party hereto, and this Agreement shall not beconstrued in any respect to be a contract in whole or in part for the benefit of any third person.Section 7.4 Severabilit' of Provisions. Each provision of this Agreement shall beconsidered severable and if for any reason any provision or provisions herein are determined tobe invalid, unenforceable or illegal under any existing or future law, such invalidity,unenforceability or illegality shall not impair the operation of or affect those portions of thisAgreement which are valid, enforceable and legal.Section 7.5 Entire Agreement. This Agreement constitutes the entire agreement of theMember with respect to subject matter hereof.[Remainder of Page Intentionally Left Blank; Signature Page to Follow]10 IN WITNESS WHEREOF, the undersigned has executed this Agreement as of the datefirst set forth above.EFH2 CORP., as sole memberTitle: Executive Vice President and ChiefFinancial Officer[Signature Page to EFCH LLC Agreement] Table of ContentsUNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K[] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2012-OR-Q) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934Commission File Number 001-34543Energy Future Competitive Holdings Company(Exact name of registrant as specified in its charter)Texas 75-1837355(State or other jurisdiction of (I.R.S. Employerincorporation or organization) Identification No.)1601 Bryan Street, Dallas, TX 75201-3411 (214) 812-4600(Address of principal executive offices)(Zip Code) (Registrant's telephone number, including area code)Securities registered pursuant to Section 12(b) of the Act: NoneSecurities registered pursuant to Section 12(g) of the Act: NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 03 No ElIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d)oftheAct. Yes 0 No 0Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities ExchangeAct of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days. Yes 0 No 0Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every InteractiveData File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months(or for such shorter period that the registrant was required to submit and post such files). Yes 0l No 0Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not containedherein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by referencein Part III of this Form 10-K or any amendment to this Form 10-K. E0Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reportingcompany. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.Large accelerated filer 0 Accelerated filer 01Non-Accelerated filer 0] (Do not check if a smaller reporting company) Smaller reporting company 0Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes 0 No 0lCommon Stock Outstanding as of February 19,2013:2,062,768 Class A shares, without par value and 39,192,594 Class B shares, withoutpar value.Energy Future Competitive Holdings Company meets the conditions set forth in General Instructions (1)(1)(a) and (b) of Form10-K and is therefore filing this report with the reduced disclosure format.DOCUMENTS INCORPORATED BY REFERENCENone Table of ContentsTABLE OF CONTENTSGlossaryPART IItems 1. and 2. BUSINESS AND PROPERTIES 1Item IA. RISK FACTORS 15Item lB. UNRESOLVED STAFF COMMENTS 33Item 3. LEGAL PROCEEDINGS 33Item 4. MINE SAFETY DISCLOSURES 34PART IIItem 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERMATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 35Item 6. SELECTED FINANCIAL DATA 36Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS 38Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 73Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 80Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE 159Item 9A. CONTROLS AND PROCEDURES 159Item 9B. OTHER INFORMATION 162PART IIIItem 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 162Item 11. EXECUTIVE COMPENSATION 162Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENTAND RELATED STOCKHOLDER MATTERS 162Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORINDEPENDENCE 162Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 163PART IVItem 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 164Energy Future Competitive Holdings Company's (EFCH) annual reports on Form 10-K, quarterly reports on Form 10-Q, currentreports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the Energy FutureHoldings Corp. (EFH Corp.) website at http://www.enetgyfutureholdings.com, as soon as reasonably practicable after they havebeen filed with or furnished to the Securities and Exchange Commission. EFCH also from time to time makes available to thepublic, free of charge, on the EFH Corp. website certain financial statements of its wholly-owned subsidiary, Texas CompetitiveElectric Holdings Company LLC. The information on EFH Corp.'s website shall not be deemed a part of, or incorporated byreference into, this annual report on Form 10-K. The representations and warranties contained in any agreement that EFCH hasfiled as an exhibit to this annual report on Form 10-K or that EFCH has or may publicly file in the future may contain representationsand warranties made by and to the parties thereto at specific dates. Such representations and warranties may be subject to exceptionsand qualifications contained in separate disclosure schedules, may represent the parties' risk allocation in the particular transaction,or may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.This annual report on Form 10-K and other Securities and Exchange Commission filings of EFCH and its subsidiaries occasionallymake references to EFH Corp., EFCH (or "we," "our,1" "fus" or "the company"), TCEH, TXU Energy or Luminant when describingactions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidatedwith, or otherwise reflected in, their respective parent company's financial statements for financial reporting purposes. However,these references should not be interpreted to imply that the relevant parent company is actually undertaking the action or has therights or obligations of the relevant subsidiary company or vice versa.i Table of ContentsGLOSSARYWhen the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.2011 Form 10-KAdjusted EBITDAancillary servicesEFCH's Annual Report on Form 10-K for the year ended December 31, 2011Adjusted EBITDA means EBITDA adjusted to exclude noncash items, unusualitems and other adjustments allowable under certain debt arrangements of TCEHand EFH Corp. See the definition of EBITDA below. Adjusted EBITDA andEBITDA are not recognized terms under US GAAP and, thus, are non-GAAPfinancial measures. We are providing TCEH's and EFH Corp.'s Adjusted EBITDAin this Form 10-K (see reconciliations in Exhibits 99(b) and 99(c)) solely becauseof the important role that Adjusted EBITDA plays in respect of certain covenantscontained in the debt arrangements. We do not intend for Adjusted EBITDA (orEBITDA) to be an alternative to net income as a measure of operating performanceor an alternative to cash flows from operating activities as a measure of liquidityor an alternative to any other measure of financial performance presented inaccordance with US GAAP. Additionally, we do not intend for Adjusted EBITDA(or EBITDA) to be used as a measure of free cash flow available for management'sdiscretionary use, as the measure excludes certain cash requirements such as interestpayments, tax payments and other debt service requirements. Because not allcompanies use identical calculations, our presentation of Adjusted EBITDA (andEBITDA) may not be comparable to similarly titled measures of other companies.Refers to services necessary to support the transmission of energy and maintainreliable operations for the entire transmission system. These services includemonitoring and providing for various types of reserve generation to ensure adequateelectricity supply and system reliability.Clean Air Interstate RuleCAIRCFTCUS Commodity Futures Trading Commissioncarbon dioxideCO2CPNPCCSAPRDOEEBITDAEFCHRefers to Comanche Peak Nuclear Power Company LLC, which was formed bysubsidiaries of TCEH (holding an 88% equity interest) and Mitsubishi HeavyIndustries Ltd. (MHI) (holding a 12% equity interest) for the purpose of developingtwo new nuclear generation units and obtaining a combined operating license fromthe NRC for the units.the final Cross-State Air Pollution Rule issued by the EPA in July 2011 and vacatedby the US Court of Appeals for the District of Columbia Circuit in August 2012(see Note 3 to Financial Statements)US Department of Energyearnings (net income) before interest expense, income taxes, depreciation andamortizationEnergy Future Competitive Holdings Company, a direct, wholly-owned subsidiaryof EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending oncontextEnergy Future Holdings Corp., a holding company, and/or its subsidiaries,depending on context, whose major subsidiaries include TCEH and OncorRefers, collectively, to EFH Corp.'s 10.875% Senior Notes due November 1, 2017(EFH Corp. 10.875% Notes) and EFH Corp.'s 11.25%/12.00% Senior ToggleNotesdue November 1, 2017 (EFH Corp. Toggle Notes).Refers, collectively, to EFH Corp.'s 9.75% Senior Secured Notes due October 15,2019 (EFH Corp. 9.75% Notes) and EFH Corp.'s 10.000% Senior Secured Notesdue January 15, 2020 (EFH Corp. 10% Notes).Energy Future Intermediate Holding Company LLC, a direct, wholly-ownedsubsidiary of EFH Corp. and the direct parent of Oncor HoldingsEFIH Finance Inc., a direct, wholly-owned subsidiary of EFIH, formed for the solepurpose of serving as co-issuer with EFIH of certain debt securitiesEFH Corp.EFH Corp. Senior NotesEFH Corp. Senior Secured NotesEFIHEFIH Financeii Table of ContentsEPAERCOTERISAFERCGAAPGHGGWhIRSkWhLIBORLuminantmarket heat rateUS Environmental Protection AgencyElectric Reliability Council of Texas, Inc., the independent system operator andthe regional coordinator of various electricity systems within TexasEmployee Retirement Income Security Act of 1974, as amendedUS Federal Energy Regulatory Commissiongenerally accepted accounting principlesgreenhouse gasgigawatt-hoursUS Internal Revenue Servicekilowatt-hoursLondon Interbank Offered Rate, an interest rate at which banks can borrow funds,in marketable size, from other banks in the London interbank marketsubsidiaries of TCEH engaged in competitive market activities consisting ofelectricity generation and wholesale energy sales and purchases as well ascommodity risk management and trading activities, all largely in TexasHeat rate is a measure of the efficiency of converting a fuel source to electricity.Market heat rate is the implied relationship between wholesale electricity pricesand natural gas prices and is calculated by dividing the wholesale market price ofelectricity, which is based on the price offer of the marginal supplier in ERCOT(generally natural gas plants), by the market price of natural gas. Forward wholesaleelectricity market price quotes in ERCOT are generally limited to two or threeyears; accordingly, forward market heat rates are generally limited to the same timeperiod. Forecasted market heat rates for time periods for which market price quotesare not available are based on fundamental economic factors and forecasts,including electricity supply, demand growth, capital costs associated with newconstruction of generation supply, transmission development and other factors.the Mercury and Air Toxics Standard fimalized by the EPA in December 2011 andpublished in February 2012The transaction referred to in the Agreement and Plan of Merger, dated February25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which wascompleted on October 10, 2007.million British thermal unitsMATSMergerMMBtuMoody'sMWMWhNERCNOxNRCNYMEXOncorMoody's Investors Services, Inc. (a credit rating agency)megawattsmegawatt-hoursNorth American Electric Reliability Corporationnitrogen oxidesUS Nuclear Regulatory Commissionthe New York Mercantile Exchange, a physical commodity futures exchangeOncor Electric Delivery Company LLC, a direct, majority-owned subsidiary ofOncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidatedbankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition BondCompany LLC, depending on context, that is engaged in regulated electricitytransmission and distribution activitiesOncor Electric Delivery Holdings Company LLC, a direct, wholly-ownedsubsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries,depending on contextOncor Holdingsiii Table of ContentsOPEBPUCTPURApurchase accountingREPRRCS&PSECSG&AS02Sponsor GroupTCEHother postretirement employee benefitsPublic Utility Commission of TexasTexas Public Utility Regulatory ActThe purchase method of accounting for a business combination as prescribed byUS GAAP, whereby the cost or "purchase price" of a business combination,including the amount paid for the equity and direct transaction costs are allocatedto identifiable assets and liabilities (including intangible assets) based upon theirfair values. The excess of the purchase price over the fair values of assets andliabilities is recorded as goodwill.retail electric providerRailroad Commission of Texas, which among other things, has oversight of lignitemining activity in TexasStandard & Poor's Ratings Services, a division of the McGraw-Hill CompaniesInc. (a credit rating agency)US Securities and Exchange Commissionselling, general and administrativesulfur dioxideRefers, collectively, to certain investment funds affiliated with Kohlberg KravisRoberts & Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GSCapital Partners, an affiliate of Goldman, Sachs & Co., that have an ownershipinterest in Texas Holdings.Texas Competitive Electric Holdings Company LLC, a direct, wholly-ownedsubsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries,depending on context, that are engaged in electricity generation and wholesale andretail energy markets activities, and whose major subsidiaries include Luminantand TXU EnergyRefers to certain loans from TCEH to EFH Corp. in the form of demand notes tofinance EFH Corp. debt principal and interest payments and, until April 2011, othergeneral corporate purposes of EFH Corp., that are guaranteed on a senior unsecuredbasis by EFCH and EFIH.TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for thesole purpose of serving as co-issuer with TCEH of certain debt securitiesRefers, collectively, to TCEH's and TCEH Finance's 10.25% Senior Notes dueNovember 1, 2015 and 10.25% Senior Notes due November 1, 2015, Series B(collectively, TCEH 10.25% Notes) and TCEH's and TCEH Finance's10.50%/11.25% Senior ToggleNotes due November 1, 2016 (TCEH Toggle Notes).Refers, collectively, to the TCEH Term Loan Facilities, TCEH Revolving CreditFacility, TCEH Letter of Credit Facility and, until it expired on December 31,2012,TCEH Commodity Collateral Posting Facility. See Note 8 to Financial Statementsfor details of these facilities.TCEH's and TCEH Finance's 11.5% Senior Secured Notes due October 1, 2020Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured SecondLien Notes due April 1,2021 and TCEH's and TCEH Finance's 15% Senior SecuredSecond Lien Notes due April 1, 2021, Series B.Texas Commission on Environmental QualityTexas Energy Future Holdings Limited Partnership, a limited partnership controlledby the Sponsor Group, that owns substantially all of the common stock of EFHCorp.Texas Reliability Entity, Inc., an independent organization that develops reliabilitystandards for the ERCOT region and monitors and enforces compliance with NERCstandards and ERCOT protocolsTCEH Demand NotesTCEH FinanceTCEH Senior NotesTCEH Senior Secured FacilitiesTCEH Senior Secured NotesTCEH Senior Secured Second LienNotesTCEQTexas HoldingsTREiv Table of ContentsTXU EnergyTXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEHthat is a REP in competitive areas of ERCOT and is engaged in the retail sale ofelectricity to residential and business customersUnited States of AmericaUsVIEvariable interest entityv Table of ContentsPART I.Items 1. and 2. BUSINESS AND PROPERTIESReferences in this report to "we," "our," "us" and "the company" are to EFCH and/or its subsidiaries, as apparent in thecontext. See "Glossary" on page ii for defined terms.EFCH's Business and StrategyEFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. We conduct our operationsalmost entirely through our wholly-owned subsidiary, TCEH. TCEH is a holding company for subsidiaries engaged in competitiveelectricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodityrisk management and trading activities and retail electricity sales. Key management activities, including commodity riskmanagement and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently,there are no reportable business segments.TCEH owns or leases 15,427 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. TCEH is also one of the largest purchasers of wind-generated electricity in Texas and the US. TCEHprovides competitive electricity and related services to 1.75 million retail electricity customers in Texas.At December 31, 2012, we had approximately 5,200 full-time employees, including approximately 2,050 employees undercollective bargaining agreements.EFCH's MarketWe operate primarily within the ERCOT market. This market represents approximately 85% of the electricity consumptionin Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the IndependentSystem Operator (ISO) of the interconnected transmission grid for those systems. ERCOT's membership consists of approximately300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators,independent power marketers, investor-owned utilities, REPs and consumers.The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over theERCOT market to ensure adequacy and reliability of power supply across Texas' main interconnected transmission grid. TheERCOT ISO is responsible for scheduling power on the grid and maintaining reliable operations of the electricity supply systemin the market. Its responsibilities include centralized dispatch of the power pool and ensuring that electricity production anddelivery are accurately accounted for among the generation resources and wholesale buyers and sellers. The ERCOT ISO alsoserves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.Significant changes in the operations of the wholesale electricity market resulted from the change from a zonal to a nodalmarket implemented by ERCOT in December 2010. The nodal market design resulted in a substantial increase in the number ofsettlement price points for participants and established a new "day-ahead market," operated by ERCOT, in which participants canenter into forward sales and purchases of electricity. The nodal market also established hub trading prices, which represent theaverage of node prices within geographic regions, at which participants can hedge and trade power through bilateral transactionsand established congestion revenue rights, which are financial instruments auctioned by ERCOT that allow participants to hedgeprice differences between settlement points. See Item 7, "Management's Discussion and Analysis of Financial Condition andResults of Operations -Significant Activities and Events and Items Influencing Future Performance -Wholesale Market Design-Nodal Market" for additional discussion of the ERCOT nodal market.I Table of ContentsThe following data is derived from information published by ERCOT:Installed generation capacity in the ERCOT market for the year 2012 totaled approximately 84,500 MW, includingapproximately 2,900 MW mothballed (idled) capacity and more than 10,000 MW of wind and other resources that may not beavailable coincident with system need. Texas has more installed wind generation capacity than any other state in the US. In 2012,ERCOT's hourly demand peaked at 66,548 MW, which was less than the record peak demand of 68,305 MW in 2011. Of ERCOT'stotal installed capacity, approximately 59% is natural gas-fueled generation, approximately 28% is lignite/coal and nuclear-fueledgeneration and approximately 13% is wind and other renewable resources. In November 2010, ERCOT changed its minimumreserve margin planning criterion to 13.75% from 12.5%. In December 2012, ERCOT projected the reserve margin for the summerpeak load period to be 13.2% in 2013, 10.9% in 2014, and 10.5% in 2015. Reserve margin represents the percentage by whichsystem generation capacity exceeds anticipated peak load. See Item 7, "Management's Discussion and Analysis of FinancialCondition and Results of Operations -Key Risks and Challenges -Declining Reserve Margins and Weather Extremes."The ERCOT market has limited interconnections to other markets in the US and Mexico, which currently limits potentialimports into and exports out of the ERCOT market to 1,106 MW of generation capacity (or approximately 2% of peak demand).In addition, wholesale transactions within the ERCOT market are generally not subject to regulation by the FERC.Natural gas-fueled generation is the predominant electricity capacity resource (approximately 59%) in the ERCOT marketand accounted for approximately 45% of the electricity produced in the ERCOT market in 2012. Because of the significant amountof natural gas-fueled capacity and the ability of such facilities to more readily increase or decrease production when compared tonuclear and lignite/coal-fueled generation, marginal demand for electricity is usually met by natural gas-fueled facilities. As aresult, wholesale electricity prices in ERCOT have generally moved with natural gas prices.EFCH's StrategiesOur business focuses operations on key safety, reliability, economic and environmental drivers such as optimizing anddeveloping our generation fleet to safely provide reliable electricity supply in a cost-effective manner and in consideration ofenvironmental impacts, hedging our commodity price and volume exposure and providing high quality service and innovativeenergy products to retail and wholesale customers.Other elements of our strategies include:Increase valuefirom existing business lines. We strive for top tier performance across our operations in terms ofsafety, reliability, cost and customer service. In establishing strategic objectives, we incorporate the following coreoperating principles:* Safety: Placing the safety of communities, customers and employees first;* Environmental Stewardship: Continuing to make strategic and operational improvements that lead to cleaner air,land and water;* Customer Focus: Delivering products and superior service to help customers more effectively manage their useof electricity;* Community Focus: Being an integral part of the communities in which we live, work and serve;* Operational Excellence: Incorporating continuous improvement and financial discipline in all aspects of thebusiness to achieve top-tier results that maximize the value of the company for stakeholders, including operatingworld-class facilities that produce and deliver safe and dependable electricity at affordable prices, and* Performance-Driven Culture: Fostering a strong values- and performance-based culture designed to attract,develop and retain best-in-class talent.2 Table of Contents" Drive and support growth of the ERCOT market We expect to pursue growth opportunities across our existingbusiness lines, including:" Pursuing generation development opportunities to help meet ERCOT's growing electricity needs over thelonger term from a diverse range of energy sources such as natural gas, nuclear and renewable energy." Working with ERCOT and other market participants to develop policies and protocols that provide appropriatepricing signals that encourage the development of new generation to meet growing electricity demand in theERCOT market." Profitably increasing the number of retail customers served throughout the competitive ERCOT market areasby delivering superior value through high quality customer service and innovative energy products, includingleading energy efficiency initiatives and service offerings." Manage exposure to wholesale electricity price volatility. We actively manage our exposure to wholesale electricityprices in ERCOT through contracts for physical delivery of electricity, exchange traded and "over-the-counter"financial contracts, ERCOT "day-ahead market" transactions and bilateral contracts with other wholesale marketparticipants, including other generators and end-use customers. These hedging activities include shorter-termagreements, longer-term electricity sales contracts and forward sales of natural gas." The historical relationship between natural gas prices and wholesale electricity prices in the ERCOT market hasprovided us an opportunity to manage a portion of our exposure to variability of wholesale electricity prices througha natural gas price hedging program. Under this program, TCEH has entered into market transactions involvingnatural gas-related financial instruments, and at December 31, 2012, has effectively sold forward approximately 360million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 42,000 GWh at an assumed8.5 market heat rate) for the period January 1, 2013 through December 31, 2014 at weighted average annual hedgeprices ranging from $6.89 per MMBtu to $7.80 per MMBtu. Taking together forward wholesale and retail electricitysales with the natural gas positions in the hedging program, we have effectively hedged an estimated 96% and 41%of the price exposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2013 and2014, respectively (assuming an 8.5 market heat rate). For additional discussion of the natural gas price hedgingprogram, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations,"specifically sections entitled "Significant Activities and Events and Items Influencing Future Performance -NaturalGas Price Hedging Program and Other Hedging Activities," "Key Risks and Challenges -Natural Gas Price andMarket Heat Rate Exposure" and "Financial Condition -Liquidity and Capital Resources -Liquidity Effects ofCommodity Hedging and Trading Activities."" Strengthen our balance sheet through a liability managementprogram. In 2009, EFH Corp. implemented a liabilitymanagement program focused on improving EFH Corp.'s and its competitive subsidiaries' (including our) balancesheets. Accordingly, we and EFH Corp. expect to opportunistically look for ways to reduce the amount and extendthe maturity of our outstanding debt. Since inception, the program has resulted in our capture of $700 million of debtdiscount, the extension of $2.05 billion of commitments under the TCEH Revolving Credit Facility to 2016 and theextension of $19.6 billion of debt maturities to 2017-2021. For EFH Corp., the program has resulted in the captureof $2.5 billion of debt discount (including the acquisition of $363 million principal amount of TCEH Senior Notesand $19 million principal amount ofborrowings underthe TCEH Senior Secured Facilities that are held as an investmentby EFH Corp. or EFIH) and the extension of approximately $25.7 billion of debt maturities to 2017-2021. Activitiesto date have included debt exchanges, issuances and repurchases as well as amendments to, and extensions under, theCredit Agreement governing the TCEH Senior Secured Facilities. As a result of these and other activities, we expectTCEH will have sufficient liquidity to meets its obligations until October 2014, at which time a total of $3.8 billionof the TCEH Term Loan Facilities matures. TCEH's ability to satisfy this obligation is dependent upon theimplementation of one or more of the actions described below. See Item 7, "Management's Discussion and Analysisof Financial Condition and Results of Operations -Significant Activities and Events and Items Influencing FuturePerformance -Liability Management Program" and Notes land 8 to Financial Statements for additional discussionof these transactions.3 Table of ContentsAs part of the liability management program, EFH Corp. and EFCH and its subsidiaries continue to consider andevaluate possible transactions and initiatives to address their highly leveraged balance sheets and significant cashinterest requirements and may from time to time enter into discussions with their lenders and bondholders with respectto such transactions and initiatives. These transactions and initiatives may include, among others, debt for debtexchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equity exchanges orconversions, including exchanges or conversions of debt of EFCH and TCEH into equity of EFH Corp., EFCH, TCEHand/or any of their subsidiaries. These actions could result in holders of TCEH debt instruments not recovering thefull principal amount of those obligations.In evaluating whether to undertake any liability management transaction, we will take into account liquidityrequirements, prospects for future access to capital, contractual restrictions, the market price of our outstanding debt,the maturity dates of our debt, potential transaction costs and other factors. Any liability management transaction,including any refinancing or extension, may occur on a stand-alone basis or in connection with, or immediatelyfollowing, other liability management transactions.Pursue new environmental initiatives. We are committed to continue to operate in compliance with all environmentallaws, rules and regulations and to reduce our impact on the environment. EFH Corp.'s Sustainable Energy AdvisoryBoard advises us in our pursuit of technology development opportunities that reduce our impact on the environmentwhile balancing the need to help address the energy requirements of Texas. The Sustainable Energy Advisory Boardis comprised of individuals who represent the following interests, among others: the environment, labor unions,customers, economic development in Texas and technology/reliability standards. See "Environmental Regulationsand Related Considerations" below for discussion of actions we are taking to reduce emissions from our generationfacilities and our investments in energy efficiency and related initiatives.SeasonalityOur revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, withrevenues being highest in the summer.Business OrganizationKey TCEH management activities, including commodity price risk management and electricity sourcing for our retail andwholesale customers, are performed on an integrated basis. This integration strategy, the execution of which is discussed belowin describing the activities of our wholesale operations, is a key consideration in our operating segment determination. For purposesof operational accountability and market identity, the operations of TCEH have been grouped into Luminant, which is engagedin electricity generation and wholesale markets activities, and TXU Energy, which is engaged in retail electricity sales activities.These activities are conducted through separate legal entities.Luminant -Luminant's existing electricity generation fleet consists of 14 plants in Texas with total installed nameplategenerating capacity as shown in the table below:Installed Nameplate Number of Number ofFuel Tve Capacity (MW) Plant Sites Units (a)Nuclear 2,300 1 2Lignite/coal (b) 8,017 5 12Natural gas (c) 5,110 8 26Total 15,427 14 40(a) Leased units consist of six natural gas-fueled combustion turbine units totaling 390 MW of capacity. All other units areowned.(b) Includes 1,130 MW representing two units at our Monticello facility for which operations have been suspended until summer2013 due to low wholesale power prices in ERCOT and other market conditions.(c) Includes 1,655 MW representing four units mothballed and not currently available for dispatch. See "Natural Gas-FueledGeneration Operations" below.4 Table of ContentsThe generation units are located primarily on owned land. Nuclear and lignite/coal-fueled units are generally scheduled torun at capacity except for periods of scheduled maintenance activities; however, we reduce production from certain lignite/coal-fueled generation units, referred to as economic backdown, during periods when wholesale electricity market prices are less thanthe unit's variable production costs. The natural gas-fueled generation units supplement the nuclear and lignite/coal-fueledgeneration capacity in meeting consumption in peak demand periods as production from certain of these units, particularlycombustion-turbine units, can be more readily ramped up or down as demand warrants.Nuclear Generation Operations -Luminant operates two nuclear generation units at the Comanche Peak plant site, eachof which is designed for a capacity of 1,150 MW. Comanche Peak's Unit I and Unit 2 went into commercial operation in 1990and 1993, respectively, and are generally operated at full capacity. Refueling (nuclear fuel assembly replacement) outages foreach unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, therefueling cycle results in the refueling of both units during the same year, which last occurred in 2011. While one unit is undergoinga refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance,modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last threeyears the refueling outage period per unit has ranged from 22 to 25 days. The Comanche Peak facility operated at a capacity factorof 98.5%, 95.7% and 100% in 2012, 2011 and 2010, respectively.Luminant has contracts in place for all of its uranium and nuclear fuel conversion, enrichment and fabrication services for2013. For the period of 2014 through 2019, Luminant has contracts in place for the acquisition of approximately 71% of itsuranium requirements and 87% of its nuclear fuel conversion services requirements. In addition, Luminant has contracts in placefor all of its nuclear fuel enrichment services through 2014, as well as all of its nuclear fuel fabrication services through 2018.Luminant does not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion andenrichment services in the foreseeable future.The nuclear industry is developing ways to store used nuclear fuel on site at nuclear generation facilities, primarily throughthe use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation inthe US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site usednuclear fuel storage capability is sufficient for the foreseeable future.The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date of commercial operation.Therefore, assuming that Luminant receives 20-year license extensions, similar to what has been granted by the NRC to severalother commercial generation reactors over the past several years, decommissioning activities would be scheduled to begin in 2050for Comanche Peak Unit I and 2053 for Unit 2 and common facilities. Decommissioning costs will be paid from a decommissioningtrust that, pursuant to Texas law, is intended to be fully funded from Oncor's customers through an ongoing delivery surcharge.(See Note 15 to Financial Statements for discussion of the decommissioning trust fund.)Nuclear insurance provisions are discussed in Note 9 to Financial Statements.Nuclear Generation Development -In 2008, a subsidiary of TCEH filed a combined operating license application withthe NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at its existing ComanchePeak nuclear plant site. In connection with the filing of the application, in 2009, subsidiaries of TCEH and Mitsubishi HeavyIndustries Ltd. (MHI) formed ajoint venture, Comanche Peak Nuclear Power Company (CPNPC), to further the development ofthe two new nuclear generation units using MHI's US-Advanced Pressurized Water Reactor technology. The TCEH subsidiaryowns an 88% interest in CPNPC, and a MHI subsidiary owns a 12% interest.Based on the NRC's license application review schedule, we expect the NRC will complete its review in summer 2014 andthat a license could be issued by year-end 2014. We have filed a loan guarantee application with the DOE for financing theproposed units prior to commencement of construction.Lignite/Coal-Fueled Generation Operations -Luminant's lignite/coal-fueled generation fleet capacity totals 8,017 MWand consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (2 units) and Sandow (2 units)plant sites. Maintenance outages at these units are scheduled during seasonal off-peak demand periods. Over the last three years,the total annual scheduled and unscheduled outages per unit averaged 40 days (last two years include three recently constructedunits discussed immediately below). Luminant's lignite/coal-fueled generation fleet operated at a capacity factor of 70.0% in2012, 83.5% in 2011 and 82.2% in 2010. This performance reflects increased economic backdown of the units as described aboveand the suspension of operations until summer 2013 of two units at Monticello as reflected in the footnotes to the generatingcapacity table above.5 Table of ContentsIn 2009 and 2010, Luminant completed the construction of three lignite-fueled generation units with a total capacity of 2,180MW. The three units consist of one unit at a leased site that is adjacent to an existing lignite-fueled generation unit (Sandow) andtwo units at an owned site (Oak Grove). The Sandow unit and the first Oak Grove unit achieved substantial completion (as definedin the engineering, procurement and construction (EPC) agreements for the respective units) in the fourth quarter 2009. Thesecond Oak Grove unit achieved substantial completion (as defined in the EPC agreement for the unit) in the second quarter 2010.Approximately 71% of the fuel used at Luminant's lignite/coal-fueled generation units in 2012 was supplied from surface-minable lignite reserves dedicated to the Big Brown, Monticello, Martin Lake and Oak Grove plant sites, which are located adjacentto the reserves. Luminant owns or has under lease an estimated 735 million tons of lignite reserves dedicated to these sites, andhas an undivided interest in 200 million tons of lignite reserves that provide fuel for the Sandow facility. Luminant also owns orhas under lease approximately 85 million tons of reserves not currently dedicated to specific generation plants. In 2012, Luminantrecovered approximately 31 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipmentto remove the overburden and recover the lignite.Luminant's lignite mining operations include extensive reclamation activities that return the land to productive uses such aswildlife habitats, commercial timberland and pasture land. In 2012, Luminant reclaimed more than 3,700 acres of land. In addition,Luminant planted 1.7 million trees in 2012, the majority of which were part of the reclamation effort.Luminant meets its fuel requirements at Big Brown, Monticello and Martin Lake by blending lignite with western coal fromthe Powder River Basin in Wyoming. The coal is purchased from multiple suppliers under contracts of various lengths and istransported from the Powder River Basin to Luminant's generation plants by railcar. Based on its current planned usage, Luminantbelieves that it has sufficient lignite reserves for the foreseeable future and has contracted the majority of its anticipated westerncoal requirements through 2013 and all of the related transportation through 2014.See "Environmental Regulations and Related Considerations -Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions"for discussion of potential effects of recent EPA rules on future operations of our generation units.Natural Gas-Fueled Generation Operations -Luminant owns or leases a fleet of 26 natural gas-fueled generation unitstotaling 5,110 MW of capacity, which includes 3,455 MW of currently available capacity and 1,655 MW of capacity representingfour units currently mothballed (idled). The natural gas-fueled units predominantly serve as peaking units that can be ramped upor down to balance electricity supply and demand.In December 2012, Luminant filed a permit application with the TCEQ to build two natural gas combustion turbines totaling420 MW at its existing DeCordova generation facility. While we believe the current market conditions do not provide adequateeconomic returns for the development or construction of new generation, we believe additional generation resources will be neededto support continued electricity demand growth in the ERCOT market. See "Management's Discussion and Analysis of FinancialCondition and Results of Operations -Significant Activities and Events and Items Influencing Future Performance -Recent PUCT/ERCOT Actions" for discussion of actions by the PUCT and ERCOT to encourage development of new generation resources.Wholesale Operations -Luminant's wholesale operations play a pivotal role in our business by optimally dispatching thegeneration fleet, sourcing all of TXU Energy's electricity requirements and managing commodity price risk associated with retailand wholesale electricity sales and generation fuel requirements.Our electricity price exposure is managed across the complementary generation, wholesale and retail operations on a portfoliobasis. Under this approach, Luminant's wholesale operations manage the risks of imbalances between generation supply and salesload, as well as exposures to natural gas price movements and market heat rate changes (variations in the relationships betweennatural gas prices and wholesale electricity prices), through wholesale market activities that include physical purchases and salesand transacting in financial instruments.Luminant's wholesale operations provide TXU Energy and other retail and wholesale customers with electricity-relatedservices to meet their demands and the operating requirements of ERCOT. In consideration of electricity generation resourceavailability and consumer demand levels that can be highly variable, as well as opportunities to meet longer-term objectives oflarger wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-termforward electricity purchase and sales agreements. Luminant is also one of the largest purchasers of wind-generated electricityin Texas and the US with more than 900 MW of existing wind power under contract.Fuel price exposure, primarily relating to Powder River Basin coal, natural gas, uranium and fuel oil, as well as fueltransportation costs, is managed primarily through short- and long-term contracts for physical delivery of fuel as well as financialcontracts.6 Table of ContentsIn its hedging activities, Luminant enters into contracts for the physical delivery of electricity and fuel commodities, exchangetraded and "over-the-counter" financial contracts and bilateral contracts with other wholesale market participants, includinggenerators and end-use customers. Part of these hedging activities are achieved through a natural gas price hedging program,described above under "EFCH's Strategies", designed to reduce exposure to changes in future electricity prices due to changes inthe price of natural gas, principally utilizing natural gas-related financial instruments.The wholesale operations also dispatch Luminant's available generation capacity. These dispatching activities includeeconomic backdown of lignite/coal-fueled units and ramping up and down of natural gas-fueled units as market conditions warrant.Luminant's dispatching activities are performed through a centrally managed real-time operational staff that optimizes operationalactivities across the fleet and interfaces with various wholesale market channels. In addition, the wholesale operations managethe fuel procurement requirements for Luminant's fossil fuel generation facilities.Luminant's wholesale operations include electricity and natural gas trading and third-party energy management activities.Natural gas transactions include direct purchases from natural gas producers, transportation agreements, storage leases andcommercial retail sales. Luminant currently manages approximately 10 billion cubic feet of natural gas storage capacity.Luminant's wholesale operations manage exposure to wholesale commodity and credit-related risk within establishedtransactional risk management policies, limits and controls. These policies, limits and controls have been structured so that theyare practical in application and consistent with stated business objectives. Risk management processes include capturing transactiondata, monitoring transaction types and notional limits, reviewing and managing credit risk, performing and validating valuationsand reporting exposures on a daily basis using risk management information systems designed to support a large transactionalportfolio. A risk management forum meets regularly to ensure that business practices comply with approved transactional limits,commodities, instruments, exchanges and markets. Transactional risks are monitored to ensure limits comply with the establishedrisk policy. Risk management also includes a disciplinary program to address any violations of the risk management policies andperiodic reviews of these policies to ensure they are responsive to changing market and business conditions.TXU Energy -TXU Energy serves 1.75 million residential and commercial retail electricity customers in Texas.Approximately 67% of our reported retail revenues in 2012 represented sales to residential customers. Texas is one of the fastestgrowing states in the nation with a diverse economy and, as a result, has attracted a number of competitors into the retail electricitymarket; consequently, competition is robust. TXU Energy, as an active participant in this competitive market, provides retailelectric service to all areas of the ERCOT market now open to competition, including the Dallas/Fort Worth, Houston, CorpusChristi, and lower Rio Grande Valley areas of Texas. TXU Energy competitively markets its services to add new customers andretain its existing customer base, as well as opportunistically acquire customers from other REPs. There are more than 100 REPscertified to compete within the State of Texas. Based upon data published by the PUCT, at June 30, 2012, approximately 59% ofresidential customers and 68% of small commercial customers in competitive areas of ERCOT are served by REPs not affiliatedwith the pre-competition utility. TXU Energy is a REP affiliated with a pre-competition utility, considering EFH Corp.'s historyprior to the deregulation of the Texas market.TXU Energy's strategy focuses on providing its customers with high quality customer service and creating new productsand services to meet customer needs; accordingly, customer care enhancements are implemented on an ongoing basis to continuallyimprove customer satisfaction. TXU Energy offers a wide range of residential products to meet varying customer needs and hasinvested $100 million in energy efficiency initiatives over a five-year period through 2012 as part of a program to offer customersa broad set of innovative energy products and services.Regulation -Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to thejurisdiction of the NRC with respect to its nuclear generation units. NRC regulations govern the granting of licenses for theconstruction and operation of nuclear-fueled generation facilities and subject such facilities to continuing review and regulation.Luminant also holds a power marketer license from the FERC and, with respect to any wholesale power sales outside the ERCOTmarket, is subject to market behavior and any other competition-related rules and regulations under the Federal Power Act thatare administered by the FERC. In addition, Luminant is subject to the jurisdiction of the RRC's oversight of its lignite miningand reclamation operations.7 Table of ContentsLuminant is also subject to the jurisdiction of the PUCT's oversight of the competitive ERCOT wholesale electricity market.PUCT rules establish robust oversight, certain limits and a framework for wholesale power pricing and market behavior. Luminantis also subject to the requirements of the ERCOT Protocols, including Nodal Protocols and ERCOT reliability standards as adoptedand enforced by the TRE and the NERC, including NERC critical infrastructure protection (CIP) standards. Luminant is alsosubject to the expanding authority of the CFTC as it continues to implement rules and provide oversight vested in the agency bythe Wall Street Reform and Consumer Protection Act of 2010, particularly Title VII, which deals with over-the-counter derivativemarkets.TXU Energy is a licensed REP under the Texas Electric Choice Act and is subject to the jurisdiction of the PUCT withrespect to provision of electricity service in ERCOT. PUCT rules govern the granting of licenses for REPs, including oversightbut not setting of retail prices. TXU Energy is also subject to the requirements of the ERCOT Protocols, including Nodal Protocolsand ERCOT reliability standards as adopted and enforced by the TRE and the NERC, including NERC CIP standards.Environmental Regulations and Related ConsiderationsGlobal Climate ChangeBackground- There is a debate nationally and internationally about global climate change and how greenhouse gas (GHG)emissions, such as CO2, might contribute to global climate change. GHG emissions from the combustion of fossil fuels, primarilyby our lignite/coal-fueled generation units, represent the substantial majority of our total GHG emissions. CO2, methane andnitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions. Weestimate that our generation facilities produced 57 million short tons of CO2 in 2012. Other aspects of our operations result inemissions of GHGs including, among other things, coal piles at our generation plants, refrigerant from our chilling and coolingequipment, fossil fuel combustion in our motor vehicles and electricity usage at our facilities and headquarters. Our financialcondition liquidity or results of operations could be materially affected by the enactment of statutes or regulations that mandate areduction in GHG emissions or that impose financial penalties, costs or taxes on those that produce GHG emissions. See Item IA,"Risk Factors" for additional discussion of risks posed to us regarding global climate change regulation.Global Climate Change Legislation -Over the past few years, several bills have been introduced in the US Congress oradvocated by the Obama Administration that were intended to address climate change using different approaches, including mostprominently a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade). In additionto potential federal legislation to regulate GHG emissions, the US Congress has also considered, and may in the future consider,other legislation that could result in the reduction of GHG emissions, such as the establishment of renewable or clean energyportfolio standards.Through our own evaluation and working in tandem with other companies and industry trade associations, we have supportedthe development of an integrated package of recommendations for the federal government to address the global climate changeissue through federal legislation at various times in the past few years. When GHG legislation involving a cap-and-trade programwas being debated, we expressed a view that any such program should be mandatory, economy-wide, consistent with expectedtechnology development timelines and designed in a way to limit potential harm to the economy or grid reliability and protectconsumers. We have held that any mechanism for allocation of GHG emission allowances should include substantial allocationof allowances to offset the cost of GHG regulation, including the cost to electricity consumers. In addition, we have participatedin a voluntary electric utility industry sector climate change initiative in partnership with the DOE through the Edison ElectricInstitute (EEl). Our strategies are generally consistent with the "EEI Global Climate Change Points of Agreement" published bythe EEl in January 2009 and "The Carbon Principles" announced in February 2008 by three major financial institutions. We havealso created a Sustainable Energy Advisory Board that advises us on technology development opportunities that reduce the effectsof our operations on the environment while balancing the need to address theenergy requirements of Texas. EFH Corp.'s SustainableEnergy Advisory Board is comprised of individuals who represent the following interests, among others: the environment,customers, economic development in Texas and technology/reliability standards. If, despite these efforts, a substantial numberof our customers or others refuse to do business with us because of our GHG emissions, it could have a material effect on ourresults of operations, liquidity and financial condition.8 Table of ContentsFederal Level -The EPA has taken a number of actions regarding GHG emissions. In September 2009, the EPA issued afinal rule requiring the reporting of calendar year GHG emissions from specified large GHG emissions sources in the US. Thisreporting rule applies to our lignite/coal-fueled generation facilities, and we have complied with the requirement since its effectivedate in 2011. In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment andthat emissions from motor vehicles contribute to that endangerment. The EPA's finding required it to begin regulating GHGemissions from motor vehicles and ultimately stationary sources under existing provisions of the federal Clean Air Act. In March2010, the EPA determined that the Clean Air Act's Prevention of Significant Deterioration (PSD) program permit requirementswould apply to newly identified pollutants such as GHGs when a nation-wide rule requiring the control of a pollutant takes effect.Under this determination, PSD permitting requirements became applicable to GHG emissions from planned stationary sources orplanned modifications to stationary sources that had not been issued a PSD permit by January 2, 2011 -the first date that newmotor vehicles were required to meet the new GHG standards. In June 2010, the EPA finalized its so-called "tailoring rule" thatestablished new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources,including our power generation facilities. The EPA's tailoring rule defines the threshold of GHG emissions for determiningapplicability of the Clean Air Act's PSD and Title V permitting programs at levels greater than the emission thresholds containedin the Clean Air Act. In December 2010, in response to the State of Texas's indication that it would not take regulatory action toimplement the EPA's tailoring rule, the EPA adopted a rule to take over the issuance of permits for GHG emissions from the TCEQ.The State of Texas challenged that rule and the GHG permitting rules through litigation and has refused to implement the GHGpermitting rules issued by the EPA. In June 2012, the D.C. Circuit Court upheld all of the EPA's GHG rules and regulations. Anumber of members of the US Congress from both parties have introduced legislation to either block or delay EPA regulation ofGHGs under the Clean Air Act, and legislative activity in this area in the future is possible. In August 2012, various industrygroups and states that challenged the rule filed petitions with the D.C. Circuit Court asking for review by the full D.C. CircuitCourt of the panel's decision. In December 2012, the D.C. Circuit Court denied these requests. Parties will have approximately90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeal will befiled.In March 2012, the EPA released a proposal for a performance standard for greenhouse gas emissions from new electricgeneration units (EGUs). The proposed standard, which is currently limited to new sources, is based on the carbon dioxide emissionrate from a natural gas-fueled combined cycle EGU. None of our existing generation units would be considered a new sourceunder the proposed rule. While we do not believe the proposed rule, as released, affects our existing generation units, we continueto monitor the rule.State and Regional Level -There are currently no Texas state regulations in effect concerning GHGs, and there are noregional initiatives concerning GHGs in which the State of Texas is a participant. We oppose state-by-state regulation of GHGs.In October 2009, Public Citizen Inc. filed a lawsuit against the TCEQ and its commissioners seeking to compel the TCEQ toregulate GHG emissions under the Texas Clean Air Act. The Attorney General of Texas filed special exceptions to the PublicCitizen pleading, which were granted by the court in May 2010. Public Citizen Inc. appealed the court's ruling and the appeal hasbeen fully briefed and submitted to the appellate court for decision on the briefs. We are not a party to this litigation, but we arecontinuing to monitor the case.International Level -In December 2009, leaders of developed and developing countries met in Copenhagen under theUnited Nations Framework Convention on Climate Change (UNFCCC) and issued the Copenhagen Accord. The CopenhagenAccord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissionsof GHGs by 2020 and provides for developed countries to fund GHG emission mitigation projects in developing countries.President Obama participated in the development of, and endorsed, the Copenhagen Accord. In January 2010, the US informedthe United Nations that it would reduce GHG emissions by 17% from 2005 levels by 2020, contingent on Congress passing climatechange legislation. In December 2011, the UNFCCC met in Durban, South Africa and agreed to develop a document with "legalforce" to address climate change by 2015, with reductions effective starting in 2020. In December 2012, the UNFCCC met inDoha, Qatar and 194 countries agreed to an extension of the Kyoto Protocol through 2020. The United States and China are notparticipants in the Kyoto Protocol extension. The impact, if any, of the Durban agreement or the Kyoto Protocol extension onnear-term regulatory or legislative policy cannot yet be determined.We continue to assess the risks posed by possible future legislative or regulatory changes pertaining to GHG emissions.Because some of the proposals described above are in their formative stages, we are unable to predict the potential effects on ourbusiness, results of operations, liquidity or financial condition; however, any such effects could be material. The effect will depend,in large part, on the specific requirements of the legislation or regulation and how much, if any, of the costs are included in wholesaleelectricity prices.9 Table of ContentsEFCH's Voluntary Energy Efficiency, Renewable Energy, and Global Climate Change Efforts We are actively engagedin, considering, or expect to be actively engaged in, business activities that could result in reduced GHG emissions including:Investing in Energy Efficiency and Related Initiatives -Over the last five years, we invested $100 million in energyefficiency and related initiatives, including software- and hardware-based services deployed behind the meter. Theseprograms leverage advanced meter interval data and in-home devices to provide usage and other information andinsights to customers, as well as to control energy-consuming equipment. Examples of these initiatives include: theTXU Energy MyEnergy DashboardsM, an online tool showing residential customers how and when they use electricity;the Brightensm Personal Energy Advisor, an online energy audit tool with personalized tips and projects for savingelectricity; the Brightensm Online Energy Store that provides customers the opportunity to purchase hard-to-find, cost-effective energy-saving products; the BrightensM iThermostat, a web-enabled programmable thermostat with a loadcontrol feature for cycling air conditioners during times of peak energy demand; TXU Energy PowerSmartsM and TXUEnergy Free NightssM, time-based electricity rates, and TXU Energy FlexPowersM, prepaid electricity plans, that workin conjunction with advanced metering infrastructure; in-home display devices that enable residential customers tomonitor whole-house energy usage and cost in real-time and project month-end bill amounts; rate plans that includeelectricity from renewable resources; the BrightensM Energy Efficiency Assistance Program that delivered productsand services, as well as grants through social service agencies, to save energy at participating low income customerhomes and apartment complexes; a program to refer customers to energy efficiency contractors, and the provision ofrebates to business customers for purchasing new energy efficient equipment for their facilities through the BrightensMGreenback Energy Efficiency Rebate Program; the TXU Energy Electricity Usage Report, a weekly email that containscharts and graphs that give customers insight to better control their electricity usage and bills; programs promotingdistributed renewable generation to reduce peak summer demand on the grid; and mobile access through smart phones,tablets and other mobile devices with "alert" features that help inform residential customers about recent electricityconsumption thresholds." Purchasing Electricityfr'om Renewable Sources -We expect to remain a leader in the ERCOT market in providingelectricity from renewable sources by purchasing wind power. Our total wind power portfolio is currently more than900 MW. We also purchase additional renewable energy credits (RECs) to support discretionary sales of renewablepower to our customers;" Promoting the Use ofSolar Power-- TXU Energy provides qualified customers, through its TXU Energy SolarLeasesMprogram, the ability to finance the addition of solar panels to their homes. TXU Energy also purchases surplus renewabledistributed generation from qualified customers. In addition, TXU Energy's Solar Academy works with Texas schooldistricts to teach and demonstrate the benefits of solar power;" Investing in Technology -We continue to evaluate the development and commercialization of cleaner power facilitytechnologies, including technologies that support sequestration and/or reduction of CO,; incremental renewable sourcesof electricity, including wind and solar power; energy storage, including advanced battery and compressed air storage,as well as related technologies that seek to lower emissions intensity. Additionally, we continue to explore and participatein opportunities to accelerate the adoption of electric cars and plug-in hybrid electric vehicles that have the potentialto reduce overall GHG emissions and are furthering the advance of such vehicles by supporting, and helping developinfrastructure for, networks of charging stations for electric vehicles;" Evaluating the Development of a New Nuclear Generation Facility -As discussed under "Nuclear GenerationDevelopment" above, we have filed applications with the NRC for combined construction and operating licenses fortwo new 1,700 MW nuclear power plants (3,400 MW total) of new nuclear generation capacity (the lowest GHGemission source of baseload generation currently available) at our Comanche Peak nuclear generation facility. Inaddition, we have (i) filed a loan guarantee application with the DOE for financing of the proposed units and (ii) formeda joint venture with Mitsubishi Heavy Industries Ltd. (MHI) to further develop the units using MHI's US-AdvancedPressurized Water Reactor technology, andOffsetting GHG Emissions by Planting Trees -We are engaged in a number of tree planting programs that offsetGHG emissions, resulting in the planting of over 1.7 million trees in 2012. The majority of these trees were plantedas part of our mining reclamation efforts but also include TXU Energy's Urban Tree Farm program, which has plantedmore than 180,000 trees since its inception in 2002.10 Table of ContentsSulfur Dioxide, Nitrogen Oxide and Mercury Air EmissionsCross-State Air Pollution Rule -In 2005, the EPA issued a final rule (the Clean Air Interstate Rule or CAIR) intended toimplement the provisions of the Clean Air Act Section 1 I0(a)(2)(D)(i)(I) (CAA Section 110) requiring states to reduce emissionsof sulfur dioxide (SO2) and nitrogen oxides (NOx) that significantly contribute to other states failing to attain ormaintain compliancewith the EPA's National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone. In 2008, the US Courtof Appeals for the District of Columbia Circuit (D.C. Circuit Court) invalidated CAIR, but allowed the rule to continue until theEPA issued a final replacement rule.In July 2011, the EPA issued the final replacement rule for CAIR (as finally issued, the Cross-State Air Pollution Rule(CSAPR)). The CSAPR included Texas in its annual SO2 and NOx emissions reduction programs, as well as the seasonal NOxemissions reduction program. These programs would have required significant additional reductions of SO2 and NOx emissionsfrom fossil-fueled generation units in covered states (including Texas) and instituted a limited "cap and trade" system as anadditional compliance tool to achieve reductions the EPA contends are necessary to implement CAA Section 110. In September2011, we filed a petition for review in the D.C. Circuit Court challenging the CSAPR as it applies to Texas.In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR,including emissions budgets for the State of Texas. In June 2012, the EPA finalized the proposed rule (Second Revised Rule). Intotal, the emissions budgets established by the Final Revisions along with the Second Revised Rule would require our fossil-fueledgeneration units to reduce (i) their annual SO2 and NOx emissions by approximately 120,600 tons (56 percent) and 9,000 tons (22percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NOx emissions by approximately 3,300 tons (18percent) compared to 2010 levels. We could comply with these emissions limits either through physical reductions or through thepurchase of emissions credits from third parties, but the volume of SO2 credits that may be purchased from sources outside ofTexas would be subject to limitations starting in 2014. In April 2012, we filed in the D.C. Circuit Court a petition for review ofthe Final Revisions on the ground, among others, that the rules do not include all of the budget corrections we requested from theEPA. The parties to these proceedings have agreed that the case should be held in abeyance pending the conclusion of the CSAPRrehearing proceeding discussed immediately below. Since the CSAPR rehearing proceeding has concluded, the parties will conferregarding how the case should proceed, if at all.In August 2012, a three judge panel of the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for furtherproceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule do not impose any immediate requirementson us, the State of Texas, or other affected parties. The D.C. Circuit Court's order stated that the EPA was expected to continueadministering the CAIR pending the EPA's further consideration of the rule. In October 2012, the EPA and certain other partiesthat supported the CSAPR filed petitions with the D.C. Circuit Court seeking review by the full court of the panel's decision tovacate and remand the CSAPR. In January 2013, the D.C. Circuit Court denied these requests for rehearing, concluding theCSAPR rehearing proceeding. The EPA and the other parties to the proceedings have approximately 90 days to appeal the D.C.Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeals will be filed.Given the uncertainty regarding the CSAPR's (including the Final Revisions, the Second Revised Rule or any replacementrules) requirements and the timing of its implementation, we are unable to predict its effects on our results of operations, liquidityor financial condition. See Note 3 to Financial Statements for discussion of accounting actions taken as a result of the CSAPR.Mercury andAir Toxics Standard- In December 2011, the EPA finalized a rule called the Mercury and Air Toxics Standard(MATS). MATS regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases. Anyadditional control equipment retrofits on our lignite/coal-fueled generation units required to comply with MATS as finalized wouldneed to be installed within three to four years from the April 2012 effective date of the rule. In April 2012, we filed a petition forreview of MATS in the D.C. Circuit Court. Certain states and industry participants have also filed petitions for review in the D.C.Circuit Court. We cannot predict the timing or outcome of these petitions. In November 2012, the EPA proposed revised standardsfor new coal-fired generation units and other minor changes to MATS, including changes to the work practice standards affectingall units. We cannot predict the outcome of the final rule.11 Table of ContentsRegional Haze -S02 and NOx reductions required under the proposed regional haze/visibility rule (or so-called BARTrule) only apply to units built between 1962 and 1977. The reductions are required either on a unit-by-unit basis or by stateparticipation in an EPA-approved regional trading program such as the CAIR. In February 2009, the TCEQ submitted a StateImplementation Plan (SIP) concerning regional haze to the EPA, which we believe would not have a material impact on ourgeneration facilities. In December 2011, the EPA proposed a limited disapproval of the SIP due to its reliance on the CAIR anda Federal Implementation Plan for Texas providing that the inclusion in the CSAPR programs meets the regional haze requirementsfor SO2 and NOx reductions. In June 2012, the EPA finalized the limited disapproval of the Texas regional haze SIP, but did notfinalize a Federal Implementation Plan for Texas. We cannot predict whether or when the EPAwill finalize a Federal ImplementationPlan for Texas regarding regional haze or its impact on our results of operations, liquidity or financial condition. In August 2012,we filed a petition for review in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the EPA's limiteddisapproval of the Texas regional haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court'sdecision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and otherstates and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of Federal ImplementationPlans regarding regional haze. The parties to these cases have mutually agreed that the cases should be held in abeyance pendingcompletion of the CSAPR rehearing proceeding described above. Because the CSAPR rehearing proceeding is completed, weanticipate that these cases will no longer be held in abeyance. We cannot predict when or how the Fifth Circuit Court or the D.C.Circuit Court will rule on these petitions.State Implementation Plan -The Clean Air Act requires each state to monitor air quality for compliance with federal healthstandards. The EPA is required to periodically review, and if appropriate, revise all national ambient air quality standards. Thestandards for ozone are not being achieved in several areas of Texas. The TCEQ adopted SIP rules in May 2007 to deal with eight-hour ozone standards, which required NOx emission reductions from certain of our peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposedto further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation fromozone-related damage; however, in September 2011, the White House directed the EPA to withdraw this reconsideration. Sincethe EPA has not designated nonattainment areas and projects that SIP rules to address attainment of the 2008 standards will notbe required until June 2015, we cannot yet predict the impact of this action on our generation facilities. In January 2010, the EPAadded a new one-hour NOx National Ambient Air Quality standard that may require actions within Texas to reduce emissions.The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required noearlier than January 2021. In June 2010, the EPA adopted a new one-hour SO2 national ambient air quality standard that mayrequire action within Texas to reduce SO2 emissions. Based on current monitoring, Texas has recommended to the EPA that noarea in Texas is in nonattainment with this one-hour SO2 standard. The EPA had indicated that it will not make final area designationsuntil June 2013. We cannot predict the impact of the new standards on our business, results of operations or financial conditionuntil the TCEQ adopts (if required) an implementation plan with respect to the standards.In September 2010, the EPA disapproved a portion of the State Implementation Plan pursuant to which the TCEQ implementsits program to achieve the requirements of the Clean Air Act. The EPA disapproved the Texas standard permit for pollution controlprojects. We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. Wechallenged the EPA's disapproval by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ's adoption of the standardpermit conditions for pollution control projects was consistent with the Clean Air Act. In March 2012, the Fifth Circuit Courtvacated the EPA's disapproval of the Texas standard permit for pollution control projects and remanded the matter to the EPA forreconsideration. We cannot predict the timing or outcome of the EPA's reconsideration.In November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacingthat exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generationfacility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicabilityof the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and receivedthe generation facility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the Fifth CircuitCourt arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issuedis consistent with the Clean Air Act. In July 2012, the Fifth Circuit Court denied our challenge and ruled that the EPA's actionswere in accordance with the Clean Air Act. In October 2012, the Fifth Circuit Court panel withdrew its original opinion and issueda new expanded opinion that again upheld the EPA's disapproval. In November 2012, we filed a petition with the Fifth CircuitCourt asking for review by the full Fifth Circuit Court of the panel's new expanded opinion. Other parties to the proceedings alsofiled a petition with the Fifth Circuit Court asking the panel to reconsider its decision. We cannot predict the timing or outcomeof this matter.12 Table of ContentsAcidRain Program -The EPA has promulgated Acid Rain Program rules that require fossil-fueled plants to have sufficientSO2 emission allowances and meet certain NOx emission standards. We believe our generation plants meet these SO2 allowancerequirements and NOx emission rates.Installation of Substantial Emissions Control Equipment -Each of our lignite/coal-fueled generation facilities is currentlyequipped with substantial emissions control equipment. All of our lignite/coal-fueled generation facilities are equipped withactivated carbon injection systems to reduce mercury emissions. Flue gas desulfurization systems designed primarily to reduceSO2 emissions are installed at Oak Grove Units 1 and 2, Sandow Units 4 and 5, Martin Lake Units 1, 2, and 3, and MonticelloUnit 3. Selective catalytic reduction systems designed to reduce NOx emissions are installed at Oak Grove Units I and 2 andSandow Unit 4. Selective non-catalytic reduction systems designed to reduce NOx emissions are installed at Sandow Unit 5,Monticello Units 1, 2, and 3, and Big Brown Units I and 2. Fabric filter systems designed primarily to reduce particulate matteremissions are installed at Oak Grove Units I and 2, Sandow Unit 5, Monticello Units 1 and 2, and Big Brown Units I and 2.Electrostatic precipitator systems designed primarily to reduce particulate matter emissions are installed at Sandow Unit 4, MartinLake Units 1, 2, and 3, Monticello Units 1,2, and 3, and Big Brown Units I and 2. Sandow Unit 5 uses a fluidized bed combustionprocess that facilitates control of NOx and SO2.Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitatorsystems also assist in reducing mercury and other emissions.We believe that we hold all required emissions permits for facilities in operation. If the TCEQ adopts implementation plansthat require us to install additional emissions controls, or if the EPA adopts more stringent requirements through any of the numberof potential rulemaking activities in which it is or may be engaged, we could incur material capital expenditures, higher operatingcosts and potential production curtailments, resulting in material effects on our results of operations, liquidity and financialcondition.WaterThe TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. We believeour facilities are presently in material compliance with applicable state and federal requirements relating to discharge of pollutantsinto water. We believe we hold all required waste water discharge permits from the TCEQ for facilities in operation and haveapplied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirementsnecessary to obtain any required permits or renewals.In 2010, we obtained a renewed and amended permit for discharge of waste water from our Oak Grove generation facility.Opponents to that permit renewal have initiated a challenge in Travis County, Texas District Court. We and the State of Texasdefended the issuance of the permit. In October 2012, the Texas District Court ruled in favor of the issuance of the permit.Opponents have filed an appeal directed at the State of Texas. If the permit is ultimately rejected by the courts, and we are requiredto undertake additional permitting activity and install additional temperature-control equipment, we could incur material capitalexpenditures, which could result in material effects on our results of operations, liquidity and financial condition. (See Note 9 toFinancial Statements.)Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQand the EPA. We believe we possess all necessary permits from the TCEQ for these activities at our current facilities. CleanWater Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were publishedby the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actionsthat might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuitbrought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it wassuspending the regulations pending further rulemaking. The US Supreme Court issued a decision in April 2009 reversing thefederal court's decision, in part, and finding that the EPA permissibly used cost-benefit analysis in the Section 316(b) regulations.Pursuant to a settlement agreement, the EPA issued for comment proposed new Section 316(b) regulations in March 2011 andmust adopt the final regulations by June 2013. In the absence of regulations, the EPA has instructed the states implementing theSection 316(b) program, including Texas, to use their best professional judgment in reviewing applications and issuing permitsunder Section 316(b). Although the proposed rule does not mandate a certain control technology, it does require site-specificassessments of technology feasibility on a case-by-case basis at the state level. Compliance with this rule would be requiredbeginning eight years following promulgation. We cannot predict the substance of the final regulations or the impact they mayhave on our results of operations, liquidity or financial condition.13 Table of ContentsRadioactive WasteWe currently, and expect to continue to, ship low-level waste material to a disposal facility outside of Texas. Under thefederal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its ownor jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The Stateof Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congressand signed by the President in 1998, and the State of Texas has enacted legislation allowing a private entity to be licensed to acceptlow-level radioactive waste for disposal. The first disposal facility in Texas for such purposes began operations in 2012, and weexpect to ship some forms of waste material to the facility in 2013. Should existing off-site disposal become unavailable, the low-level waste material can be stored on-site. (See discussion under "Luminant -Nuclear Generation Operations" above.)The nuclear industry is developing ways to store used nuclear fuel on site at nuclear generation facilities, primarily throughthe use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation inthe US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site usednuclear fuel storage capability is sufficient for the foreseeable future.Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled GenerationTreatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas SolidWaste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and theToxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 andthe Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable toour facilities. We believe we are in material compliance with all applicable solid waste rules and regulations. In addition, wehave registered solid waste disposal sites and have obtained or applied for permits required by such regulations.In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured, releasing a significantquantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of our impoundments, whichare significantly smaller than the TVA's and are inspected on a regular basis. We routinely sample groundwater monitoring wellsto ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, in May 2010, the EPAreleased a proposed rule that considers regulating coal combustion residuals as either a hazardous waste or a non-hazardous waste.We are unable to predict the requirements of a final rule; however, the potential cost of compliance could be material.The EPA issued a notice in December 2009 that it had identified several industries, including the electric power industry,which should be subject to financial responsibility requirements under the Comprehensive Environmental Response, Compensationand Liability Act (CERCLA) consistent with the risk associated with their production, transportation, treatment, storage or disposalof hazardous substances. The EPA indicated in its notice that it would develop regulations that define the scope of those financialresponsibility requirements. We do not know the scope of these requirements, nor are we able to estimate the potential cost, whichcould be material, of complying with any such new requirements.Environmental Capital ExpendituresCapital expenditures for our environmental projects totaled $270 million in 2012 and are expected to total approximately$100 million in 2013 for environmental control equipment to comply with regulatory requirements. Based on analysis and testingof options to comply with the MATS rule, as well as estimates related to other EPA regulations, including expenditures previouslyincurred related to the CSAPR, between 2011 and the end of the decade we estimate that we will incur more than $1 billion incapital expenditures for environmental control equipment, though the ultimate total will depend on the evolution of pending orfuture regulatory requirements. Based on regulations currently in effect, we estimate that we will incur approximately $500 millionof environmental capital expenditures between 2013 and 2017, including amounts required to maintain installed environmentalcontrol equipment. Our current plan includes the ongoing use of lignite coal as part of the fuel mix at all of our coal facilities, invarying proportions that reflect the economically available fuel supply as well as the configuration of environmental controlequipment for each unit.14 Table of ContentsItem 1A. RISK FACTORSSome important factors, in addition to others specifically addressed in Item 7, "Management's Discussion and Analysis ofFinancial Condition and Results of Operations," that could have a material impact on our operations, liquidity, financial resultsand financial condition, or could cause our actual results or outcomes to differ materially from any projected outcome containedin any forward-looking statement in this report, include:Risks Related to Substantial IndebtednessOur substantial leverage could adversely affect our ability to fund our operations, limit our ability to react to changes in theeconomy or our industry (including changes to environmental regulations), limit our ability to raise additional capital andadversely impact our ability to meet obligations under our various debt agreements.We are highly leveraged. At December 31, 2012, our consolidated principal amount of debt (short-term borrowings andlong-term debt, including amounts due currently and amounts held by affiliates) totaled $32.7 billion (see Note 8 to FinancialStatements). Our substantial indebtedness has, or could have, important consequences, including:" making it more difficult for us to make payments on our debt, including our maturities of $3.8 billion of the TCEH TermLoan Facilities in October 2014;* requiring a substantial portion of our cash flow to be dedicated to the payment of principal and interest on our debt,thereby limiting our liquidity and reducing our ability to use our cash flow to fund operations, capital expenditures,future business opportunities and execution of our growth strategy;" increasing our vulnerability to adverse economic, industry or competitive conditions or developments, including changesto environmental regulations;* limiting our ability to make strategic acquisitions or causing us to make non-strategic divestitures;* limiting our ability to develop new (or maintain our current) generation facilities;* limiting our ability to obtain additional financing for working capital (including collateral posting), capital expenditures,project development, debt service requirements, acquisitions and general corporate or other purposes, or to refinanceexisting debt, and increasing the costs of any such financing or refinancing;* limiting our ability to find counterparties for our hedging and asset management activities in the wholesale commoditymarket, and* limiting our ability to adjust to changing market and industry conditions (including changes to environmental regulations)and placing us at a disadvantage compared to competitors who are less leveraged and who, therefore, may be able tooperate at a lower overall cost (including debt service) and take advantage of opportunities that we cannot.We may not be able to repay or refinance our debt as or before it becomes due, or obtain additional financing, particularly ifwholesale electricity prices in ERCOTdo not significantly increase and/or if environmental regulations are adopted that resultin significant capital requirements, and the costs of any refinancing may be significant.We may not be able to repay or refinance our debt as or before it becomes due, including our maturities of $3.8 billion ofthe TCEH Term Loan Facilities in October 2014, or we may only be able to refinance such amounts on terms that will increaseour cost of borrowing or on terms that may be more onerous. Our ability to successfully implement any future refinancing of ourdebt will depend on, among other things, our financial condition and operating performance, which is subject to prevailing economicand competitive conditions, and to certain financial, business and other factors beyond our control, including, without limitation,wholesale electricity prices in ERCOT (which are primarily driven by the price of natural gas and ERCOT market heat rates),environmental regulations and general conditions in the credit markets. Refinancing may also be difficult because of generaleconomic conditions, including the slow economic recovery, the possibility of rising interest rates and uncertainty with respect toUS fiscal policy. Because our credit ratings are significantly below investment grade, we may be more heavily exposed to theserefinancing risks than other borrowers. In addition, the timing of additional financings may require us to pursue such financingsat inopportune times, and we may be able to incur new financing only at significant cost.15 Table of ContentsAt December 31, 2012, a substantial amount of our long-term debt matures in the next few years, including approximately$80 million, $3.9 billion and $3.7 billion principal amount of debt maturing in 2013, 2014 and 2015, respectively. A substantialamount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities. In April 2011 and January 2013, wesecured extensions of a significant portion of the commitments and loans under the TCEH Senior Secured Facilities. However,even after taking these extensions into account, we still have $3.8 billion principal amount of loans under the TCEH Term LoanFacilities that were not extended and will mature in October 2014. In addition, notwithstanding the extensions, the commitmentsand loans could mature earlier as described in the next paragraph. Moreover, while we were able to extend a significant portionof the commitments and loans under the TCEH Senior Secured Facilities, the extensions were only for three years and the cost ofthese extensions was significant. As a result, we have a substantial principal amount of debt that matures in 2016 (approximately$1.9 billion) and 2017 (approximately $16.1 billion, including $947 million under the TCEH Letter of Credit Facility that is heldin restricted cash).The extended commitments and loans under the TCEH Senior Secured Facilities include a "springing maturity" provisionpursuant to which in the event that (a) more than $500 million aggregate principal amount of the TCEH 10.25% Notes or morethan $150 million aggregate principal amount of the TCEH Toggle Notes (in each case, other than notes held by EFH Corp. or itscontrolled affiliates at March 31, 2011 to the extent held at the determination date), as applicable, remain outstanding as of 91days prior to the maturity date of the applicable notes and (b) TCEH's consolidated total debt to consolidated EBITDA ratio (asdefined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at such applicable determination date, then the maturitydate of the extended commitments and loans will automatically change to 90 days prior to the maturity date of the applicablenotes. As a result of this "springing maturity" provision, we may lose the benefit of the extension of the commitments and loansunder the TCEH Senior Secured Facilities if we are unable to refinance the requisite portion of the TCEH 10.25% Notes and TCEHToggle Notes (collectively, the TCEH Senior Notes) by the applicable deadline. The TCEH 10.25% Notes mature on November1,2015, and the TCEH Toggle Notes mature on November 1, 2016. If holders of the TCEH Senior Notes are unwilling to extendthe maturities of their notes, then, to avoid the "springing maturity" of the extended commitments and loans, we may be requiredto repay a substantial portion of the TCEH Senior Notes at prices above market or at par. There is no assurance that we will beable to make such payments, whether through cash on hand or additional financings. At December 31, 2012, $3.125 billion and$1.749 billion aggregate principal amount of the TCEH 10.25% Notes and the TCEH Toggle Notes, respectively, were outstanding,excluding amounts held by affiliates.Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas. Accordingly, thecontribution to earnings and the value of our nuclear and lignite/coal-fueled generation assets are dependent in significant partupon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008 (from $11.12 perMMBtu in mid-2008 to $4.03 per MMBtu at December 31, 2012 for calendar year 2014). In recent years, natural gas supply hasoutpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weakness associated withthe economic downturn. Many industry experts expect this supply/demand imbalance to continue for a number of years, therebydepressing natural gas prices for a long-term period. These market conditions are challenging to our liquidity and the long-termprofitability of our businesses. Specifically, low natural gas prices and their effect in ERCOT on wholesale electricity prices couldhave a material impact on TCEH's overall profitability for periods in which TCEH does not have significant hedge positions. AtDecember 31,2012, we have hedged approximately 96% and 41% of our wholesale natural gas price exposure related to expectedgeneration output for 2013 and 2014, respectively, based on currently governing CAIR regulation, and we do not have any significantamounts of hedges in place for periods after 2014. Consequently, a continuation, or further decline, of current forward naturalgas prices could result in further declines in the values of TCEH's nuclear and lignite/coal-fueled generation assets and limit orhinder TCEH's ability to hedge its wholesale electricity revenues at sufficient price levels to support its significant interest paymentsand debt maturities, which could adversely impact its ability to obtain additional liquidity and refinance and/or extend the maturitiesof its outstanding debt.Aspects of our current financial condition may also be challenging to our efforts to obtain additional financing (or refinanceor extend our existing financing) in the future. For example, our liabilities exceed our assets as shown on our balance sheetprepared in accordance with US GAAP at December 31, 2012. Our reported assets include $4.952 billion of goodwill atDecember 31, 2012. In 2012 and 2010, we recorded $1.2 billion and $4.1 billion, respectively, noncash goodwill impairmentcharges reflecting the estimated effect of lower wholesale electricity prices on the enterprise value of TCEH, driven by the sustaineddecline in forward natural gas prices, as indicated by our cash flow projections and declines in market values of securities ofcomparable companies. The enterprise value of TCEH will continue to depend on, among other things, wholesale electricity pricesin the ERCOT market. Further, third party analyses of TCEH's business performed in connection with goodwill impairment testingin accordance with US GAAP, which have indicated that the principal amount of TCEH's outstanding debt exceeds its enterprisevalue, may make it more difficult for us to successfully access the capital markets to obtain liquidity and/or implement anyrefinancing or extensions of our debt or obtain additional financing. Our ability to obtain future financing is also limited by thevalue of our unencumbered assets. Substantially all of our assets are encumbered (in most cases by both first and second liens),and we have no material assets that could be used as additional collateral in future financing transactions.16 Table of ContentsEFCH's (or any applicable subsidiary's) credit ratings and any actual or perceived changes in their creditworthiness couldnegatively affect EFCH's (or the subsidiary's) ability to access capital and could require EFCH or its subsidiaries to postcollateral or repay certain indebtedness.EFCH's (or any applicable subsidiary's) credit ratings could be lowered, suspended or withdrawn entirely at any time by therating agencies, if in each rating agency's judgment, circumstances warrant. Downgrades in EFCH's or any of its subsidiaries'long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources todecrease and could trigger liquidity demands pursuant to the terms of new commodity contracts, leases or other agreements. Futuretransactions by EFCH or any of its subsidiaries, including the issuance of additional debt or the consummation of additionaltransactions under our liability management program, could result in temporary or permanent downgrades of EFCH's or itssubsidiaries' credit ratings.Most of EFCH's large customers, suppliers and counterparties require an expected level of creditworthiness in order for themto enter into transactions. Because of EFCH's (and its applicable subsidiary's) existing credit ratings, the cost to operate itsbusinesses is likely higher because counterparties in some instances could require the posting of collateral in the form of cash orcash-related instruments. If our creditworthiness or perceptions of our creditworthiness deteriorate further, counterparties coulddecline to do business with EFCH (or its applicable subsidiary).Despite our current high debt level, we may still be able to incur substantially more debt. This could further exacerbate therisks associated with our substantial debt.We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on the incurrenceof additional debt, these restrictions are subject to a number of significant qualifications and exceptions. Under certaincircumstances, the amount of debt, including secured debt, that could be incurred in the future in compliance with these restrictionscould be substantial. If new debt is added to our existing debt levels, the related risks that we and holders of our existing debtnow face could intensify.EFCH and its subsidiaries may pursue various transactions and initiatives to address their highly leveraged balance sheetsand significant cash interest requirements.Future transactions and initiatives that we may pursue may have significant effects on our business, capital structure,ownership, liquidity, credit ratings and/or results of operations. For example, in addition to the exchanges, repurchases andextensions of our debt beginning in 2009 reflected in Item 7, "Management's Discussion and Analysis of Financial Condition andResults of Operations -Significant Activities and Events and Items Influencing Future Performance -Liability ManagementProgram," EFH Corp., EFCH and TCEH continue to consider and evaluate possible transactions and initiatives to address theirhighly leveraged balance sheets and significant cash interest requirements and may from time to time enter into discussions withtheir lenders and bondholders with respect to such transactions and initiatives. These transactions and initiatives may include,among others, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equityexchanges or conversions, including exchanges or conversions of debt of EFCH and TCEH into equity of EFH Corp., EFCH,TCEH and/or any of their subsidiaries, and could have significant effects on the business, capital structure, ownership, liquidity,credit ratings and/or results of operations of EFCH and TCEH, including significantly deleveraging TCEH. There can be noguarantee that any of such transactions or initiatives would be successful or produce the desired outcome, which could ultimatelyaffect us or our debtholders in a material manner, including debtholders not recovering the full principal amount of TCEH debt.17 Table of ContentsOur debt agreements contain covenants and restrictions that limit flexibility in operating our businesses, and a breach of anyof these covenants or restrictions could result in an event of default under one or more of our debt agreements at differententities within our capital structure, including as a result of cross acceleration or default provisions.Our debt agreements contain various covenants and other restrictions that, among other things, limit flexibility in operatingour businesses. A breach of any of these covenants or restrictions could result in a significant portion of our debt becoming dueand payable. Our ability to comply with certain of our covenants and restrictions can be affected by events beyond our control.These covenants and other restrictions limit our ability to, among other things:* incur additional debt or issue preferred shares;" pay dividends on, repurchase or make distributions in respect of capital stock or make other restricted payments;" make investments;* sell or transfer assets;" create liens on assets to secure debt;" consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;" enter into transactions with affiliates;" designate subsidiaries as unrestricted subsidiaries, and" repay, repurchase or modify certain subordinated and other material debt.There are a number of important limitations and exceptions to these covenants and other restrictions. See Note 8 to FinancialStatements for a description of these covenants and other restrictions.Under the TCEH Senior Secured Facilities, TCEH is required to maintain a consolidated secured debt to consolidatedEBITDA ratio below specified levels. TCEH's ability to maintain the consolidated secured debt to consolidated EBITDA ratiobelow such levels can be affected by events beyond its control, including, without limitation, wholesale electricity prices (whichare primarily derived by the price of natural gas and ERCOT market heat rates) and environmental regulations, and there can beno assurance that TCEH will comply with this ratio. At December 31, 2012, TCEH's consolidated secured debt to consolidatedEBITDA ratio was 5.9 to 1.00, which compares to the maximum consolidated secured debt to consolidated EBITDA ratio of 8.00to 1.00 currently permitted under the TCEH Senior Secured Facilities. The secured debt portion of the ratio excludes (a) up to$1.5 billion of debt ($906 million excluded at December 31, 2012) secured by a first-priority lien (including the TCEH SeniorSecured Notes) if the proceeds of such debt are used to repay term loans or deposit letter of credit loans under the TCEH SeniorSecured Facilities and (b) debt secured by a lien ranking junior to the TCEH Senior Secured Facilities, including the TCEH SeniorSecured Second Lien Notes. In addition, under the TCEH Senior Secured Facilities, TCEH is required to timely deliver to thelenders audited annual financial statements that are not qualified as to the status of TCEH and its consolidated subsidiaries as agoing concern. See Note I to Financial Statements for discussion of TCEH's liquidity and the $3.8 billion of TCEH Term LoanFacilities that matures in October 2014.Abieach of any of these covenants or restrictions could result in an event of default under one or more of our debt agreementsat different entities within our capital structure, including as a result of cross acceleration or default provisions. Upon the occurrenceof an event of default under one of these debt agreements, our lenders or noteholders could elect to declare all amounts outstandingunder that debt agreement to be immediately due and payable and/or terminate all commitments to extend further credit. Suchactions by those lenders or noteholders could cause cross defaults or accelerations under our other debt. If we were unable torepay those amounts, the lenders or noteholders could proceed against any collateral granted to them to secure such debt. In thecase of a default under debt that is guaranteed, holders of such debt could also seek to enforce the guarantees. If lenders ornoteholders accelerate the repayment of all borrowings, we would likely not have sufficient assets and funds to repay thoseborrowings. Such occurrence could result in EFCH and/or its applicable subsidiary going into bankruptcy, liquidation or insolvency.In addition, EFH Corp. and Oncor have implemented a number of "ring-fencing" measures to enhance the credit quality ofOncor Holdings and its subsidiaries, including Oncor. Those measures include Oncor not guaranteeing or pledging any of itsassets to secure the debt of Texas Holdings and its other subsidiaries. Accordingly, Oncor's assets will not be available to repayany of our debt.18 Table of ContentsLenders and holders of our debt have in the past alleged, and might allege in the future, that we are not operating in compliancewith covenants in our debt agreements or make allegations against our directors and officers of breach offiduciary duty. Inaddition, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the pastclaimed, and might claim in the future, that a credit event has occurred under such credit derivative securities. In each case,even if the claims have no merit, these claims could cause the trading price of our debt securities to decline or adversely affectour ability to raise additional capital and/or refinance our existing debt.Lenders or holders of our debt have in the past alleged, and might allege in the future, that we are not operating in compliancewith the covenants in our debt agreements, that a default under our debt agreements has occurred or that our or our subsidiaries'boards of directors or similar bodies or officers are not properly discharging their fiduciary duties, or make other allegationsregarding our business, including for the purpose, and potentially having the effect, of causing a default under our debt or otheragreements, accelerating the maturity of such debt, protecting claims of debt issued at a certain entity or entities in our capitalstructure at the expense of debt claims elsewhere in our capital structure and/or obtaining economic benefits from us. These claimshave included, and may include in the future, among other things, claims that the TCEH Demand Notes were fraudulent transfersand should be repaid to TCEH, that authorization of the TCEH Demand Notes violated the fiduciary duties of EFCH's and TCEH'sboards of directors, that the TCEH Demand Notes were in violation of the terms of our debt agreements or that the interest rateon the TCEH Demand Notes was too low.Further, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the pastclaimed, and may claim in the future, that a credit event has occurred under such credit derivative securities based on our financialcondition. Even if these claims are without merit, they could nevertheless cause the trading price of our debt to decline andadversely affect our ability to raise additional capital and/or refinance our existing debt.We may not be able to generate sufficient cash to service our debt and may beforced to take other actions to satisfy the obligationsunder our debt agreements, which may not be successfulOur ability to make scheduled payments on our debt obligations depends on our financial condition and operatingperformance, which is subject to prevailing economic and competitive conditions and to certain financial, business and otherfactors beyond our control, including, without limitation, wholesale electricity prices (which are primarily driven by the price ofnatural gas and ERCOT market heat rates) and environmental regulations. We may not be able to maintain a level of cash flowssufficient to pay the principal, premium, if any, and interest on our debt, including the $3.8 billion principal amount of TCEHTerm Loan Facilities maturing in October 2014.If cash flows and capital resources are insufficient to fund our debt obligations, we could face substantial liquidity problemsand might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additionalcapital or restructure or refinance debt. These alternative measures may not be successful, may not be completed on economicallyattractive terms or may not be adequate for us to meet our debt obligations when due. Additionally, our debt agreements limit theuse of the proceeds from many dispositions of assets or operations. As a result, we may notbe permitted to use the proceeds fromthese dispositions to satisfy our debt obligations.Further, if we suffer or appear to suffer, from a lack of available liquidity, the evaluation of our creditworthiness bycounterparties and rating agencies and the willingness of third parties to do business with us could be adversely impacted. Inparticular, such concerns by existing and potential counterparties could significantly limit TCEH's wholesale market activities,including its natural gas price hedging program.Risks Related to Our StructureEFCH and TCEH are holding companies and their obligations are structurally subordinated to existing and future liabilitiesand preferred stock of their subsidiaries.EFCH's and TCEH's cash flows and ability to meet their obligations are largely dependent upon the earnings of theirsubsidiaries and the payment of such earnings to EFCH and TCEH in the form of dividends, distributions, loans or otherwise, andrepayment of loans or advances from EFCH or TCEH. These subsidiaries are separate and distinct legal entities and have noobligation (other than any existing contractual obligations) to provide EFCH or TCEH with fumds for their payment obligations.Any decision by a subsidiary to provide EFCH or TCEH with funds for their payment obligations, whether by dividends,distributions, loans or otherwise, will depend on, among other things, the subsidiary's results of operations, financial condition,cash requirements, contractual restrictions and other factors. In addition, a subsidiary's ability to pay dividends may be limitedby covenants in its existing and future debt agreements or applicable law.19 Table of ContentsBecause EFCH and TCEH are holding companies, their obligations to their creditors are structurally subordinated to allexisting and future liabilities and existing and future preferred stock of their subsidiaries that do not guarantee such obligations.Therefore, with respect to subsidiaries that do not guarantee EFCH's or TCEH's obligations, EFCH's and TCEH's rights and therights of their creditors to participate in the assets of any subsidiary in the event that such a subsidiary is liquidated or reorganizedare subject to the prior claims of such subsidiary's creditors and holders of such subsidiary's preferred stock. To the extent thatEFCH or TCEH may be a creditor with recognized claims against any such subsidiary, EFCH's or TCEH's claims would still besubject to the prior claims of such subsidiary's creditors to the extent that they are secured or senior to those held by EFCH orTCEH, Subject to restrictions contained in financing arrangements, EFCH's and TCEH's subsidiaries may incur additional debtand other liabilities.EFH Corp. has in the past relied significantly on loans from TCEH to meet its obligations, and if EFH Corp. does not receivedistributions from Oncor in the future it may need to borrow funds from TCEH.EFH Corp. is a holding company and substantially all of its reported consolidated assets are held by its subsidiaries. AtDecember 31, 2012, TCEH and its subsidiaries held approximately 79% of EFH Corp.'s reported consolidated assets, and for theyear ended December 31, 2012, TCEH and its subsidiaries represented all of EFH Corp.'s reported consolidated revenues.Accordingly, TCEH and its subsidiaries in the past constituted an important funding source for EFH Corp. to satisfy its obligations,which are significant. The terms of the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Notes and theTCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities permit TCEH to make loans and/or dividends (to the extent permitted by applicable state law) to cover certain of EFH Corp.'s obligations, particularly principaland interest payments. At December 31, 2012, TCEH had notes receivable from EFH Corp. (TCEH Demand Notes) totaling $698million (see Note 15 to Financial Statements) that were repaid in January 2013, but TCEH may if necessary make additional loansto EFH Corp. in the future.The TCEH Senior Secured Facilities contain provisions related to the TCEH Demand Notes, which are payable to TCEHon demand and and are guaranteed by EFCH and EFIH on a senior unsecured basis. These provisions include:" TCEH may only make loans to EFH Corp. for debt principal and interest payments;" borrowings outstanding under the TCEH Demand Notes will not exceed $2 billion in the aggregate at any time; and" the sum of(a) the outstanding senior secured indebtedness (including guarantees) issued by EFH Corp. or any subsidiaryof EFH Corp. (including EFIH) secured by a second-priority lien on the equity interests that EFIH owns in OncorHoldings (EFIH Second-Priority Debt) and (b) the aggregate outstanding amount of the TCEH Demand Notes will notexceed, at any time, the maximum amount of EFIH Second-Priority Debt permitted by the indenture governing the EFHCorp. Senior Secured Notes as in effect on April 7, 2011.EFH Corp. and Oncor, which is a subsidiary of EFH Corp. but not a subsidiary of EFCH, have implemented certain structuraland operational "ring-fencing" measures that were based on principles articulated by rating agencies and commitments made byTexas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor's credit quality. These measures were put intoplace to mitigate Oncor's credit exposure to Texas Holdings and its subsidiaries other than Oncor Holdings and its subsidiaries(Texas Holdings Group) and to reduce the risk that the assets and liabilities of Oncor would be substantively consolidated withthe assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities.As part of the ring-fencing measures, a majority of the members of the board of directors of Oncor are required to be, andare, independent from EFH Corp. Any new independent directors of Oncor are required to be appointed by the nominatingcommittee of Oncor Holdings, which is required to be, and is, comprised of a majority of directors that are independent from EFHCorp. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certainperiods, any director designated by Texas Transmission Investment LLC (which owns approximately 19.75% of Oncor), the expressright to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meetexpected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp., whichmay result in EFH Corp. relying on loans from TCEH to meet its obligations.In addition, Oncor's organizational documents prohibit Oncor from making any distribution to EFH Corp. so long as and tothe extent that such distribution would cause Oncor's regulatory capital structure to exceed the debt-to-equity ratio establishedfrom time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.20 Table of ContentsRisks Related to Our BusinessesTCEH's revenues and results of operations generally are negatively impacted by decreases in market prices for electricity,natural gas prices and/or market heat rates.TCEH is not guaranteed any rate of return on capital investments in its businesses. We market and trade electricity, includingelectricity from our own generation facilities and generation contracted from third parties, as part of our wholesale operations.TCEH's results of operations depend in large part upon wholesale market prices for electricity, natural gas, uranium, coal, fuel oiland transportation in its regional market and other competitive markets and upon prevailing retail electricity rates, which may beimpacted by, among other things, actions of regulatory authorities. Market prices may fluctuate substantially over relatively shortperiods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. Duringperiods of over-supply, prices might be depressed. Also, at times, there may be political pressure, or pressure from regulatoryauthorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations,bidding rules and other mechanisms to address volatility and other issues in these markets.Some of the fuel for our generation facilities is purchased under short-term contracts. Prices of fuel (including diesel, naturalgas, coal and nuclear fuel) may also be volatile, and the price we can obtain for electricity sales may not change at the same rateas changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility inthese markets may affect costs incurred in meeting obligations.Volatility in market prices for fuel and electricity may result from the following:" volatility in natural gas prices;" volatility in ERCOT market heat rates;" volatility in coal and rail transportation prices;" severe or unexpected weather conditions, including drought and limitations on access to water;" seasonality;" changes in electricity and fuel usage;* illiquidity in the wholesale power or other commodity markets;" transmission or transportation constraints, inoperability or inefficiencies;" availability of competitively-priced alternative energy sources;" changes in market structure;" changes in supply and demand for energy commodities, including nuclear fuel and related enrichment and conversionservices;" changes in the manner in which we operate our facilities, including curtailed operation due to market pricing,environmental, safety or other factors;" changes in generation efficiency;" outages or otherwise reduced output from our generation facilities or those of our competitors;" changes in the credit risk or payment practices of market participants;" changes in production and storage levels of natural gas, lignite, coal, crude oil, diesel and other refined products;" natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and" federal, state and local energy, environmental and other regulation and legislation.All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets.Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas because marginal electricitydemand is generally supplied by natural gas-fueled generation facilities. Accordingly, our earnings and the value of our nuclearand lignite/coal-fueled generation assets, which provided a substantial portion of our supply volumes in 2012, are dependent insignificant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008 (from$11.12 per MMBtu in mid-2008 to $4.03 per MMBtu at December 31, 2012 for calendar year 2014). In recent years natural gassupply has outpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weaknessassociated with the economic downturn. Many industry experts expect this supply/demand imbalance to continue for a numberof years, thereby depressing natural gas prices for a long-term period.Wholesale electricity prices also have generally moved with ERCOT market heat rates, which could fall if demand forelectricity were to decrease or if more efficient generation facilities are built in ERCOT. Accordingly, our earnings and the valueof our nuclear and lignite/coal-fueled generation assets are also dependent in significant part upon market heat rates. As a result,our nuclear and lignite/coal-fueled generation assets could significantly decrease in profitability and value if ERCOT market heatrates decline.21 Table of ContentsOur assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedgingtransactions may not work as planned or hedge counterparties may default on their obligations.We cannot fully hedge the risk associated with changes in commodity prices, most notably electricity and natural gas prices,because of the expected useful life of our generation assets and the size of our position relative to market liquidity. To the extentwe have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations,liquidity and financial position, either favorably or unfavorably.To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portionsof purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, crude oil, diesel fuel, uraniumand refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinelyutilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of riskmanagement procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place maynot always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge theexpected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, consumer behavior,market constraints or other factors could cause us to purchase power to meet unexpected demand in periods of high wholesalemarket prices or resell excess power into the wholesale market in periods of low prices. As a result of these and other factors, wecannot precisely predict the impact that risk management decisions may have on our businesses, results of operations, liquidityor financial position.With the tightening of credit markets that began in 2008 and the expansion of regulatory oversight through various financialreforms, there has been some decline in the number of market participants in the wholesale energy commodities markets, resultingin less liquidity, particularly in the ERCOT electricity market. Participation by financial institutions and other intermediaries(including investment banks) has particularly declined. Extended declines in market liquidity could materially affect our abilityto hedge our financial exposure to desired levels.To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that oweus money, energy or other commodities as a result of these activities will not perform their obligations. Should the counterpartiesto these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlyingcommitment at then-current market prices. In such event, we could incur losses in addition to amounts, if any, already paid to thecounterparties. ERCOT market participants are also exposed to risks that another ERCOT market participant may default on itsobligations to pay ERCOT for power taken, in which case such costs, to the extent not offset by posted security and other protectionsavailable to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in thefuture impact, our businesses and/or results of operations.Our businesses operate in changing market environments influenced by various state and federal legislative and regulatoryinitiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. Wewill need to continually adapt to these changes.Our businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic EnergyAct, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act, the Energy Policy Act of 2005 and the Dodd-FrankWall Street Reform and Consumer Protection Act), changing governmental policy and regulatory actions (including those of thePUCT, the NERC, the TRE, the RRC, the TCEQ, the FERC, the EPA, the NRC and the CFTC) and the rules, guidelines andprotocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nucleargeneration facilities, construction and operation of other generation facilities, recovery of costs and investments, decommissioningcosts, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, alongwith other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rulesand regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to any wholesale power salesoutside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the FederalPower Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations mayhave a material effect on our businesses.The Texas Legislature meets every two years (the current legislative session began in January 2013); however, at any timethe governor of Texas may convene a special session of the Legislature. During any regular or special session bills may beintroduced that, if adopted, could materially affect our businesses, including our results of operations, liquidity or financialcondition.22 Table of ContentsThe PUCT and the RRC are subject to a "Sunset" review by the Texas Sunset Advisory Commission during the 2013 sessionof the Texas Legislature. The powers of the PUCT and the RRC may be materially changed, or the agencies may be abolished,by the Texas Legislature following such review. If the PUCT or the RRC are not renewed or are changed materially by theTexas Legislature pursuant to Sunset review, it could have a material effect on our businesses.Sunset review is the regular assessment of the continuing need for a state agency to exist, and is grounded in the'premisethat an agency will be abolished unless legislation is passed to continue its functions. On a specified time schedule, the TexasSunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agency to theTexas Legislature, which action may include modifying or even abolishing the agency. The PUCT and the RRC are subject toreview by the Sunset Commission in 2013. In 2011, the Texas Legislature extended the authority of the RRC and the PUCT until2013. In 2013, the RRC will undergo a full sunset review, and the PUCT will undergo a limited sunset review. These agencies,for the most part, govern and operate the electricity and mining markets in Texas upon which our business model is based. If theTexas Legislature materially changes or fails to renew either of these agencies, it could have a material impact on our business.There can be no assurance that future action of the Sunset Commission will not result in legislation during the 2013 LegislativeSession that could have a material effect on our results of operations, liquidity or financial condition.Our cost of compliance with existing and new environmental laws could materially affect our results of operations, liquidityand financial condition.We are subject to extensive environmental regulation by governmental authorities, including the EPA and the TCEQ. Inoperating our facilities, we are required to comply with numerous environmental laws and regulations and to obtain numerousgovernmental permits. We may incur significant additional costs beyond those currently contemplated to comply with theserequirements. If we fail to comply with these requirements, we could be subject to civil or criminal liabilities and fines. Existingenvironmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable tous or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory andenforcement developments related to air emissions, all of which could result in significant additional costs beyond those currentlycontemplated to comply with existing requirements (see Note 9 to Financial Statements).Over the past couple of years, the EPA has completed several regulatory actions establishing new requirements for controlof certain emissions from sources including electricity generation facilities. It is also currently considering several other regulatoryactions, as well as contemplating future additional regulatory actions, in each case that may affect our generation facilities or ourability to cost-effectively develop new generation facilities. There is no assurance that the currently-installed emissions controlequipment at our coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Someof the recent regulatory actions, such as the EPA's CSAPR and MATS, could require us to install significant additional controlequipment, resulting in material costs of compliance for our generation units, including capital expenditures, higher operating andfuel costs and potential production curtailments if the rules take effect. These costs could result in material effects on our resultsof operations, liquidity and financial condition.We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtainingany required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approvalis retroactively disallowed, the operation of our facilities could be stopped, curtailed or modified or become subject to additionalcosts.In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities thatwe have acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. Inconnection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certainenvironmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or failto meet its indemnification obligations to us.23 Table of ContentsOur results of operations, liquidity and financial condition may be materially affected if new federal and/or state legislationor regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons orproperty resulting from greenhouse gas emissions.There is a concern nationally and internationally about global climate change and how greenhouse gas (GHG) emissions,such as carbon dioxide (CO2), contribute to global climate change. Over the last few years, several bills addressing climate changehave been introduced in the US Congress or discussed by the Obama Administration that were intended to address climate changeusing different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the development of low-carbon technology and federal renewableportfolio standards. In addition, a number of federal court cases have been filed in recent years asserting damage claims relatedto GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (includingus) that produce GHG emissions.The EPA rule known as the Prevention of Significant Deterioration (PSD) tailoring rule established thresholds for regulatingGHG emissions from stationary sources under the Clean Air Act. The rule requires any source subject to the PSD permittingprogram, due to emissions of non-GHG pollutants, that increases its GHG emissions by 75,000 tons per year (tpy) to have anoperating permit under the Title V Operating Permit Program of the Clean Air Act and install the best available control technologyin conjunction with construction activities or plant modifications. PSD permitting requirements also apply to new projects withGHG emissions of at least 100,000 tpy and modifications to existing facilities that increase GHG emissions by at least 75,000 tpy(even if no non-GHG PSD thresholds are exceeded). The EPA has also issued regulations that require certain categories of GHGemitters (including our lignite/coal-fueled generation facilities) to monitor and report their annual GHG emissions.In March 2012, the EPA released a proposal for a performance standard for greenhouse gas emissions from new electricgeneration units (EGUs). The proposal, which is currently limited to new sources, is based on the carbon dioxide emission ratefrom a natural gas-fueled combined cycle EGU. None of our existing generation units would be considered a new source underthe proposed rule. While we do not believe the proposed rule, as released, affects our existing generation units, it could affect ourability to cost-effectively develop new generation facilities. If limits or guidelines become applicable to our generation facilitiesand require us to install new control equipment or substantially alter our operations, it could have a material effect on our resultsof operations, liquidity and financial condition.We produce GHG emissions from the combustion of fossil fuels at our generation facilities. Because a substantial portionof our generation portfolio consists of lignite/coat-fueled generation facilities, our results of operations, liquidity and financialcondition could be materially affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissionsor that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowancesor credits to comply with such a program. The EPA regulation of GHGs under the Clean Air Act, or judicially imposed sanctionsor damage awards related to GHG emissions, may require us to make material expenditures to reduce our GHG emissions. Inaddition, if a significant number of our customers or others refuse to do business with us because of our GHG emissions, it couldhave a material effect on our results of operations, liquidity or financial condition.Litigation related to environmental issues, including claims alleging that GHG emissions constitute a public nuisance bycontributing to global climate change, has increased in recent years. American Electric Power Co. v. Connecticut, Comer v. MurphyOil USA and Native Village ofKivalina v. ExxonMobil Corporation all involve nuisance claims for damages purportedly causedby the defendants' emissions of GHGs. Although we are not currently a party to any pending lawsuits alleging that GHG emissionsare a public nuisance, these lawsuits could establish precedent that might affect our business or industry generally. Other similarlawsuits have involved claims of property damage, personal injury, challenges to issued permits and citizen enforcement ofenvironmental laws and regulations. We cannot predict the ultimate outcome of the pending proceedings. If we are sued in theseor similar proceedings and are ultimately subject to an adverse ruling, we could be required to make substantial capital expendituresfor emissions control equipment, halt operations and/or pay substantial damages. Such expenditures or the cessation of operationscould adversely affect our results of operations, liquidity and financial condition.24 Table of ContentsIf we are required to comply with the EPA's revised Cross-State Air Pollution Rule (CSAPR), or a similar replacement, andthe Mercury and Air Toxics Standard (MATS) we will likely incur material capital expenditures and operating costs andexperience material revenue decreases due to reduced generation and wholesale electricity sales volumes.In July 2011, the EPA issued the CSAPR, a replacement for the Clean Air Interstate Rule (CAIR). In February 2012, theEPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including emissions budgetsfor the State of Texas as discussed in Items 1 and 2, "Business and Properties -Environmental Regulations and RelatedConsiderations- Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions." In June 2012, the EPA finalized the proposed rule(Second Revised Rule). In total, the emissions budgets established by the Final Revisions along with the Second Revised Rulewould require our fossil-fueled generation units to reduce (i) their annual SO2 and NOx emissions by approximately 120,600 tons(56 percent) and 9,000 tons (22 percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NOx emissions byapproximately 3,300 tons (18 percent), compared to 2010 levels. We could comply with these emissions limits either throughphysical reductions or through the purchase of emissions credits from third parties, but the volume of SO2 credits that may bepurchased from sources outside of Texas is subject to limitations starting in 2014. Because the CSAPR was vacated and remandedto the EPA in August 2012 by a three judge panel of the D.C. Circuit Court, the CSAPR, the Final Revisions and the SecondRevised Rule do not impose any immediate legal or compliance requirements on us, the State of Texas, or other affected parties.In October 2012, the EPA and certain other parties that supported the CSAPR filed petitions seeking review by the full court ofthe D.C. Circuit Court's ruling. In January 2013, the D.C. Circuit Court denied the request for rehearing. The EPA and the otherparties to these proceedings have approximately 90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court.We cannot predict whether, when, or in what form the CSAPR, the Final Revisions, the Second Revised Rule or any replacementswill take effect.Material capital expenditures would be required to comply with the CSAPR, as revised in June 2012, as well as with otherpending and expected environmental regulations, including the MATS, for which we and certain states and industry participantshave filed petitions for review in the D.C. Circuit Court. We cannot predict the outcome of these petitions.Prior to the publication of the final MATS rule and the vacatur and remand of the CSAPR, we estimated that expendituresof more than $1.5 billion before the end of the decade in environmental control equipment would be required to comply withregulatory requirements, including the CSAPR and MATS. We have revised our estimates ofcapital expenditures for environmentalcontrol equipment to comply with regulatory requirements, based on analysis and testing of options to comply with the MATSrule, as well as estimates related to other EPA regulations, including expenditures previously incurred related to the CSAPR.Between 2011 and the end of the decade, we estimate that we will incur more than $1 billion in capital expenditures for environmentalcontrol equipment, though the ultimate total will depend on the evolution of pending or future regulatory requirements. Basedon regulations currently in effect, we estimate that we will incur approximately $500 million of environmental capital expendituresbetween 2013 and 2017, including amounts required to maintain installed environmental control equipment.We cannot predict whether the EPA or any other party will appeal the D.C. Circuit Court's decision with respect to the CSAPRto the US Supreme Court or, if such appeal is granted, how the US Supreme Court will rule on any such appeal of the CSAPR.As a result, there can be no assurance that we will not be required to implement a compliance plan for the CSAPR, the FinalRevisions, the Second Revised Rule or any replacement rules in a short time frame or that such plan will not materially affect ourresults of operations, liquidity or financial condition.Luminant's mining permits are subject to RRC review.The RRC reviews on an ongoing basis whether Luminant is compliant with RRC rules and regulations and whether it hasmet all of the requirements of its mining permits. Any revocation of a mining permit would mean that Luminant would no longerbe allowed to mine lignite at the applicable mine to serve its generation facilities. Such event would have a material effect on ourresults of operations, liquidity and financial condition.25 Table of ContentsLitigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significantliabilities and reputation damage, and have a material effect on our results of operations, and the litigation environment inwhich we operate poses a significant risk to our businesses.We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, andenvironmental issues, and other claims for injuries and damages, among other matters. We evaluate litigation claims and legalproceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Basedon these evaluations and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, asappropriate. These evaluations and estimates are based on the information available to management at the time and involve asignificant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. Thesettlement or resolution of such claims or proceedings may have a material effect on our results of operations. We use appropriatemeans to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significantbusiness risk.We are involved in the ordinary course of business in permit applications and renewals, and we are exposed to the risk thatcertain of our operating permit applications may not be granted or that certain of our operating permits may not be renewed onsatisfactory terms. Failure to obtain and maintain the necessary permits to conduct our businesses could have a material effect onour results of operations, liquidity and financial condition.We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings,and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings.See Item 3, "Legal Proceedings -Regulatory Reviews." While we cannot predict the outcome of any regulatory investigation oradministrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring materialpenalties and/or other costs and have a material effect on our results of operations, liquidity and financial condition.Our collateral requirements for hedging arrangements could be materially impacted if the remaining rules implementing theFinancial Reform Act broaden the scope of the Act's provisions regarding the regulation of over-the-counter financialderivatives, making certain provisions applicable to end-users like us.In July 2010, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (theFinancial Reform Act) was enacted. While the legislation is broad and detailed, a few key rulemaking decisions remain to bemade by federal governmental agencies to fully implement the Financial Reform Act.Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives (Swaps) market.The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we useto hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However,under the end-user clearing exemption, entities are exempt from these clearing requirements if they (i) arenot "Swap Dealers" or"Major Swap Participants" and (ii) use Swaps to hedge or mitigate commercial risk. The legislation mandates significant compliancerequirements for any entity that is determined to be a Swap Dealer or Major Swap Participant and additional reporting andrecordkeeping requirements for all entities that participate in the derivative markets. See Item 7, "Management's Discussion andAnalysis of Financial Condition and Results of Operations -Key Risks and Challenges -Financial Services Reform Legislation."The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateralrequirements are unclear as to whether an end-user or its counterparty (e.g., swap dealer) is required to post cash collateral, thereis risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. The final rule formargin requirements has not been issued. However, the legislative history of the Financial Reform Act suggests that it was notCongress' intent to require end-users to post cash collateral with respect to swaps. If we were required to post cash collateral onour swap transactions with swap dealers, our liquidity would likely be materially impacted, and our ability to enter into derivativesto hedge our commodity and interest rate risks would be significantly limited.We cannot predict the outcome of the final rulemakings to implement the OTC derivative market provisions of the FinancialReform Act. Based on our assessment and published guidance from the CFTC, we are not a Swap Dealer or Major Swap Participantand we will be able to take advantage of the End-User Exemption for Swaps that hedge or mitigate commercial risk; however, theremaining rulemakings related to how Swap Dealers and other market participants administer margin requirements could negativelyaffect our ability to hedge our commodity and interest rate risks. The inability to hedge these risks would likely have a materialeffect on our results of operations, liquidity and financial condition.26 Table of ContentsWe may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generationfacility.The ownership and operation of a nuclear generation facility involves certain risks. These risks include:* unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity or other problems;* inadequacy or lapses in maintenance protocols;* the impairment of reactor operation and safety systems due to human error or force majeure;* the costs of storage, handling and disposal of nuclear materials, including availability of storage space;* the costs of procuring nuclear fuel;* the costs of securing the plant against possible terrorist or cybersecurity attacks;* limitations on the amounts and types of insurance coverage commercially available, and* uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end oftheir useful lives.The prolonged unavailability of Comanche Peak could materially affect our financial condition and results of operations.The following are among the more significant of these risks:" Operational Risk -Operations at any nuclear generation facility could degrade to the point where the facility wouldhave to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of theoperational downgrade to return the facility to operation could require significant time and expense, resulting in bothlost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-downor failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availabilityat Comanche Peak." Regulatory Risk -The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to complywith the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unlessextended, the NRC operating licenses for Comanche Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively.Changes in regulations by the NRC, including potential regulation as a result of the NRC's ongoing analysis and responseto the effects of the natural disaster on nuclear generation facilities in Japan in 2010, could require a substantial increasein capital expenditures or result in increased operating or decommissioning costs.* Nuclear Accident Risk -Although the safety record of Comanche Peak and other nuclear generation facilities generallyhas been very good, accidents and other unforeseen problems have occurred both in the US and elsewhere. Theconsequences of an accident can be severe and include loss of life, injury, lasting negative health impact and propertydamage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any suchresulting liability from a nuclear accident could exceed our resources, including insurance coverage.The operation and maintenance of electricity generation facilities involves significant risks that could adversely affect ourresults of operations, liquidity and financial condition.The operation and maintenance of electricity generation facilities involves many risks, including, as applicable, start-uprisks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel sourceor the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expectedlevels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses.A significant number ofour facilities were constructed many years ago. In particular, older generating equipment, even ifmaintainedin accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiencyor reliability. The risk of increased maintenance and capital expenditures arises from (i) increased starting and stopping of generationequipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricityprices that may not justify sustained or year-round operation of all our generating facilities, (ii) any unexpected failure to generateelectricity, including failure caused by equipment breakdown or forced outage, (iii) damage to facilities due to storms, naturaldisasters, wars, terrorist or cybersecurity acts and other catastrophic events and (iv) the passage of time and normal wear and tear.Further, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects iscontingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject toadditional costs and/or losses and write downs of our investment in the project or improvement.27 Table of ContentsWe cannot be certain of the level of capital expenditures that will be required due to changing environmental and safetylaws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events(such as natural disasters or terrorist or cybersecurity attacks). The unexpected requirement of large capital expenditures couldmaterially affect our results of operations, liquidity and financial condition.If we make any major modifications to our power generation facilities, we may be required to install the best availablecontrol technology or to achieve the lowest achievable emission rates as such terms are defined under the new source reviewprovisions of the Clean Air Act. Any such modifications would likely result in us incurring substantial additional capitalexpenditures.Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses thatcould result from the risks discussed above, including the cost of replacement power. Likewise, the ability to obtain insurance,and the cost of and coverage provided by such insurance, could be affected by events outside our control.Our results of operations, liquidity and financial condition may be materially affected by the effects of extreme weatherconditions.Our results of operations may be affected by weather conditions and may fluctuate substantially on a seasonal basis as theweather changes. In addition, we could be subject to the effects of extreme weather. Extreme weather conditions could stress ourgeneration facilities resulting in outages, increased maintenance and capital expenditures. Extreme weather events, includingsustained cold temperatures, hurricanes, storms or other natural disasters, could be destructive and result in casualty losses thatare not ultimately offset by insurance proceeds or in increased capital expenditures or costs, including supply chain costs.Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damageto other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weatherevent might affect the availability of generation and transmission capacity, limiting our ability to source or deliver electricity whereit is needed or limit our ability to source fuel for our plants (including due to damage to rail infrastructure). These conditions,which cannot be reliably predicted, could have an adverse consequence by requiring us to seek additional sources of electricitywhen wholesale market prices are high or to sell excess electricity when market prices are low.Our results of operations, liquidity and financial condition may be materially affected by insufficient water supplies.Supplies of water are important for our generation facilities. Water in Texas is limited and various parties have madeconflicting claims regarding the right to access and use such limited supplies of water. In addition, Texas has experienced sustaineddrought conditions that could affect the water supply for certain of our generation facilities if adequate rain does not fall in thewatershed that supplies the affected areas. If we are unable to access sufficient supplies of water, it could restrict, prevent orincrease the cost of operations at certain of our generation facilities.Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significantadditional costs if unsuccessfuLAs we seek to improve our financial condition, we have taken, and intend to take steps to reduce our costs. While we havecompleted and have underway a number of initiatives to reduce costs, it will likely become increasingly difficult to identify andimplement significant new cost savings initiatives. The implementation of performance improvement initiatives identified bymanagement may not produce the desired reduction in costs and if unsuccessful, may instead result in significant additional costsas well as significant disruptions in our operations due to employee displacement and the rapid pace of changes to organizationalstructure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect onour results of operations, liquidity and financial condition.28 Table of ContentsAttacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities and reputationdamage and disrupt business operations, which could have a material effect on our results of operations, liquidity andfinancialcondition.Much of our information technology infrastructure is connected (directly or indirectly) to the Internet. There have beennumerous attacks on government and industry information technology systems through the Internet that have resulted in materialoperational, reputation and/or financial costs. While we have controls in place designed to protect our infrastructure and have nothad any significant breaches, a breach ofcyber/data security measures that impairs our information technology infrastructure coulddisrupt normal business operations and affect our ability to control our generation assets, access retail customer information andlimit communication with third parties. Any loss of confidential or proprietary data through a breach could adversely affect ourreputation, expose the company to material legal/regulatory claims, impair our ability to execute on business strategies and/ormaterially affect our results of operations, liquidity and financial condition.As part of the continuing development of new and modified reliability standards, the FERC has approved changes to itsCritical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets."Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day per violation) for failure to complywith mandatory electric reliability standards, including standards to protect the power system against potential disruptions fromcyber and physical security breaches.Our retail operations (TXU Energy) may lose a significant number of customers due to competitive marketing activity by otherretail electric providers.Our retail operations face competition for customers. Competitors may offer lower prices and other incentives, which,despite the business' long-standing relationship with customers, may attract customers away from us. We operate in a verycompetitive retail market, as is reflected in a 21% decline in customers (based on meters) served over the last four years.In some retail electricity markets, our principal competitor may be the incumbent REP. The incumbent REP has the advantageof long-standing relationships with its customers, including well-known brand recognition.In addition to competition from the incumbent REP, we may face competition from a number ofother energy service providers,other energy industry participants, or nationally branded providers of consumer products and services who may develop businessesthat will compete with us. Some of these competitors or potential competitors may be larger or better capitalized than we are. Ifthere is inadequate potential margin in these retail electricity markets, it may not be profitable for us to compete in these markets.Our retail operations are subject to the risk that sensitive customer data may be compromised, which could result in an adverseimpact to our reputation and/or the results of the retail operations.Our retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitivecustomer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history,credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank accountinformation. Our retail business may need to provide sensitive customer data to vendors and service providers who require accessto this information in order to provide services, such as call center operations, to the retail business. If a significant breach occurred,the reputation of our retail business may be adversely affected, customer confidence may be diminished, or our retail businessmay be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the businessand its results of operations, liquidity and financial condition.Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provideelectricity to, and to obtain information about, its customers. Any infrastructure failure could negatively impact customersatisfaction and could have a material negative impact on the business and results of operations.Our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities, as wellas Oncor's facilities, to deliver the electricity it sells to its customers. If transmission capacity is inadequate, our ability to sell anddeliver electricity may be hindered, and we may have to forgo sales or buy more expensive wholesale electricity than is availablein the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers mayexceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interruptsor impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service.29 Table of ContentsOur retail operations offer bundled services to customers, with some bundled services offered at fixed prices and for fixedterms. If our costs for these bundled services exceed the prices paid by our customers, our results of operations could bematerially affected.Our retail operations offer customers a bundle of services that include, at a minimum, electricity plus transmission, distributionand related services. The prices we charge for the bundle of services or for the various components of the bundle, any of whichmay be fixed by contract with the customer for a period of time, could fall below our underlying cost to provide the componentsof such services.The REP certification of our retail operations is subject to PUCT review.The PUCT may at any time initiate an investigation into whether our retail operations comply with PUCT Substantive Rulesand whether we have met all ofthe requirements for REP certification, including financial requirements. Any removal or revocationof a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers. Suchdecertification could have a material effect on our results of operations, liquidity and financial condition.Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and maysignificantly impact our businesses in other ways as well.Research and development activities are ongoing to improve existing and alternative technologies to produce electricity,including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. It is possiblethat advances in these or other technologies will reduce the costs of electricity production from these technologies to a level thatwill enable these technologies to compete effectively with our traditional generation facilities. Consequently, where we havefacilities, the profitability and market value of our generation assets could be significantly reduced. Changes in technology couldalso alter the channels through which retail customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be materially reduced.Electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewisesignificantly reduce the value of our generation assets. Certain regulatory and legislative bodies have introduced or are consideringrequirements and/or incentives to reduce energy consumption. Effective energy conservation by our customers could result inreduced energy demand or significantly slow the growth in demand. Such reduction in demand could materially reduce ourrevenues. Furthermore, we may incur increased capital expenditures if we are required to increase investment in conservationmeasures.Our revenues and results of operations may be adversely impacted by decreases in wholesale market prices of electricity dueto the development of wind generation sources.A significant amount of investment in wind generation in the ERCOT market over the past few years has increased overallwind power generation capacity. Generally, the increased capacity has led to lower wholesale electricity prices (driven by lowermarket heat rates) in the regions at or near wind power development. As a result, the profitability of our generation facilities andpower purchase contracts, including certain wind generation power purchase contracts, has been impacted and could be furtherimpacted by the effects of the wind power development, and the value could significantly decrease if wind power generation hasa material sustained effect on market heat rates.Our results of operations andfinancial condition could be negatively impacted by any development or event beyond our controlthat causes economic weakness in the ERCOT market.We derive substantially all of our revenues from operations in the ERCOT market, which covers approximately 75% of thegeographical area in the State of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market,economic weakness in the ERCOT market could lead to reduced demand for electricity in the ERCOT market. Such a reductioncould have a material negative impact on our results of operations, liquidity and financial condition.30 Table of ContentsOur liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets and/or duringtimes when there are significant changes in commodity prices. The inability to access liquidity, particularly on favorable terms,could materially affect our results of operations, liquidity and financial condition.Our businesses are capital intensive. We rely on access to financial markets and credit facilities as a significant source ofliquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The inabilityto raise capital or access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our ability tomeet our obligations or sustain and grow our businesses and could increase capital costs. Our access to the financial markets andcredit facilities could be adversely impacted by various factors, such as:" changes in financial markets that reduce available liquidity or the ability to obtain or renew credit facilities on acceptableterms;.economic weakness in the ERCOT or general US market;" changes in interest rates;* a deterioration, or perceived deterioration of EFCH's (and/or its subsidiaries') creditworthiness or enterprise value;" a reduction in EFCH's or its applicable subsidiaries' credit ratings;* a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilitiesthat affects the ability of such lender(s) to make loans to us;" volatility in commodity prices that increases margin or credit requirements;" a material breakdown in our risk management procedures, and" the occurrence of changes in our businesses that restrict our ability to access credit facilities.Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the sizeof our hedging program, any significant increase in the price of natural gas could result in us being required to provide cash orletter of credit collateral in substantial amounts. Any perceived reduction in our creditworthiness could result in clearing agentsor other counterparties requesting additional collateral. An event of default by one or more of our hedge counterparties couldresult in termination-related settlement payments that reduce available liquidity if we owe amounts related to commodity contractsor delays in receipts of expected settlements if the hedge counterparties owe amounts to us. These events could have a materialnegative impact on our results of operations, liquidity and financial condition.In the event that the governmental agencies that regulate the activities of our businesses determine that the creditworthinessof any such business is inadequate to support our activities, such agencies could require us to provide additional cash or letter ofcredit collateral in substantial amounts to qualify to do business.In the event our credit facilities are being used largely to support the hedging program as a result of a significant increasein the price of natural gas or significant reduction in creditworthiness, we may have to forego certain capital expenditures or otherinvestments in our businesses or other business opportunities.Further, a lack of available liquidity could adversely impact the evaluation of our creditworthiness by counterparties andrating agencies. In particular, such concerns by existing and potential counterparties could significantly limit TCEH's wholesalemarkets activities, including any future hedging activities.The costs ofprovidingpostretirement benefits and relatedfunding requirements are subject to changes in value offund assets,benefit costs, demographics and actuarial assumptions and may have a material effect on our results of operations, liquidityand financial condition.To a limited extent, EFH Corp. provides pension benefits based on either a traditional defined benefit formula or a cashbalance formula and also provides certain health care and life insurance benefits to our eligible employees and their eligibledependents upon the retirement of such employees. Our costs of providing such benefits and related funding requirements aredependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates,including the market value of the assets funding EFH Corp.'s pension and OPEB plans. Fluctuations in financial market returnsas well as changes in general interest rates may result in increased or decreased benefit costs in future periods.31 Table of ContentsThe values of the investments that fund EFH Corp.'s pension and OPEB plans are subject to changes in financial marketconditions. Significant decreases in the values of these investments could increase the expenses of the pension plan and the costsof the OPEB plans and related funding requirements in the future. Our costs of providing such benefits and related fundingrequirements are also subject to changing employee demographics (including but not limited to age, compensation levels andyears of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and thediscount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impactcurrent and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result inincreased or decreased benefit costs in future periods. See Note 13 to Financial Statements for further discussion of EFH Corp.'spension and OPEB plans, including certain pension plan amendments approved by EFH Corp. in August 2012.As discussed in Note 3 to Financial Statements, goodwill and/or other intangible assets not subject to amortization that wehave recorded in connection with the Merger are subject to at least annual impairment evaluations. As a result, we could berequired in the future to write off some or all of this goodwill and other intangible assets, such as the goodwill impairments of$1.2 billion and $4.1 billion recorded in 2012 and 2010, respectively, which may cause adverse impacts on our results ofoperations and financial condition.In accordance with accounting standards, goodwill and certain other indefinite-lived intangible assets that are not subject toamortization are reviewed annually or, if certain conditions exist, more frequently, for impairment. Factors such as the economicclimate, market conditions, including the market prices for wholesale electricity and natural gas and market heat rates, environmentalregulation, and the condition of assets are considered when evaluating these assets for impairment. The actual timing and amountsof any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Any reduction in or impairmentof the value of goodwill or other intangible assets will result in a charge against earnings, which could cause a material impact onour reported results of operations and financial condition.The loss of the services of our key management and personnel could adversely affect our ability to operate our businesses.Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete forsuch personnel with many other companies, in and outside our industry, government entities and other organizations. We maynot be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attractnew personnel or retain existing personnel could have a material effect on our businesses.The Sponsor Group in the aggregate controls and may have conflicts of interest with us in the future.The Sponsor Group in the aggregate indirectly owns approximately 60% of EFH Corp.'s capital stock on a fully-dilutedbasis through its investment in Texas Holdings. As a result of this ownership and the Sponsor Group's aggregate ownership ininterests of the general partner of Texas Holdings, the Sponsor Group taken as a whole has control over decisions regarding ouroperations, plans, strategies, finances and structure, including whether to enter into any corporate transaction, and will have theability to prevent any transaction that requires the approval of EFH Corp.'s shareholders. The Sponsor Group is comprised ofKohlberg Kravis Roberts & Co. L.P., TPG and GS Capital Partners, each of which acts independently of the others with respectto its investment in EFH Corp. and Texas Holdings.The interests of these entities may differ in material respects from the interests of holders of EFCH and its subsidiaries' debt.For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of the Sponsor Group,as equity holders or as members of the board of directors of EFH Corp., might conflict with our noteholders' and other creditors'interests. The Sponsor Group may also have an interest in pursuing acquisitions, divestitures, financings or other transactionsthat, in theirjudgment, could enhance their equity investments, even though such transactions might involve risks to our noteholdersand other creditors. Additionally, the agreements governing the terms of our debt permits us to distribute cash to EFH Corp. topay advisory fees, dividends or make other restricted payments under certain circumstances, and the Sponsor Group may have aninterest in our doing so.Each member of the Sponsor Group is in the business of making investments in companies and may from time to timeacquire and hold interests in businesses that compete directly or indirectly with us. Members of the Sponsor Group may alsopursue acquisition opportunities that may be complementary to our businesses and, as a result, those acquisition opportunitiesmay not be available to us. So long as the members of the Sponsor Group, or other funds controlled by or associated with themembers of the Sponsor Group, continue to indirectly own, in the aggregate, a significant amount of the outstanding shares ofEFH Corp.'s common stock, even if such amount is less than 50%, the Sponsor Group will continue to be able to strongly influenceor effectively control our decisions.32 Table of ContentsItem lB. UNRESOLVED STAFF COMMENTSNone.Item 3. LEGAL PROCEEDINGSSee Items I and 2, "Business and Properties -Environmental Regulations and Related Considerations -Sulfur Dioxide,Nitrogen Oxide and Mercury Air Emissions" for discussion of litigation regarding the CSAPR and the Texas State ImplementationPlan as well as certain other environmental regulations.Litigation Related to Generation FacilitiesIn November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak GroveManagement Company LLC's (Oak Grove) (a wholly-owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System(TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in theTravis County, Texas District Court. Plaintiffs sought a reversal of the TCEQ's order and a remand back to the TCEQ for furtherproceedings. Oral argument was held in this administrative appeal on October 23, 2012, and the court affirmed the TCEQ'sissuance of the TPDES permit to Oak Grove. In December 2012, plaintiffs appealed the district court's decision to the Third Courtof Appeals in Austin, Texas. While we cannot predict the timing or outcome of this proceeding, we believe the renewal andamendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (TexarkanaDivision) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violationsof the Clean Air Act (CAA) at Luminant's Martin Lake generation facility. In May 2012, the Sierra Club filed a lawsuit in the USDistrict Court for the Western District of Texas (Waco Division) against EFH Corp. and Luminant Generation Company LLC foralleged violations of the CAA at Luminant's Big Brown generation facility. The Big Brown and Martin Lake cases are currentlyscheduled for trial in November 2013. While we are unable to estimate any possible loss or predict the outcome, we believe thatthe Sierra Club's claims are without merit, and we intend to vigorously defend these lawsuits. In addition, in December 2010 andagain in October 2011, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating CAA provisions inconnection with Luminant's Monticello generation facility. In May 2012, the Sierra Club informed us that it may sue us forallegedly violating CAA provisions in connection with Luminant's Sandow 4 generation facility. While we cannot predict whetherthe Sierra Club will actually file suit regarding Monticello or Sandow 4 or the outcome of any resulting proceedings, we believewe have complied with the requirements of the CAA at all of our generation facilities.Regulatory ReviewsIn June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of theCAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, includingNew Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generationfacilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received alarge and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently receiveda notice of violation from the EPA, which has in some cases progressed to litigation or settlement. In July 2012, the EPA sent usa notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our MartinLake and Big Brown generation facilities. While we cannot predict whether the EPA will initiate enforcement proceedings underthe notice of violation, we believe that we have complied with all requirements of the CAA at all of our generation facilities. Wecannot predict the outcome of any resulting enforcement proceedings or estimate the penalties that might be assessed in connectionwith any such proceedings. In September 2012, we filed a petition for review in the United States Court of Appeals for the FifthCircuit Court seeking judicial review of the EPA's notice of violation. Given recent legal precedent subjecting agency orders likethe notice of violation to judicial review, we filed the petition for review to preserve our ability to challenge the EPA's issuanceof the notice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December 2012, the Fifth CircuitCourt issued an order that will delay a ruling on the EPA's motion to dismiss until after the case has been fully briefed and oralargument, if any, is held. We cannot predict the outcome of these proceedings.Other MattersWe are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutionsof which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity orfinancial condition.33 Table of ContentsItem 4. MINE SAFETY DISCLOSURESWe currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities.These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safetyand Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RRC andOffice of Surface Mining. The MSHA inspects US mines, including ours, on a regular basis, and if it believes a violation of theMine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompaniedby a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction ofthe severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders andproposed assessments are provided in Exhibit 95(a) to this annual report on Form 10-K.34 Table of ContentsPART 11Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIESNot applicable. All of EFCH's common stock is owned by EFH Corp.See Note 10 to Financial Statements for a description of the restrictions on EFCH's ability to pay dividends.35 Table of ContentsItem 6. SELECTED FINANCIAL DATAEFCH AND SUBSIDIARIESSELECTED CONSOLIDATED FINANCIAL DATA(millions of dollars, except ratios)Operating revenuesImpairment of goodwillNet income (loss)Ratio of earnings to fixed charges (a)Cash provided by (used in) operating activitiesCash provided by (used in) financing activitiesCash provided by (used in) investing activitiesCapital expenditures, including nuclear fuelTotal assetsProperty, plant & equipment -netGoodwill and intangible assetsCapitalizationLong-term debt, less amounts due currentlyEFCH shareholder's equityNoncontrolling interests in subsidiariesTotalCapitalization ratiosLong-term debt, less amounts due currentlyEFCH shareholder's equityNoncontrolling interests in subsidiariesTotalShort-term borrowingsLong-term debt due currentlyYear Ended December 31,2012 2011 2010 2009 2008$ 5,636 $ 7,040 $ 8,235 $ 7,911 $ 9,787$ (1,200) $ -$ (4,100) $ (70) $ (8,000)$ (3,008) $ (1,802) $ (3,530) $ 515 $ (9,039)---1.36 -$ (240) S 1,236 $ 1,257 $ 1,384 $ 1,657$ 1,161 $ (973) $ 27 $ 279 $ 1,289$ 134 $ (190) $ (1,338) $ (2,048) $ (2,682)$ (844) $ (662) $ (902) $ (1,521) $ (2,074)At December 31,2012 2011 2010 2009 2008$ 32,973 $ 37,340 $ 39,144 $ 43,245 $ 43,000$ 18,556 $ 19,218 $ 20,155 $ 20,980 $ 20,902$ 6,733 $ 7,978 $ 8,523 $ 12,845 $ 13,096$ 30,310 S 30,458 $ 29,4741 $ 32,121 $ 31,556(10,506) (7,819) (6,236) (4,266) (5,002)112 103 87 48 -$ 19,916 S 22,742 $ 23,325 $ 27,903 $ 26,554152.2 % 133.9% 126.4% 115.1% 118.8 %(52.8)% (34.4)% (26.7)% (15.3)% (18.8)%0.6% 0.5 % 0.3 % 0.2% -%100.0 % 100.0 % 100.0 % 100.0 % 100.0 %$ 2,136 $ 774 $ 1,221 $ 953 $ 900$ 96 S 39 $ 658 $ 302 $ 269(a) Fixed charges exceeded earnings (see Exhibit 12(a)) by $3.932 billion, $2.745 billion, $3.212 billion and $9.543 billion forthe years ended December 31, 2012, 2011, 2010 and 2008, respectively.36 Table of ContentsNote: See Note I to Financial Statements "Basis of Presentation." Results for 2010 reflect the prospective adoption of amendedguidance regarding consolidation accounting standards related to variable interest entities and amended guidance regardingtransfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a saleof accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 7 to FinancialStatements. Results for 2012 were significantly impacted by a goodwill impairment charge as discussed in Note 3 to FinancialStatements. Results for 2011 were significantly impacted by an impairment charge related to emissions allowance intangibleassets as discussed in Note 3 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairmentcharge as discussed in Note 3 to Financial Statements and debt extinguishment gains as discussed in Note 6 to Financial Statements.Results for 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowancesintangible assets and natural gas-fueled generation facilities.See Notes to Financial Statements.Quarterly Information (Unaudited)Results of operations by quarter are summarized below. In our opinion, all adjustments (consisting of normal recurringaccruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a fullyear's operations because of seasonal and other factors. All amounts are in millions of dollars and may not add to full year amountsdue to rounding.First Second Third FourthQuarter Quarter Quarter Quarter (a)2012:Operating revenues $ 1,222 $ 1,385 $ 1,752 $ 1,278Net loss $ (253) $ (661) $ (385) $ (1,710)First Second Third FourthQuarter Quarter Quarter (b) Quarter2011:Operating revenues $ 1,672 $ 1,679 $ 2,321 $ 1,368Net loss $ (315) $ (667) $ (724) $ (96)(a) Net loss includes the effect of a goodwill impairment charge (see Note 3 to Financial Statements).(b) Net loss includes the effect of an impairment charge related to emissions allowance intangible assets (see Note 3 to FinancialStatements).37 Table of ContentsItem 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONSThe following discussion and analysis of our financial condition and results of operations for the years ended December 31,2012, 2011 and 2010 should be read in conjunction with Selected Consolidated Financial Data and our audited consolidatedfinancial statements and the notes to those statements.All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwiseindicated.BusinessEFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. We conduct our operationsalmost entirely through our wholly-owned subsidiary, TCEH. TCEH is a holding company for subsidiaries engaged in competitiveelectricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodityrisk management and trading activities and retail electricity sales. Key management activities, including commodity riskmanagement and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently,there are no reportable business segments.Significant Activities and Events and Items Influencing Future PerformanceNatural Gas Price Hedging Program and Other Hedging Activities -Because wholesale electricity prices in ERCOThave generally moved with natural gas prices, TCEH has a natural gas price hedging program designed to mitigate the effect ofnatural gas price changes on future electricity revenues. Under the program, we have entered into market transactions involvingnatural gas-related financial instruments, and at December 31, 2012, have effectively sold forward approximately 360 millionMMBtu of natural gas (equivalent to the natural gas exposure of approximately 42,000 GWh at an assumed 8.5 market heat rate)at weighted average annual hedge prices as shown in the table below. Volumes and hedge values associated with the natural gasprice hedging program are inclusive of offsetting purchases entered into to take into account new wholesale and retail electricitysales contracts and avoid over-hedging. This activity results in both commodity contract asset and liability balances pending thematurity and settlement of the offsetting transactions.Taking together forward wholesale and retail electricity sales with the natural gas positions in the hedging program, we haveeffectively hedged an estimated 96% and 41% of the price exposure, on a natural gas equivalent basis, related to TCEH's expectedgeneration output for 2013 and 2014, respectively (assuming an 8.5 market heat rate). The natural gas positions were entered intowith the continuing expectation that wholesale electricity prices in ERCOT will generally move with prices of natural gas, whichwe expect to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOTmarket. If the relationship changes in the future, the cash flows targeted under the natural gas price hedging program may not beachieved.The company has entered into related put and call transactions (referred to as collars), primarily for 2014, that effectivelyhedge natural gas prices within a range. These transactions represented 42% of the positions in the natural gas price hedgingprogram at December 31, 2012, with the approximate weighted average strike prices under the collars being a floor of $7.80 perMMBtu and a ceiling of $11.75 per MMBtu.38 Table of ContentsThe following table summarizes the natural gas positions in the hedging program at December 31, 2012:Measure 2013 2014 TotalNatural gas hedge volumes (a) mm MMBtu -211 -146 -357Weighted average hedge price (b) $/MMBtu -6.89 -7.80 -Average market price (c) $/MMBtu -3.54 -4.03Realization of hedge gains (d) $ billions -$1.0 -$0.6 -$1.6(a) Where collars are reflected, the volumes are based on the notional position of the derivatives to represent protection againstdownward price movements. The notional volumes for collars are approximately 150 million MMBtu, which correspondsto a delta position of approximately 146 million MMBtu in 2014.(b) Weighted average hedge prices are based on prices of positions in the natural gas price hedging program (excluding offsettingpurchases to avoid over-hedging). Where collars are reflected, sales price represents the collar floor price.(c) Based on NYMEX Henry Hub prices.(d) Based on cumulative unrealized mark-to-market gain at December 31, 2012.Changes in the fair value of the instruments in the natural gas price hedging program are recorded as unrealized gains andlosses in net gain from commodity hedging and trading activities in the statement of income, which has and could continue toresult in significant volatility in reported net income. Based on the size of the natural gas price hedging program at December 31,2012, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately$360 million in pretax unrealized mark-to-market gains or losses.The natural gas price hedging program has resulted in reported net gains (losses) as follows:Year Ended December 31,2012 2011 2010Realized net gain $ 1,833 $ 1,265 $ 1,151Unrealized net gain (loss) including reversals of previously recordedamounts related to positions settled (1,540) (19) 1,165Total S 293 $ 1,246 $ 2,316The cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging program totaled$1.584 billion and $3.124 billion at December 31, 2012 and 2011, respectively. The decline was driven by settlement of maturingpositions.Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains orlosses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in the future. If naturalgas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negativeeffect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices ofthe hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricityprices and will in this context be viewed as having resulted in an opportunity cost.The significant cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging programreflects the sustained decline in forward market natural gas prices as presented in "Key Risks and Challenges" below. Forwardnatural gas prices have generally trended downward over the past several years. While the natural gas price hedging program isdesigned to mitigate the effect on earnings of low wholesale electricity prices, depressed forward natural gas prices are challengingto our liquidity and the long-term profitability of our business. Specifically, low natural gas prices and their effect in ERCOT onwholesale electricity prices could have a material impact on our liquidity and TCEH's overall profitability for periods in whichTCEH does not have significant hedge positions. See Note 1 to Financial Statements.Also see Note 3 to Financial Statements for discussion regarding goodwill impairment charges recorded in 2012 and 2010.39 Table of ContentsTCEH Interest Rate Swap Transactions -TCEH employs interest rate swaps to hedge exposure to its variable rate debt.As reflected in the table below, at December 31,2012, TCEH has entered into the following series of interest rate swap transactionsthat effectively fix the interest rates at between 5.5% and 9.3%.Fixed Rates Expiration Dates Notional Amount5.5% -9.3% February 2013 through October 2014 $18.46 billion (a)6.8% -9.0% October 2015 through October 2017 $12.60 billion (b)(a) Swaps related to an aggregate $2.6 billion principal amount of debt expired in 2012. Per the terms of the transactions, thenotional amount of swaps entered into in 2011 grew by $2.405 billion, substantially offsetting the expired swaps.(b) These swaps are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes$3 billion that expires in October 2015 with the remainder expiring in October 2017.We may enter into additional interest rate hedges from time to time.TCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achievedthrough the interest rate swaps. Basis swaps in effect at December 31, 2012 totaled $11.967 billion notional amount, a decreaseof $5.783 billion from December 31, 2011 reflecting both new and expired swaps. The basis swaps relate to debt outstandingthrough 2014.The interest rate swaps have resulted in net losses reported in interest expense and related charges as follows:Year Ended December 31,2012 2011 2010Realized net loss $ (670) $ (684) $ (673)Unrealized net gain (loss) 166 (812) (207)Total $ (504) $ (1,496) $ (880)The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.065 billion and$2.231 billion at December 31, 2012 and 2011, respectively, of which $65 million and $76 million (both pretax), respectively,were reported in accumulated other comprehensive income. These fair values can change materially as market conditions change,which could result in significant volatility in reported net income. For example, at December 31, 2012, a one percent change ininterest rates would result in an increase or decrease of approximately $675 million in our cumulative unrealized mark-to-marketnet liability.First-Lien Security for Natural Gas Hedging Program and Interest Rate Swaps -Approximately 85% of the positionsin the natural gas price hedging program and all of the TCEH interest rate swaps are secured by a first-lien interest in the assetsof TCEH on a pari passu basis with the TCEH Senior Secured Facilities. Certain entities are counterparties to both our naturalgas hedge program positions and our interest rate swaps and have entered into master agreements that provide for netting andsetoff of amounts related to these positions. At December 31, 2012, our net liability positions related to these counterpartiestogether with liability positions related to entities that are counterparties to only our interest rate swaps totaled approximately $1.2billion. This amount is not expected to change materially through 2013 assuming market values do not change significantly.40 Table of ContentsPension Plan Actions -In August 2012, EFH Corp. approved certain amendments to its pension plan (see Note 13 toFinancial Statements). These actions were completed in the fourth quarter 2012, and the amendments resulted in:" splitting off assets and liabilities under the plan associated with employees of Oncor and all retirees and terminated vestedparticipants of EFH Corp. and its subsidiaries (including discontinued businesses) to a new plan sponsored andadministered by Oncor (the Oncor Plan);" splitting off assets and liabilities under the plan associated with active employees of EFH Corp.'s competitive businesses,other than collective bargaining unit (union) employees, to a Terminating Plan, freezing benefits and vesting all accruedplan benefits for these participants;* the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities under the TerminatingPlan, and* maintaining assets and liabilities under the plan associated with union employees of EFH Corp.'s competitive businessesunder the current plan.Settlement of the Terminating Plan obligations and the full funding of the EFH Corp. competitive operations portion ofliabilities (including discontinued businesses) under the Oncor Plan resulted in an aggregate cash contribution by EFH Corp.'scompetitive operations of $259 million in the fourth quarter 2012.EFH Corp.'s competitive operations recorded charges totaling $285 million in the fourth quarter 2012, including $92 millionrelated to the settlement of the Terminating Plan and $193 million related to the competitive business obligations (includingdiscontinued businesses) that are being assumed under the Oncor Plan. These amounts represent the previously unrecognizedactuarial losses reported in EFH Corp.'s accumulated other comprehensive income (loss). TCEH's allocated share of these chargestotaled $141 million. TCEH settled $91 million of this allocation with EFH Corp. in 2012 and expects to settle the remaining $50million with EFH Corp. in the first quarter 2013.Impairment of Goodwill -In 2012 and 2010, we recorded $1.2 billion and $4.1 billion, respectively, noncash goodwillimpairment charges (which were not deductible for income tax purposes). The write-offs reflected the estimated effect of lowerwholesale power prices on TCEH's enterprise value, driven by the sustained decline in forward natural gas prices as discussedabove. Recorded goodwill totaled $4.95 billion at December 31, 2012.The noncash impairment charge did not cause EFCH or its subsidiaries to be in default under any of their respective debtcovenants or impact counterparty trading agreements or have a material impact on liquidity.See Note 3 to Financial Statements and "Application ofCritical Accounting Policies" below formore information on goodwillimpairment testing and charges.Liability Management Program -At December 31, 2012, we had $30.5 billion principal amount of long-term debtoutstanding, including $450 million pushed down from EFH Corp. We and EFH Corp. have implemented a liability managementprogram designed to reduce debt, capture debt discount and extend debt maturities through debt exchanges, repurchases andextensions.Amendments to the TCEH Senior Secured Facilities completed in April 2011 and January 2013 resulted in the extension of$16.4 billion in loan maturities under the TCEH Term Loan Facilities and the TCEH Letter of Credit Facility from October 2014to October 2017 and $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October2016.41 Table of ContentsOther liability management activities since 2009 related to TCEH debt include debt exchange, issuance and repurchaseactivities as follows (all transactions occurred prior to 2012):Debt Debt Issued/Security (except where noted, debt amounts are principal amounts) Acquired Cash PaidTCEH 10.25% Notes due 2015 $ 1,513 $TCEH Toggle Notes due 2016 758TCEH Senior Secured Facilities due 2013 and 2014 1,604 -TCEH 15% Notes due 2021 -1,221TCEH 11.5% Notes due 2020 (a) 1,604Cash paid, including use of proceeds from debt issuances in 2010 (b) -- 343Total $ 3,875 $ 3,168(a) Excludes from the $1.750 billion principal amount $12 million in debt discount and $134 million in proceeds used fortransaction costs related to the issuance of these notes and the amendment and extension of the TCEH Senior SecuredFacilities. All other proceeds were used to repay borrowings under the TCEH Senior Secured Facilities, and the remainingtransaction costs were funded with cash on hand.(b) Includes $343 million of the proceeds from the October 2010 issuance of $350 million principal amount of TCEH 15%Senior Secured Second Lien Notes due 2021 that were used to repurchase debt, including $53 million used to repurchasedebt held by EFH Corp.Since inception, TCEH's transactions in the liability management program resulted in the capture of approximately $700million of debt discount and the extension of approximately $19.6 billion of debt maturities to 2017-2021.As the result of EFH Corp. and EFIH liability management transactions in December 2012 and early 2013, substantially allEFH Corp. debt guaranteed by EFCH was cancelled or amended to remove EFCH's guarantee, such that EFCH now guaranteesonly $60 million principal amount of EFH Corp. debt (see Note 8 to Financial Statements).EFH Corp., EFCH and TCEH continue to consider and evaluate possible transactions and initiatives to address their highlyleveraged balance sheets and significant cash interest requirements and may from time to time enter into discussions with theirlenders and bondholders with respect to such transactions and initiatives. These transactions and initiatives may include, amongothers, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equity exchangesor conversions, including exchanges or conversions of debt of EFCH and TCEH into equity of EFH Corp., EFCH, TCEH and/orany of their subsidiaries.In evaluating whether to undertake any liability management transaction, we will take into account liquidity requirements,prospects for future access to capital, contractual restrictions, tax consequences, the market price and maturity dates of ouroutstanding debt, potential transaction costs and other factors. Any liability management transaction, including any refinancingor extension, may occur on a stand-alone basis or in connection with, or immediately following, other liability managementtransactions.Also see "Key Risks and Challenges -Substantial Leverage, Uncertain Financial Markets and Liquidity Risk" and Notes Iand 8 to Financial Statements.Global Climate Change and Other EnvironmentalMatters -See Items 1 and 2 "Business and Properties -EnvironmentalRegulations and Related Considerations" for discussion of global climate change, recent and anticipated EPA actions and variousother environmental matters and their effects on the company.42 Table of ContentsWholesale Market Design -Nodal Market -In accordance with a rule adopted by the PUCT in 2003, ERCOT developeda new wholesale market, using a stakeholder process, designed to assign congestion costs to the market participants causing thecongestion. The nodal market design was implemented December 1, 2010. Under this new market design, ERCOT:" establishes nodes, which are metered locations across the ERCOT grid, for purposes ofmore granular price determination;" operates a voluntary "day-ahead electricity market" for forward sales and purchases of electricity and other relatedtransactions, in addition to the existing "real-time market" that primarily functions to balance power consumption andgeneration;* establishes hub trading prices, which represent the average of certain node prices within four major geographic regions,at which participants can hedge or trade power under bilateral contracts;" establishes pricing for load-serving entities based on weighted-average node prices within new geographical load zones,and" provides congestion revenue rights, which are instruments auctioned by ERCOT that allow market participants to hedgeprice differences between settlement points.ERCOT previously had a zonal wholesale market structure consisting of four geographic zones. The new location-basedcongestion-management market is referred to as a "nodal" market because wholesale pricing differs across the various nodes onthe transmission grid instead of across the geographic zones. There are over 550 nodes in the ERCOT market. The nodal marketdesign was implemented in conjunction with transmission improvements designed to reduce current congestion. We are certifiedto participate in both the "day-ahead" and "real-time markets." Additionally, all of our operational generation assets and ourqualified scheduling entities are certified and operate in the nodal market. Since the opening of the nodal market, the amount ofletters of credit posted with ERCOT to support our market participation has fluctuated between $110 million and $420 millionbased upon weekly settlement activity, and at December 31, 2012, totaled $190 million.As discussed above, the nodal market design includes the establishment of a "day-ahead market" and hub trading prices tofacilitate hedging and trading of electricity by participants. Under the previous zonal market, volumes under our nontradingbilateral purchase and sales contracts, including contracts intended as hedges, were scheduled as physical power with ERCOTand, therefore, reported gross as wholesale revenues or purchased power costs. In conjunction with the transition to the nodalmarket, unless the volumes represent physical deliveries to retail and wholesale customers or purchases from counterparties, thesecontracts are reported on a net basis in the income statement in net gain from commodity hedging and trading activities. As aresult of these changes, reported wholesale revenues and purchased power costs (and the associated volumes) in 2012 and 2011were materially less than amounts reported in prior periods.Recent PUCT/ERCOT Actions -In response to ERCOT's publication of reports (known as the Capacity, Demand, andReserves report and the Seasonal Assessment of Resource Adequacy report) showing declining reserve margins in the ERCOTmarket, the PUCT and the ERCOT Board of Directors took action to implement or approve in 2012 several changes to ERCOTprotocols designed to establish minimum offer floors for wholesale power offers during deployment of certain reliability-relatedservices, including non-spinning reserve, responsive reserve, reliability unit commitment, and other services. In addition, in Juneand October 2012 the PUCT approved rules that, among other things, increased the system-wide offer cap that applies to wholesalepower offers in ERCOT from its previous level of $3,000 per MWh to $4,500 per MWh effective August 1, 2012, and increasedthe cap to $5,000, $7,000, and $9,000 per MWh in the summers of 2013, 2014, and 2015, respectively, for the stated purpose ofsending appropriate price signals to encourage development of generation resources in ERCOT. Also in June 2012, the BrattleGroup, an independent consultant engaged by ERCOT to assess the incentives for generation investment in the ERCOT market,issued a report on potential next steps for addressing generation resource adequacy. The Brattle report discusses a range of potentialsolutions that could promote resource adequacy in the ERCOT market, ranging from enhancing the current energy-only structurein the ERCOT market to creating a capacity market structure, whereby generators receive capacity payments to ensure availablegeneration in the market and provide a return on the generator's investment, similar to those used in certain other competitivemarkets in the US. The Brattle report concluded that, even if the wholesale energy offer cap were increased to $9,000 per MWh,the expected corresponding reserve margin that would be obtained in the current energy-only market design would be approximately10%. ERCOT's current target reserve margin is 13.75%. Discussions are ongoing among ERCOT, the PUCT, market participantsand other stakeholders regarding the range of solutions presented in the Brattle report and the actions necessary to continueproviding reliable electricity supply in ERCOT.43 Table of ContentsSeasonalSuspension of Certain Generation Operations-- In October 2012, ERCOT approved our filing of notice of intentto suspend operations at two of the three generation units at our Monticello generation facility due to low wholesale power pricesand other market conditions. Beginning December 1, 2012, we suspended operations for approximately six months, with bothunits expected to return to service during the peak demand months in the summer of 2013. Our mines that support the Monticellogeneration facility will continue year round operations. Based on cash flow projections and related analysis, no asset impairmentwas recorded as a result of the suspension. At current wholesale market prices of electricity, we do not expect the suspension ofoperations to significantly impact our results of operations, liquidity or financial condition.Natural Gas-Fueled Generation Development -In December 2012, Luminant filed a permit application with the TCEQto build two natural gas combustion turbines totaling 420 MW at its existing DeCordova generation facility. While current marketconditions do not provide adequate economic returns for the development or construction of new generation, we believe additionalgeneration resources will be needed to support continued electricity demand growth and reliability in the ERCOT market. See"Recent PUCT/ERCOT Actions" above for discussion of actions by the PUCT and ERCOT to encourage development of newgeneration resources.Settlement ofMake-WholeAgreements with Oncor- See Note 15 to Financial Statements for discussion of the settlementin the third quarter 2012 of our interest and tax-related reimbursement agreements with Oncor associated with Oncor's bankruptcy-remote financing subsidiary's securitization bonds.Sunset Review -Sunset review is the regular assessment of the continuing need for a state agency to exist, and is groundedin the premise that an agency will be abolished unless legislation is passed to continue its functions. On a specified time schedule,the Texas Sunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agencyto the Texas Legislature, which action may include modifying or even abolishing the agency. The PUCT and the RRC are subjectto review by the Sunset Commission in 2013. In 2011, the Texas Legislature extended the authority of the RRC and the PUCTuntil 2013. In 2013, the RRC will undergo a full sunset review, and the PUCT will undergo a limited sunset review. We cannotpredict the outcome of the sunset review process.Summary -We cannot predict future regulatory or legislative actions or any changes in economic and securities marketconditions. Such actions or changes could significantly affect our results of operations, liquidity or financial condition.44 Table of ContentsKEY RISKS AND CHALLENGESFollowing is a discussion of key risks and challenges facing management and the initiatives currently underway to managesuch challenges. These matters involve risks that could have a material effect on our results of operations, liquidity or financialcondition. Also see Item IA, "Risk Factors."Substantial Leverage, Uncertain Financial Markets and Liquidity RiskOur substantial leverage, resulting in large part from debt incurred to finance the Merger, and the covenants contained in ourdebt agreements require significant cash flows to be dedicated to interest and principal payments and could adversely affect ourability to raise additional capital to fund operations and limit our ability to react to changes in the economy, our industry (includingenvironmental regulations) or our business. Principal amounts of short-term borrowings and long-term debt, including amountsdue currently, totaled $32.7 billion at December 31, 2012, and cash interest payments in 2012 totaled $2.6 billion.Significant amounts of our long-term debt mature in the next few years, including approximate principal amounts of $80million in 2013, $3.9 billion in 2014 and $3.7 billion in 2015. A substantial amount of our debt is comprised of debt incurredunder the TCEH Senior Secured Facilities. In April 2011, we secured an extension of the maturity date of approximately $16.4billion principal amount of debt under these facilities to 2017, and in April 2011 and January 2013, we secured the extension ofthe entire $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016.Notwithstanding the extension, the maturity could be reset to an earlier date under a "springing maturity" provision if, as of adefined date, certain amounts of TCEH unsecured debt maturing prior to 2017 are not refinanced and TCEH's debt to AdjustedEBITDA ratio exceeds 6.00 to 1.00. In addition, the agreement covering the TCEH Senior Secured Facilities includes a secureddebt to Adjusted EBITDA financial maintenance covenant and a covenant requiring TCEH to timely deliver to the lenders auditedannual financial statements that are not qualified as to the status of TCEH and its consolidated subsidiaries as a going concern(see "Financial Condition -Liquidity and Capital Resources -Financial Covenants, Credit Rating Provisions and Cross DefaultProvisions" and Notes 1 and 8 to Financial Statements).In consideration of our substantial leverage, there can be no assurance that counterparties to our credit facility and hedgingarrangements will perform as expected and meet their obligations to us. Failure of such counterparties to meet their obligationsor substantial changes in financial markets, the economy, regulatory requirements, our industry or our operations could result inconstraints in our liquidity. While traditional counterparties with physical assets to hedge, as well as financial institutions andother parties, continue to participate in the markets, low natural gas and wholesale electricity prices, continued market and regulatoryuncertainty and our liquidity and upcoming debt maturities have limited our hedging and trading activities, particularly for longer-dated transactions, which could impact our ability to hedge our commodity price and interest rate exposure to desired levels atreasonable costs. See discussion of credit risk in Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," discussionof available liquidity and liquidity effects of the natural gas price hedging program in "Financial Condition -Liquidity and CapitalResources" and discussion of potential impacts of legislative rulemakings on the OTC derivatives market below in "FinancialServices Reform Legislation."In addition, because our operations are capital intensive, we expect to rely over the long-term upon access to financial marketsas a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our availablecredit facilities. Our ability to economically access the capital or credit markets could be restricted at a time when we would like,or need, to access those markets. Lack of such access could have an impact on our flexibility to react to changing economic andbusiness conditions.Further, a continuation, or further decline, of current forward natural gas prices could result in further declines in the valuesof TCEH's nuclear and lignite/coal-fueled generation assets and limit or hinder TCEH's ability to hedge its wholesale electricityrevenues at sufficient price levels to support its significant interest payments and debt maturities, which could adversely impactTCEH's ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt. See discussionabove under "Significant Activities and Events and Items Influencing Future Performance -Natural Gas Price Hedging Programand Other Hedging Activities."45 Table of ContentsAt December 31, 2012, TCEH had $1.2 billion of cash and cash equivalents and $183 million of available capacity underits letter of credit facility. In January 2013, TCEH's liquidity increased by approximately $700 million as a result of the settlementof the TCEH Demand Notes by EFH Corp. Based on the current forecast of cash from operating activities, which reflects currentforward market electricity prices, projected capital expenditures and other cash flows, we expect that TCEH will have sufficientliquidity to meets its obligations until October 2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures.TCEH's ability to satisfy this obligation is dependent upon the implementation of one or more of the actions described immediatelybelow.EFH Corp., EFCH and TCEH continue to consider and evaluate possible transactions and initiatives to address their highlyleveraged balance sheets and significant cash interest requirements and may from time to time enter into discussions with theirlenders and bondholders with respect to such transactions and initiatives. Progress to date includes the debt extensions, exchanges,issuances and repurchases completed in 2010 and 2011, which resulted in the capture of $700 million of debt discount and theextension of approximately $19.6 billion of debt maturities to 2017-202 1. Future transactions and initiatives may include, amongothers, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equity exchangesor conversions, including exchanges or conversions of debt of EFCH and TCEH into equity of EFH Corp., EFCH, TCEH and/orany of their subsidiaries. These actions could result in holders of TCEH debt instruments not recovering the full principal amountof those obligations. We have also hedged a substantial portion of variable rate debt exposure through 2017 using interest rateswaps. See "Significant Activities and Events and Items Influencing Future Performance -Liability Management Program" andNote 8 to Financial Statements.Natural Gas Price and Market Heat Rate ExposureWholesale electricity prices in the ERCOT market have historically moved with the price of natural gas because marginaldemand for electricity supply is generally met with natural gas-fueled generation facilities. The price of natural gas has fluctuateddue to changes in industrial demand, supply availability and other economic and market factors, and such prices have historicallybeen volatile. As shown in the table below, forward natural gas prices have generally trended downward in recent years, reflectingdiscovery and increased drilling of shale gas deposits combined with lingering demand weakness associated with the economicdownturn.Forward Market Prices for Calendar Year ($/MMBtu) (a)Date 2013 2014 2015 2016December 31, 2008 $ 7.15 $ 7.15 $ 7.21 $ 7.30March 31,2009 $ 7.11 $ 7.18 $ 7.25 $ 7.33June 30, 2009 $ 7.30 $ 7.43 $ 7.57 $ 7.71September 30, 2009 $ 7.06 $ 7.17 $ 7.31 $ 7.43December 31,2009 $ 6.67 $ 6.84 $ 7.05 $ 7.24March 31, 2010 $ 6.07 $ 6.36 $ 6.68 $ 7.00June 30, 2010 $ 5.89 $ 6.10 $ 6.37 $ 6.68September 30, 2010 $ 5.29 $ 5.42 $ 5.60 $ 5.76December 31, 2010 $ 5.33 $ 5.49 $ 5.64 $ 5.79March31, 2011 $ 5.41 $ 5.73 $ 6.08 $ 6.41June 30, 2011 $ 5.16 $ 5.42 $ 5.70 $ 5.98September 30, 2011 $ 4.80 $ 5.13 $ 5.39 $ 5.61December 31, 2011 $ 3.94 $ 4.34 $ 4.60 $ 4.85March 31, 2012 $ 3.47 $ 3.96 $ 4.26 $ 4.51June 30, 2012 $ 3.58 $ 3.95 $ 4.13 $ 4.29September 30, 2012 $ 3.84 $ 4.18 $ 4.37 $ 4.55December 31, 2012 $ 3.54 $ 4.03 $ 4.23 $ 4.42(a) Based on NYMEX Henry Hub prices.In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the costof generating electricity from our nuclear and lignite/coal-fueled facilities. All other factors being equal, these nuclear and lignite/coal-fueled generation assets, which provided the substantial majority of supply volumes in 2012, increase or decrease in valueas natural gas prices and market heat rates rise or fall, respectively, because of the effect on wholesale electricity prices in ERCOT.46 Table of ContentsThe wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Marketheat rate movements also affect wholesale electricity prices. Market heat rate can be affected by a number of factors includinggeneration resource availability and the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) ingenerating electricity. While market heat rates have generally increased as natural gas prices have declined, wholesale electricityprices have declined due to the greater effect of falling natural gas prices.Our market heat rate exposure is impacted by changes in the availability, such as additions and retirements of generationfacilities, and mix of generation assets in ERCOT. For example, increased wind generation capacity could result in lower marketheat rates. We expect that decreases in market heat rates would decrease the value of our generation assets because lower marketheat rates generally result in lower wholesale electricity prices, and vice versa.With the exposure to variability of natural gas prices and market heat rates in ERCOT, retail sales price management andhedging activities are critical to the profitability of the business and maintaining consistent cash flow levels.Our approach to managing electricity price risk focuses on the following:" employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts intended to partially hedge gross margins;" continuing focus on cost management to better withstand gross margin volatility;" following a retail pricing strategy that appropriately reflects the magnitude and costs of commodity price, liquidity riskand retail load variability, and" improving retail customer service to attract and retain high-value customers.As discussed above in "Significant Activities and Events and Items Influencing Future Performance," we have implementeda natural gas price hedging program to mitigate the risk of lower wholesale electricity prices due to declines in natural gas prices.While current and forward natural gas prices are currently depressed, we continue to seek opportunities to manage our wholesalepower price exposure through hedging activities, including forward wholesale and retail electricity sales. At December 31, 2012,we have no significant hedges beyond 2014.We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term heat rate hedgingtransactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricitysales contracts where practical considering pricing, credit, liquidity and related factors.The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas andcertain other commodity prices and market heat rates on realized pretax earnings for the periods presented. The estimates relatedto price sensitivity are based on TCEH's unhedged position and forward prices at December 31,2012, which for natural gas reflectsestimates of electricity generation less amounts hedged through the natural gas price hedging program and amounts under existingwholesale and retail sales contracts. On a rolling basis, generally twelve-months, the substantial majority of retail sales undermonth-to-month arrangements are deemed to be under contract.Balance 2013 (a) 2014 2015$1.00/MMBtu change in natural gas price (b) $ -18 $ -270 $ -4800. I/MMBtu/MWh change in market heat rate (c) $ -5 $ -25 $ -35$1.00/gallon change in diesel fuel price $ -13 $ -45 $ -50(a) Balance of 2013 is from February 1,2013 through December 31, 2013.(b) Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally beingon the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gasposition is assumed to be generated).(c) Based on Houston Ship Channel natural gas prices at December 31, 2012.On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based onour desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of.overall generation and consumption (which is also subject to volatility resulting from customer chum, weather, economic andother factors) in our businesses. Portfolio balancing may include the execution of incremental transactions, including heat ratehedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricityat fixed prices. As a result, commodity price exposures and their effect on earnings could materially change from time to time.47 Table of ContentsNew and Changing Environmental RegulationsWe are subject to various environmental laws and regulations related to SO2, NOx and mercury as well as other emissionsthat impact air and water quality. We believe we are in compliance with all current laws and regulations, but regulatory authoritieshave recently adopted or proposed new rules, such as the EPA's CSAPR and MATS, which could require material capitalexpenditures if the rules take effect, and authorities continue to evaluate existing requirements and consider proposals for furtherrules changes. If we make any major modifications to our power generation facilities, we may be required to install the bestavailable control technology or to achieve the lowest achievable emission rates as such terms are defined under the new sourcereview provisions of the Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures.(See Note 9 to Financial Statements for discussion of "Litigation Related to Generation Facilities," "Regulatory Reviews" and"Environmental Contingencies." and Items I and 2 "Business and Properties -Environmental Regulations and RelatedConsiderations.")We also continue to closely monitor any potential legislative, regulatory and judicial changes pertaining to global climatechange. In view of the fact that a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities,our results of operations, liquidity or financial condition could be materially affected by the enactment of any legislation, regulationor judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities thatproduce GHG emissions, or that establishes federal renewable energy portfolio standards. For example, federal, state or regionallegislation or regulation addressing global climate change could result in us either incurring material costs to reduce our GHGemissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program.See further discussion under Items 1 and 2, "Business and Properties -Environmental Regulations and Related Considerations."Competitive Retail Markets and Customer RetentionCompetitive retail activity in Texas has resulted in retail customer chum. Our total retail customer counts declined 4% in2012, 9% in 2011 and 6% in 2010. Based upon 2012 results discussed below in "Results of Operations," a 1% decline in residentialcustomers would result in a decline in annual revenues of approximately $29 million. In responding to the competitive landscapein the ERCOT marketplace, we are focusing on the following key initiatives:" Maintaining competitive pricing initiatives on residential service plans;" Profitably growing the retail customer base by actively competing for new and existing customers in areas in Texas opento competition. The customer retention strategy remains focused on continuing to implement initiatives to deliver world-class customer service and improve the overall customer experience;* Establishing TXU Energy as the most innovative retailer in the Texas market by continuing to develop tailored productofferings to meet customer needs. Over the past five years, TXU Energy has invested $100 million in retail initiativesaimed at helping consumers conserve energy and demand-side management initiatives that are intended to moderateconsumption and reduce peak demand for electricity, and* Focusing business market initiatives largely on programs targeted to retain the existing highest-value customers and torecapture customers who have switched REPs. Initiatives include maintaining and continuously refining a disciplinedcontracting and pricing approach and economic segmentation of the business market to enhance targeted sales andmarketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improvedcustomer service, aided by an enhanced customer management system, new product price/service offerings and amultichannel approach for the small business market.Financial Services Reform LegislationIn July 2010, the US Congress enacted financial reform legislation known as the Dodd-Frank Wall Street Reform andConsumer Protection Act (the Financial Reform Act). The primary purposes of the Financial Reform Act are, among other things:to address systemic risk in the financial system; to establish a Bureau of Consumer Financial Protection with broad powers toenforce consumer protection laws and promulgate rules against unfair, deceptive or abusive practices; to enhance regulation ofthe derivatives markets, including the requirement for central clearing of over-the-counter derivative instruments and additionalcapital and margin requirements for certain derivative market participants and to implement a number ofnew corporate governancerequirements for companies with listed or, in some cases, publicly-traded securities. While the legislation is broad and detailed,a few key rulemaking decisions remain to be made by federal governmental agencies to fully implement the Financial ReformAct.48 Table of ContentsTitle VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives (Swaps) market.The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we useto hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However,under the end-user clearing exemption, entities are exempt from these clearing requirements if they (i) are not "Swap Dealers" or"Major Swap Participants" and (ii) use Swaps to hedge or mitigate commercial risk. Existing swaps are grandfathered from theclearing requirements. The legislation mandates significant compliance requirements for any entity that is determined to be aSwap Dealer or Major Swap Participant and additional reporting and recordkeeping requirements for all entities that participatein the derivative markets.In May 2012, the US Commodity Futures Trading Commission (CFTC) published its final rule defining the terms SwapDealer and Major Swap Participant. Additionally, in July 2012, the CFTC approved the final rules defining the term Swap andthe end-user clearing exemption. The definition of the term Swap and the Swap Dealer/Major Swap Participant rule becameeffective in October 2012. Accordingly, we are required to assess our activity to determine if we will be required to register as aSwap Dealer or Major Swap Participant. Based on our assessment, we are not a Swap Dealer or Major Swap Participant. InOctober 2012, the CFTC issued various no-action letters granting temporary relief from enforcement from certain aspects of thedefinition of Swap and the Swap Dealer/Major Swap Participant rule.In September 2012, the District Court for the District of Columbia issued an order that vacated and remanded to the CFTCits Position Limit Rule (PLR), which would have been effective in October 2012. The PLR provided for specific position limitsrelated to 28 Core Referenced Futures Contracts, including the NYMEX Henry Hub Natural Gas Futures Contract, the NYMEXLight Sweet Crude Oil Futures Contract and the NYMEX New York Harbor No. 2 Heating Oil Futures Contract. If the PLR hadbeen approved by the court, we would have been required to comply with the portion of the PLR applicable to the contracts notedabove, which would result in increased monitoring and reporting requirements. We cannot predict when, or in what form, theCFTC will change the PLR.The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateralrequirements are unclear as to whether an end-user or its counterparty (e.g., swap dealer) is required to post cash collateral, thereis a risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. The final rulefor margin requirements has not been issued. However, the legislative history of the Financial Reform Act suggests that it wasnot Congress' intent to require end-users to post cash collateral with respect to swaps. If we were required to post cash collateralon our swap transactions with swap dealers, our liquidity would likely be materially impacted, and our ability to enter into OTCderivatives to hedge our commodity and interest rate risks would be significantly limited.We cannot predict the outcome of the final rulemakings to implement the OTC derivative market provisions of the FinancialReform Act. Based on our assessment and published guidance from the CFTC, we believe our historical practices related to ouruse of Swaps does not qualify us as a Swap Dealer or Major Swap Participant, and we believe we will be able to take advantageof the End-User Exemption for Swaps that hedge or mitigate commercial risk; however, the remaining rulemakings related to howSwap Dealers and other market participants administer margin requirements could negatively affect our ability to hedge ourcommodity and interest rate risks. Accordingly, we (and other market participants) continue to closely monitor the rulemakingsand any other potential legislative and regulatory changes and work with regulators and legislators. We have provided theminformation on our operations, the types of transactions in which we engage, our concerns regarding potential regulatory impacts,market characteristics and related matters.Exposures Related to Nuclear Asset OutagesOur nuclear assets are comprised of two generation units at the Comanche Peak plant site, each with an installed nameplatecapacity of 1,150 MW. These units represent approximately 15% of our total generation capacity. The nuclear generation unitsrepresent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, theunfavorable impact to pretax earnings is estimated (based upon forward electricity market prices for 2013 at December 31, 2012)to be approximately $1.5 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilitiesinsurance in Note 9 to Financial Statements.49 Table of ContentsThe inherent complexities and related regulations associated with operating nuclear generation facilities result inenvironmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review andregulation by the NRC, including potential regulation as a result of the NRC's ongoing analysis and response to the effects of thenatural disaster on nuclear generation facilities in Japan in 2010, covering, among other things, operations, maintenance, emergencyplanning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increasedcapital or operating costs, and it may require extended outages, modify, suspend or revoke operating licenses and impose finesfor failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outageat another nuclear generation facility could result in the NRC taking action to shut down the Comanche Peak units as a precautionarymeasure.We participate in industry groups and with regulators to remain current on the latest developments in nuclear safety, operationand maintenance and on emerging threats and mitigating techniques. These groups include, but are not limited to, the NRC andthe Institute of Nuclear Power Operations (INPO). We also apply the knowledge gained by continuing to invest in technology,processes and services to improve our operations and detect, mitigate and protect our nuclear generation assets. The ComanchePeak plant has not experienced an extended unplanned outage, and management continues to focus on the safe, reliable and efficientoperations at the plant.Declining Reserve Margins in ERCOTPlanning reserve margin represents the percentage by which estimated system generation capacity exceeds anticipated peakload. As reflected in the table below, ERCOT is projecting reserve margins in the ERCOT market in 2013 will be below ERCOT'sminimum reserve planning criterion of 13.75% and will continue to decline. Weather extremes, unplanned generation facilityoutages and variability in wind generation all exacerbate the risks of inadequate reserve margins.2013 2014 2015 2016Firm load forecast (MW) 65,952 67,592 69,679 71,613Resources forecast (MW) 74,633 74,943 76,974 77,703Reserve margin (a) 13.2% 10.9% 10.5% 8.5%(a) Source: ERCOT's "Report on the Capacity, Demand, and Reserves in the ERCOT Region -December 2012." Reservemargin (planning) = (Resources forecast -Firm load forecast) / Firm load forecast.We and the ERCOT market broadly experienced the effects of weather extremes and reduced generation availability in 2011.Severe cold weather in North Texas caused some generation units to go off-line, including certain of our generation units, resultingin electricity outages and reduced customer satisfaction, as well as loss of revenues and higher costs as we worked to bring ourunits back on line. The unusually hot 2011 summer in Texas drove higher electricity demand that resulted in wholesale electricityprice spikes and requests to consumers to conserve energy during peak load periods, while increasing stress on generation andother electricity grid assets. Unplanned generation unit outages during periods of high electricity demand, combined withinadequate reserve margins, increase the risk of spikes in wholesale power prices and could have significant adverse effects onour results of operations, liquidity and financial condition. Other weather events such as drought that often accompanies hotweather extremes reduces cooling water levels at our generation facilities and can ultimately result in reduced output. Heavy rainspresent other challenges as flooding in other states can halt rail transportation of coal, and local flooding can reduce our lignitemining capabilities, resulting in fuel shortages and reduced generation.While there can be no assurance that we can fully mitigate the risks of severe weather events and unanticipated generationunit outages, we have emergency preparedness, business continuity and regulatory compliance policies and procedures that arecontinuously reviewed and updated to address these risks. Further, we have initiatives in place to improve monitoring of generationequipment maintenance and readiness to increase system reliability and help ensure generation availability. With the learningsfrom the winter and summer events of 2011, we have implemented new procedures and continuously evaluate plans to assure thehighest possible delivery of generation during critical periods, while supporting demand side management and utilization of smartgrid and advanced meter technology to implement ERCOT mandated rotating outages to noncritical customers. We continue towork with ERCOT and other market participants to develop policies and protocols that provide appropriate pricing signals thatencourage the development of new generation to meet growing demand in the ERCOT market. See "Significant Activities andEvents and Items Influencing Future Performance -Recent PUCT/ERCOT Actions."50 Table of ContentsCyber Security and Infrastructure Protection RiskAbreach ofcyber/data security measures that impairs our information technology infrastructure could disrupt normal businessoperations and affect our ability to control our generation assets, access retail customer information and limit communication withthird parties. Any loss of confidential or proprietary data through a breach could materially affect our reputation, expose thecompany to legal claims or impair our ability to execute on business strategies.We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques. Thesegroups include, but are not limited to, the US Cyber Emergency Response Team, the National Electric Sector Cyber SecurityOrganization, the NRC and NERC. We also apply the knowledge gained by continuing to invest in technology, processes andservices to detect, mitigate and protect our cyber assets. These investments include upgrades to network architecture, regularintrusion detection monitoring and compliance with emerging industry regulation.51 Table of ContentsAPPLICATION OF CRITICAL ACCOUNTING POLICIESOur significant accounting policies are discussed in Note I to Financial Statements. We follow accounting principlesgenerally accepted in the US. Application of these accounting policies in the preparation of our consolidated financial statementsrequires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities atthe balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain criticalaccounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported usingdifferent assumptions or estimation methodologies.Push Down of Merger-Related DebtMerger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing at the time of the Merger. Debtissued in exchange for Merger-related debt is considered Merger-related. Debt issuances are considered Merger-related debt tothe extent the proceeds are used to repurchase Merger-related debt. Merger-related debt of EFH Corp. (parent) that is fully andunconditionally guaranteed on a joint and several basis by EFCH and EFIH is subject to push down in accordance with SEC StaffAccounting Bulletin Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected in our financialstatements. Merger-related debt of EFH Corp. held by its subsidiaries is not subject to push down. The amount reflected in ourbalance sheet represents 50% of the EFH Corp. Merger-related debt guaranteed by EFCH. This percentage reflects the fact thatat the time of the Merger, the equity investments of EFCH and EFIH in their respective operating subsidiaries were essentiallyequal amounts. Because payment of principal and interest on the debt is the responsibility of EFH Corp., we record the settlementof such amounts as noncash capital contributions from EFH Corp. As a result of transactions completed by EFIH and EFH Corp.in January 2013, only $60 million principal amount of debt remains subject to push down. See Note 8 to Financial Statements.Impairment of Goodwill and Other Long-Lived AssetsWe evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accountingstandards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that theircarrying amount may not be recoverable. One of those indications is a current expectation that "more likely than not" a long-livedasset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. For our nuclear andlignite/coal-fueled generation assets, another possible indication would be an expectation of continuing long-term declines innatural gas prices and/or market heat rates. The determination of the existence of these and other indications of impairmentinvolves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flowsrelated to an asset or group of assets. Further, the unique nature of our property, plant and equipment, which includes a fleet ofgeneration assets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use ofsignificant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (wehave selected December 1) or whenever events or changes in circumstances indicate an impairment may exist, such as the triggersto evaluate impairments to long-lived assets discussed above. As required by accounting guidance related to goodwill and otherintangible assets, we have allocated goodwill to our reporting unit, which essentially consists of TCEH, and goodwill impairmenttesting is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reportingunit's carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit iscompared to the estimated fair values of the reporting unit's operating assets (including identifiable intangible assets) and liabilitiesat the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excessof the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.The determination of enterprise value involves a number of assumptions and estimates. We use a combination of fair valueinputs to estimate enterprise values of our reporting units: internal discounted cash flow analyses (income approach), andcomparable publicly traded company values (market approach). The income approach involves estimates of future performancethat reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects ofenvironmental rules, generation plant performance and retail sales volume trends, as well as determination of a terminal valueusing the Gordon Growth Model. Another key variable in the income approach is the discount rate, or weighted average cost ofcapital, applied to the forecasted cash flows. The determination of the discount rate takes into consideration the capital structure,debt ratings and current debt yields of comparable public companies as well as an estimate of return on equity that reflects historicalmarket retums and current market volatility for the industry. Enterprise value estimates based on comparable company valuesinvolve using trading multiples of EBITDA of those selected public companies to derive appropriate multiples to apply to theEBITDA of the reporting units. This approach requires an estimate, using historical acquisition data, of an appropriate controlpremium to apply to the reporting unit values calculated from such multiples. Critical judgments include the selection ofcomparablecompanies and the weighting of the value metrics in developing the best estimate of enterprise value.52 Table of ContentsSince the Merger, we have recorded goodwill impairment charges totaling $13.370 billion, including $1.2 billion recordedin 2012, $4.1 billion recorded in 2010 and $8.070 billion recorded largely in 2008. The total impairment charges representedapproximately 75% of the goodwill balance resulting from purchase accounting for the Merger. The impairments in 2012 and2010 reflected the estimated effect of lower wholesale power prices in ERCOT on the enterprise value of TCEH, driven by thesustained decline in forward natural gas prices. The impairment in 2008 primarily arose from the dislocation in the capital marketsthat increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in marketvalues of debt and equity securities of comparable companies in the second half of 2008.See Note 3 to Financial Statements for additional discussion.Derivative Instruments and Mark-to-Market AccountingWe enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivativeinstruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Underaccounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-marketaccounting, and the determination of market values for these instruments is based on numerous assumptions and estimationtechniques.Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements asmarket prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net incomewith an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on thetype of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value forderivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery pointand commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. Forilliquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into accountavailable market information and other inputs that might not be readily observable in the market. We estimate fair value asdescribed in Note 1I to Financial Statements and discussed under "Fair Value Measurements" below.Accounting standards related to derivative instruments and hedging activities allow for "normal" purchase or sale electionsand hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in netincome and thus reduce the volatility of net income that can result from fluctuations in fair values. "Normal" purchases and salesare contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normalcourse of business and are not subject to mark-to-market accounting if the election as normal is made. Hedge accountingdesignations are made with the intent to match the accounting recognition of the contract's financial performance to that of thetransaction the contract is intended to hedge.Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in othercomprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, itmirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectivenessof the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in othercomprehensive income are reclassified to net income in the period that the hedged transactions are recognized in net income.Although at December 31, 2012, we do not have any derivatives designated as cash flow or fair value hedges, we continuallyassess potential hedge elections and could designate positions as cash flow hedges in the future. In March 2007, the instrumentsmaking up a significant portion of the natural gas price hedging program that were previously designated as cash flow hedgeswere dedesignated as allowed under accounting standards related to derivative instruments and hedging activities, and subsequentchanges in their fair value have been marked-to-market in net income. In addition, in August 2008, interest rate swap transactionsin effect at that time were dedesignated as cash flow hedges in accordance with accounting standards, and subsequent changes intheir fair value have been marked-to-market in net income. See further discussion of the natural gas price hedging program andinterest rate swap transactions under "Significant Activities and Events and Items Influencing Future Performance."53 Table of ContentsThe following tables provide the effects on both the statements of consolidated income (loss) and comprehensive income(loss) of accounting for those derivative instruments (both commodity-related and interest rate swaps) that we have determinedto be subject to fair value measurement under accounting standards related to derivative instruments.Amounts recognized in net income (loss) (after-tax):Unrealized net gains on positions marked-to-market in net incomeUnrealized net losses representing reversals of previously recognized fair values ofpositions settled in the periodUnrealized gain on termination of a long-term power sales contractReclassifications of net losses on cash flow hedge positions from othercomprehensive incomeTotal net gain (loss) recognizedAmounts recognized in other comprehensive income (loss) (after-tax):Reclassifications of net losses on cash flow hedge positions to net incomeYear Ended December 31,2012 2011 2010$ 287 $ 205 $ 1,257(1,162)(696)(606)75(7) (19) (59)$ (882) $ (510) $ 667$ 7 $ 19 $ 59The effect of mark-to-market and hedge accounting for derivatives on the balance sheet is as follows:December 31,Commodity contract assets $Commodity contract liabilities $Interest rate swap assets $Interest rate swap liabilities $Net accumulated other comprehensive loss included in shareholders' equity (amounts after tax) $2012 20112,047 $ 4,435(383) $ (1,245)2 $(2,067) $(42) $(2,231)(49)We report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements wehave with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the balancesheet. See Note 12 to Financial Statements.Fair Value MeasurementsWe determine value under the fair value hierarchy established in accounting standards. We utilize several valuation techniquesto measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other marketinformation for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. Thesetechniques include, but are not limited to, the use of broker quotes and statistical relationships between different price curves andare intended to maximize the use of observable inputs and minimize the use of unobservable inputs. In applying the marketapproach, we use a mid-market valuation convention (the mid-point between bid and ask prices) as a practical expedient.Under the fair value hierarchy, Level I and Level 2 valuations generally apply to our commodity-related contracts for naturalgas, electricity and fuel, including coal and uranium, derivative instruments entered into for hedging purposes, securities associatedwith the nuclear decommissioning trust, and interest rate swaps intended to fix and/or lower interest payments on long-term debt.Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date.Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information ofsimilar securities, adjusted for observable differences. Level 2 inputs include:" quoted prices for similar assets or liabilities in active markets;" quoted prices for identical or similar assets or liabilities in markets that are not active;" inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curvesobservable at commonly quoted intervals, andinputs that are derived principally from or corroborated by observable market data by correlation or other means.54 Table of ContentsExamples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assetsor liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example,certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets;however, an active market might exist for such derivatives for a different time period at the same location. We utilize correlationtechniques to compare prices for inputs at both time periods to provide a basis to value those derivatives that do not have activemarkets. (See Note 11 to Financial Statements for additional discussion of how broker quotes are utilized.)Our Level 3 valuations generally apply to congestion revenue rights, certain coal contracts, options to purchase or sellelectricity, and electricity purchase and sales agreements for which the valuations include unobservable inputs, including the hourlyshaping of the price curve. Level 3 valuations use largely unobservable inputs, with little or no supporting market activity, andassets and liabilities are classified as Level 3 if such inputs are significant to the fair value determination. We use the mostmeaningful information available from the market, combined with our own internally developed valuation methodologies, todevelop our best estimate of fair value. The determination of fair value for Level 3 assets and liabilities requires significantmanagement judgment and estimation.Valuations of Level 3 assets and liabilities are sensitive to the assumptions used for the significant inputs. Where marketdata is available, the inputs used for valuation reflect that information as of our valuation date. In periods of extreme volatility,lessened liquidity or in illiquid markets, there may be more variability in market pricing or a lack of market data to use in thevaluation process. An illiquid market is one in which little or no observable activity has occurred or one that lacks willing buyers.Valuation risk is mitigated through the performance of stress testing of the significant inputs to understand the impact that varyingassumptions may have on the valuation and other review processes performed to ensure appropriate valuation.As part of our valuation of assets subject to fair value accounting, counterparty credit risk is taken into consideration bymeasuring the extent of netting arrangements in place with the counterparty along with credit enhancements and the estimatedcredit rating of the counterparty. Our valuation of liabilities subject to fair value accounting takes into consideration the market'sview of our credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancementsposted by us. We consider the credit risk adjustment to be a Level 3 input since judgment is used to assign credit ratings, recoveryrate factors and default rate factors.Level 3 assets totaled $83 million and $124 million at December 31, 2012 and 2011, respectively, and representedapproximately 3% and 2%, respectively, of the assets measured at fair value, or less than 1% of total assets in both years. Level3 liabilities totaled $54 million and $71 million at December 31, 2012 and 2011, respectively, and represented approximately 2%of the liabilities measured at fair value, or less than 1% of total liabilities in both years.Valuations of several of our Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing modelinputs such as volatility factors and credit risk adjustments. At December 31, 2012 and 2011, a 10% change in electricity price(per MWh) assumptions across unobservable inputs would cause an approximate $8 million and $5 million change, respectively,in net Level 3 assets. A 10% change in coal price assumptions across unobservable inputs would cause an approximate $8 millionand $21 million change, respectively, in net Level 3 assets. See Note 11 to Financial Statements for additional information aboutfair value measurements, including information on unobservable inputs and related valuation sensitivities and a table presentingthe changes in Level 3 assets and liabilities for the years ended December 31, 2012, 2011 and 2010.Variable Interest EntitiesA variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level ofcontrol over the entity or results in economic risks to us. Determining whether or not to consolidate a VIE requires interpretationof accounting rules and their application to existing business relationships and underlying agreements. Amended accounting rulesrelated to VIEs became effective January 1, 2010. In determining the appropriateness of consolidation of a VIE, we evaluate itspurpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examinethe nature of any related party relationships among the interest holders of the VIE and the rights granted to the interest holders ofthe VIE to determine whether we have the right or obligation to absorb profit and loss from the VIE and the power to direct thesignificant activities of the VIE. See Note 2 to Financial Statements for information regarding our consolidated variable interestentities.55 Table of ContentsRevenue RecognitionOur revenue includes an estimate for unbilled revenue that represents estimated daily kWh consumption after the meter readdate to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using meteredconsumption as well as historical kWh usage information adjusted for weather and other measurable factors affecting consumption.Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because ofseasonal changes in demand. Accrued unbilled revenues totaled $260 million, $269 million and $297 million at December 31,2012, 2011 and 2010, respectively.Accounting for ContingenciesOur financial results may be affected by judgments and estimates related to loss contingencies. A significant contingencythat we account for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expenseis based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices,regulatory rulings, general economic conditions, effects of hurricanes and other natural disasters and customers' behaviors. Changesin customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of theestimation process. Historical results alone are not always indicative of future results, causing management to consider potentialchanges in customer behavior and make judgments about the collectability of accounts receivable. Bad debt expense, the substantialmajority of which relates to our retail operations, totaled $26 million, $56 million and $108 million for the years ended December31, 2012, 2011 and 2010, respectively.Litigation contingencies also may require significant judgment in estimating amounts to accrue. We accrue liabilities forlitigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable. Nosignificant amounts have been accrued for such contingencies during the three-year period ended December 31, 2012. See Note9 to Financial Statements for discussion of significant litigation.Accounting for Income TaxesEFH Corp. files a US federal income tax return that includes the results of EFCH and TCEH. EFH Corp. and its subsidiaries(including EFCH and TCEH) are bound by a Federal and State Income Tax Allocation Agreement, which provides, among otherthings, that each of EFCH, TCEH and any other subsidiaries under the agreement is required to make payments to EFH Corp. inan amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate taxreturn.Our income tax expense and related balance sheet amounts involve significant management estimates and judgments.Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgmentsofthe timing and probability ofrecognition ofincome and deductions by taxing authorities. In assessing the likelihood ofrealizationof deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual incometaxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, ourforecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxingauthorities. EFH Corp.'s income tax returns are regularly subject to examination by applicable tax authorities. In management'sopinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxesthat may be owed as a result of any examination. See Notes 1, 4 and 5 for discussion of income tax matters.Depreciation and AmortizationDepreciation expense related to generation facilities is based on the estimates of fair value and economic useful lives asdetermined in the application of purchase accounting for the Merger. The accuracy of these estimates directly affects the amountof depreciation expense. If future events indicate that the estimated lives are no longer appropriate, depreciation expense will berecalculated prospectively from the date of such determination based on the new estimates of useful lives.The estimated remaining lives range from 20 to 57 years for the lignite/coal- and nuclear-fueled generation units.Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives basedon the expected realization of economic effects. See Note 3 to Financial Statements for additional information.56 Table of ContentsRESULTS OF OPERATIONSEffects of Change in Wholesale Electricity MarketAs discussed above under "Significant Activities and Events and Items Influencing Future Performance," the nodal wholesalemarket design implemented by ERCOT in December 2010 resulted in operational changes that facilitate hedging and trading ofpower. As part of ERCOT's transition to a nodal wholesale market, volumes under nontrading bilateral purchase and sales contractsare no longer scheduled as physical power with ERCOT. As a result of these changes in market operations, reported wholesalerevenues and purchased power costs in 2012 and 2011 were materially less than amounts reported in prior periods. Effective withthe nodal market implementation, if volumes delivered to our retail and wholesale customers are less than our generation volumes(as determined on a daily settlement basis), we record additional wholesale revenues. Conversely, if volumes delivered to ourretail and wholesale customers exceed our generation volumes, we record additional purchased power costs. The resultingadditional wholesale revenues or purchased power costs are offset in net gain from commodity hedging and trading activities.Sales Volume and Customer Count DataYear Ended December 3 1, 20122012 2011 2010 % ChangeSales volumes:Retail electricity sales volumes -(GWh):ResidentialSmall business (a)Large business and other customersTotal retail electricityWholesale electricity sales volumes (b)Total sales volumesAverage volume (kWh) per residential customer (c)Weather (North Texas average) -percent of normal (d):Cooling degree daysHeating degree days23,283 27,337 28,2085,914 7,059 8,04210,373 12,828 15,33939,570 47,224 51,58934,524 34,496 51,35974,094 81,720 102,94814,617 16,100 15,532(14.8)(16.2)(19.1)(16.2)0.1(9.3)(9.2)2011% Change(3.1)(12.2)(16.4)(8.5)(32.8)(20.6)3.721.9(5.9)114.7% 132.7% 108.9% (13.6)82.0% 109.7% 116.6% (25.3)Customer counts:Retail electricity customers (end of period and in thousands) (e):ResidentialSmall business (a)Large business and other customersTotal retail electricity customers1,560 1,625 1,771176 185 21717 19 201,753 1,829 2,008(4.0)(4.9)(10.5)(4.2)(8.2)(14.7)(5.0)(8.9)(a) Customers with demand of less than I MW annually.(b) Includes net amounts related to sales and purchases of balancing energy in the "real-time market."(c) Calculated using average number of customers for the period.(d) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data fromreporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department ofCommerce). Normal is defined as the average over the 10-year period from 2000 to 2010.(e) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number ofmeters does not reflect the number of individual customers.57 Table of ContentsRevenue and Commodity Hedging and Trading ActivitiesYear Ended December 31, 2012 20112012 2011 2010 % Change % ChangeOperating revenues:Retail electricity revenues:ResidentialSmall business (a)Large business and other customersTotal retail electricity revenuesWholesale electricity revenues (b)(c)Amortization of intangibles (d)Other operating revenuesTotal operating revenuesNet gain from commodity hedging and trading activities:Realized net gains on settled positionsUnrealized net gains (losses)Total$ 2,918 $ 3,377738 896717 9974,373 5,2701,005 1,482$ 3,6631,0521,2115,9262,00521 18 16237 270 288$ 5,636 $ 7,040 $ 8,235$ 1,953 $ 971 $ 1,008(1,564) 40 1,153$ 389 $ 1,011 $ 2,161(13.6)(17.6)(28.1)(17.0)(32.2)16.7(12.2)(19.9)101.1(61.5)(7.8)(14.8)(17.7)(11.1)(26.1)12.5(6.3)(14.5)(3.7)(53.2)(a) Customers with demand of less than 1 MW annually.(b) Upon settlement of physical derivative commodity contracts, such as certain electricity sales and purchase agreements andcoal purchase contracts, that we mark-to-market in net income, wholesale electricity revenues and fuel and purchased powercosts are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result,these line item amounts include a noncash component, which we deem "unrealized." (The offsetting differences betweencontract and market prices are reported in net gain from commodity hedging and trading activities.) These amounts are asfollows:Reported in revenuesReported in fuel and purchased power costsNet gainYear Ended December 31,2012 2011 2010$ (1) $ -$ (28)39 18 96$ 38$ 18 $ 68(c) Includes net amounts related to sales and purchases of balancing energy in the "real-time market."(d) Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting frompurchase accounting.58 Table of ContentsProduction, Purchased Power and Delivery Cost DataFuel, purchased power costs and delivery fees ($ millions):Fuel for nuclear facilitiesFuel for lignite/coal facilities (a)Total nuclear and lignite/coal facilities (a)Fuel for natural gas facilities and purchased power costs (a)(b)Amortization of intangibles (c)Other costsFuel and purchased power costsDelivery feesTotalFuel and purchased power costs (which excludes generationfacilities operating costs) per MWh:Nuclear facilitiesLignite/coal facilities (a) (d)Natural gas facilities and purchased power (a) (e)Delivery fees per MWhProduction and purchased power volumes (GWh):Year Ended December 31,2012 2011 2010S 175 $ 160 $ 159816 992 915991 1,152 1,074323 426 1,49748 111 161194 309 1871,556 1,998 2,9191,260 1,398 1,452$ 2,816 $ 3,396 S 4,3712012 2011% Change % Change$ 8.78 $ 8.30$ 20.54 S 19.79$ 45.06 $ 53.26$ 31.75 $ 29.52$$$$7.8919.2843.8128.069.4(17.7)(14.0)(24.2)(56.8)(37.2)(22.1)(9.9)(17.1)5.83.8(15.4)7.63.2(15.2)(10.7)5.018.6(9.3)2.9(16.2)(11.4)0.68.47.3(71.5)(31.1)65.2(31.6)(3.7)(22.3)5.22.621.65.2(4.6)6.23.3(25.2)(88.5)(20.6)(4.6)1.6(0.5)Nuclear facilitiesLignite/coal facilities (f)Total nuclear- and lignite/coal facilitiesNatural gas-facilitiesPurchased power (g)Total energy supply volumesCapacity factors:Nuclear facilitiesLignite/coal facilities (f)Total19,897 19,283 20,20849,298 58,165 54,77569,195 77,448 74,9831,295 1,233 1,6483,604 3,039 26,31774,094 81,720 102,94898.5%70.0%76.4%95.7%83.5%86.2%100.3%82.2%86.6%(a) 2011 and 2010 reflect reclassifications of start-up fuel to lignite/coal from natural gas facilities to conform to current periodpresentation.(b) See note (b) to the "Revenue and Commodity Hedging and Trading Activities" table on previous page.(c) Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contractsand power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.(d) Includes depreciation and amortization of lignite mining assets (except for incremental depreciation in 2011 due to theCSAPR as discussed in Note 3 to Financial Statements), which is reported in the depreciation and amortization expense lineitem, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (b) to the "Revenue andCommodity Hedging and Trading Activities" table on previous page.(e) Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (c) immediatelyabove.(f) Includes the estimated effects of economic backdown of lignite/coal-fueled units totaling 9,550 GWh, 4,290 GWh and 3,536GWh in 2012, 2011 and 2010, respectively.(g) Includes amounts related to line loss and power imbalances.59 Table of ContentsFinancial Results -Year Ended December 31, 2012 Compared to Year Ended December 31, 2011Operating revenues decreased $1.404 billion, or 20%, to $5.636 billion in 2012.Retail electricity revenues decreased $897 million, or 17%, to $4.373 billion reflecting an $854 million decline due to lowersales volumes and $43 million in lower average prices. Sales volumes fell 16% reflecting declines in both the residential andbusiness markets. Residential market volumes were lower due to much milder weather and a 4% decrease in customer countsdriven by competitive activity. Business market volumes were lower due to a change in customer mix and lower customer countsdriven by competitive activity. Overall average retail pricing declined 1% driven by business markets.Wholesale electricity revenues decreased $477 million, or 32%, to $1.005 billion in 2012 driven by lower average prices,which reflected much milder weather, including the effects on prices of very hot weather in the summer of 2011, as well as lowernatural gas prices.Fuel, purchased power costs and delivery fees decreased $580 million, or 17%, to $2.816 billion in 2012. Lignite/coal fuelcosts decreased $176 million driven by an increase in economic backdown and planned and unplanned generation unit outages.Purchased power and other costs (including ancillary services) decreased $124 million reflecting lower wholesale electricity pricesand natural gas prices. Delivery fees declined $138 million reflecting lower retail volumes. Natural gas fuel costs decreased $63million reflecting lower prices. Amortization of intangibles decreased $63 million reflecting lower amortization of emissionallowances due to an impairment recorded in the third quarter 2011 and expiration of contracts fair-valued under purchase accountingat the Merger date.A 15% decrease in lignite/coal-fueled production was driven by increased economic backdown and generation unit plannedand unplanned outages, while nuclear-fueled production increased 3% reflecting one refueling outage in 2012 and two in 2011.Following is an analysis of amounts reported as net gain from commodity hedging and trading activities, which totaled $389million and $1.011 billion in net gains for the years ended December 31, 2012 and 2011, respectively, and is largely reflective ofthe natural gas price hedging program discussed above under "Significant Activities and Events and Items Influencing FuturePerformance -Natural Gas Price Hedging Program and Other Hedging Activities":Year Ended December 31, 2012Net Realized Net UnrealizedGains Losses TotalHedging positions $ 1,885 $ (1,542) $ 343Trading positions 68 (22) 46Total $ 1,953 $ (1,564) $ 389Year Ended December 31, 2011Net Realized Net UnrealizedGains Gains TotalHedging positions $ 912 $ 21 $ 933Trading positions 59 19 78Total $ 971 $ 40 $ 1,011While unrealized losses were recorded in both 2012 and 2011 to reverse previously recorded unrealized gains on positionssettled in the periods, the effect of greater declines in natural gas prices in 2011 on a larger hedge position resulted in net unrealizedgains in 2011.Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues andpurchased power costs, as required by accounting rules, totaled $38 million and $18 million in net gains in 2012 and 2011,respectively (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).60 Table of ContentsOperating costs decreased $36 million, or 4%, to $888 million in 2012. The decrease reflected $17 million in lower nucleargeneration maintenance costs reflecting one refueling outage in 2012 and two in 2011, $10 million in lower costs related to newsystems implementation and process improvements at generation facilities and $5 million in lower lignite-fueled generationmaintenance costs reflecting timing and scope of work.Depreciation and amortization decreased $127 million, or 9%, to $1.343 billion in 2012. The decrease reflected increaseduseful lives and retirements of certain generation assets and accelerated mine asset depreciation in 2011 due to then planned mineclosures needed to comply with the CSAPR.SG&A expenses decreased $69 million, or 9%, to $659 million in 2012. The decrease reflected $30 million in lower baddebt expense due to improved collection and customer care processes, customer mix and lower revenues, $25 million in lowerretail marketing and related expense and $21 million in lower employee compensation and benefits costs.In 2012, a $1.2 billion impairment of goodwill was recorded as discussed in Note 3 to Financial Statements.Other income totaled $13 million in 2012 and $48 million in 2011. Other income in 2012 included a $6 million fee receivedto novate certain hedge transactions between counterparties. Other income in 2011 included $21 million related to the settlementof bankruptcy claims against a counterparty, $7 million for a property damage claim and $6 million from a franchise tax refundrelated to prior years. See Note 6 to Financial Statements.Other deductions totaled $188 million in 2012 and $524 million in 2011. Other deductions in 2012 included a $141 millioncharge related to pension plan actions discussed in Note 13 to Financial Statements and a $24 million impairment of mineralinterest assets as a result of lower natural gas drilling activity and prices. Other deductions in 2011 resulting from the issuanceofthe CSAPR included a $418 million impairment charge for excess SO2 emission allowances due to emission allowance limitationsunder the CSAPR and a $9 million impairment of mining assets. Other deductions in 2011 also included $86 million in third partyfees related to the amendment and extension of the TCEH Senior Secured Facilities. See Note 6 to Financial Statements.Interest income decreased $40 million, or 47%, to $46 million. The decrease was driven by lower intercompany debt balances.Interest expense and related charges decreased $950 million, or 25%, to $2.842 billion in 2012. The decrease was drivenby a $978 million favorable change in unrealized mark-to-market net gains/losses on interest rate swaps, reflecting a mark-to-market gain of $166 million in 2012 compared to a mark-to-market loss of $812 million in 2011.Income tax benefit totaled $924 million and $943 million on pretax losses in 2012 and 2011, respectively. The effectiverate was 33.8% in 2012, excluding the $1.2 billion nondeductible goodwill impairment charge, and 34.4% in 2011. The decreasein the effective rate was driven by the absence of the domestic production deduction due to an expected loss for federal incometax purposes in 2012 compared to income in 2011.After-tax loss increased $1.206 billion to $3.008 billion in 2012 reflecting the $1.2 billion goodwill impairment charge,lower revenues net of fuel, purchased power and delivery fees as well as lower results from commodity hedging and tradingactivities, partially offset by a favorable change in unrealized mark-to-market net gains/losses on interest rate swaps and theemission allowances impairment in 2011.61 Table of ContentsFinancial Results -Year Ended December 31, 2011 Compared to Year Ended December 31, 2010Operating revenues decreased $1.195 billion, or 15%, to $7.040 billion in 2011.Retail electricity revenues decreased $656 million, or 11%, to $5.270 billion and reflected the following:" An 8% decrease in sales volumes reduced revenues by $501 million and was driven by declines in the large and smallbusiness and residential markets. Business market volumes decreased 15% reflecting reduced contract signings drivenby competitive activity. Residential market volumes decreased 3% reflecting an 8% decline in customer count drivenby competitive activity, partially offset by a 4% increase in average consumption driven by warmer summer weather." Lower average pricing reduced revenues by $155 million reflecting declining prices in all customer segments. Loweraverage pricing is reflective of competitive activity in a lower wholesale power price environment and a change inbusiness customer mix.Wholesale electricity revenues decreased $523 million, or 26%, to $1.482 billion in 2011. The decrease is primarilyattributable to the nodal market change described above, partially offset by higher production from the new lignite-fueled generationunits and lower retail sales volumes.Fuel, purchased power costs and delivery fees decreased $975 million, or 22%, to $3.396 billion in 2011. Purchased powercosts decreased $1.029 billion driven by the effect of the nodal market described above. Delivery fees declined $54 millionreflecting lower retail sales volumes, partially offset by higher rates. Amortization of intangible assets decreased $50 millionreflecting expiration of contracts fair-valued at the Merger date under purchase accounting. These decreases were partially offsetby $77 million in higher coal/lignite costs driven by higher costs related to purchased coal and increased generation.A 6% increase in lignite/coal-fueled production was driven by increased production from the newly constructed generationfacilities, while nuclear-fueled production decreased 5% primarily due to planned outages in 2011.Following is an analysis of amounts reported as net gain from commodity hedging and trading activities, which totaled $1.011billion and $2.161 billion in net gains for the years ended December 31, 2011 and 2010, respectively, which reflected the naturalgas price hedging program discussed above under "Significant Activities and Events and Items Influencing Future Performance-Natural Gas Price Hedging Program and Other Hedging Activities":Year Ended December 31, 2011Hedging positionsTrading positionsTotalHedging positionsTrading positionsTotalNetNet Realized UnrealizedGains Gains Total$ 912 $ 21 $ 93359 19 78$ 971 $ 40 $ 1,011Year Ended December 31, 2010NetUnrealizedNet Realized GainsGains (Losses) Total$ 961 $ 1,157 $ 2,11847 (4) 43$ _ 1,008 $ 1,153 $ 2,161Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues andpurchased power costs, as required by accounting rules, totaled $18 million in net gains in 2011 and $68 million in net gains in2010.62 Table of ContentsOperating costs increased $87 million, or 10%, to $924 million in 2011. The increase reflected $48 million in higher nucleargeneration maintenance costs reflecting two planned refueling outages in 2011 as compared to one planned refueling outage in2010 and $27 million in higher costs at legacy lignite/coal-fueled generation units reflecting spending for environmental controlsystems including the CSAPR, and supply chain technology and equipment reliability process improvements. The increase alsoreflected $20 million in incremental expense related to a new generation unit placed in service in May 2010. The operating costincreases were partially offset by $9 million in lower maintenance costs at natural gas-fueled generation facilities reflecting theretirement of nine units in 2010.Depreciation and amortization increased $90 million, or 7%, to $1.470 billion in 2011. The increase reflected $44 millionof accelerated depreciation in 2011 resulting from the revised estimated useful lives for mine assets due to the then planned mineclosures needed to comply with the CSAPR (see Note 3 to Financial Statements for discussion of the effects of the CSAPR), $37million in increased depreciation primarily related to lignite/coal-fueled generation facilities reflecting equipment additions andreplacements and $36 million in incremental depreciation related to the new lignite-fueled generation unit discussed above. Theseincreases were partially offset by $24 million in decreased amortization of intangible assets largely related to the retail customerrelationship and reflecting expected customer attrition (see Note 3 to Financial Statements).SG&A expenses increased $6 million, or 1%, to $728 million in 2011. The increase was driven by $39 million in higheremployee compensation and benefit costs and $16 million in higher information technology and other services costs, partiallyoffset by $52 million in lower retail bad debt expense due to improved collection initiatives and customer mix.In 2010, a $4.1 billion impairment of goodwill was recorded as discussed in Note 3 to Financial Statements.Other income totaled $48 million in 2011 and $903 million in 2010. Other income in 2011 included $21 million related tothe settlement of bankruptcy claims against a counterparty, $7 million for a property damage claim and $6 million from a franchisetax refund related to prior years. Other income in 2010 included debt extinguishment gains of $687 million, a $116 million gainon termination of a power sales contract, a $44 million gain on the sale of land and related water rights and a $37 million gainassociated with the sale of interests in a natural gas gathering pipeline business. See Note 6 to Financial Statements.Other deductions totaled $524 million in 2011 and $18 million in 2010. Other deductions in 2011 resulting from the issuanceof the CSAPR included a $418 million impairment charge for excess SO2 emissions allowances due to emissions allowancelimitations under the CSAPR and a $9 million impairment of mining assets. Other deductions in 2011 also included $86 millionin third party fees related to the amendment and extension of the TCEH Senior Secured Facilities. See Notes 3, 6 and 8 to FinancialStatements.Interest expense and related charges increased $725 million, or 24%, to $3.792 billion in 2011. Interest paid/accrued increased$141 million to $2.618 billion driven by higher average rates reflecting debt exchanges and amendments. The balance of theincrease reflected $605 million in higher unrealized mark-to-market net losses related to interest rate swaps, $61 million in higheramortization of debt issuance and amendment costs and discounts and $29 million in lower capitalized interest, partially offset by$60 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting and a $51 million decrease ininterest accrued or paid with additional toggle notes due to debt exchanges and repurchases.Income tax benefit totaled $943 million on a pretax loss in 2011 compared to income tax expense totaling $318 million ona pretax gain in 2010, before the nondeductible goodwill impairment charge. The effective rate was 34.4% and 35.8% in 2011and 2010, respectively, excluding the goodwill impairment charge. The decrease in the rate was driven by lower state taxes dueto lower taxable margins, partially offset by the effect of ongoing tax deductions (principally lignite depletion) on a pretax loss in2011 compared to pretax income in 2010.After-tax loss decreased $1.728 billion to $1.802 billion in 2011 reflecting the $4.1 billion goodwill impairment charge in2010, partially offset in 2011 by lower gains from commodity hedging and trading activities, higher interest expense driven byunrealized mark-to-market net losses related to interest rate swaps, charges and expenses resulting from the issuance of the CSAPRand debt extinguishment gains in 2010.63 Table of ContentsEnergy-Related Commodity Contracts and Mark-to-Market ActivitiesThe table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31,2012, 2011 and 2010. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.521billion in unrealized net losses in 2012 and $58 million and $1.219 billion in unrealized net gains in 2011 and 2010, respectively,arising from mark-to-market accounting for positions in the commodity contract portfolio. The portfolio consists primarily ofeconomic hedges but also includes trading positions.Commodity contract net asset at beginning of periodSettlements of positions (a)Changes in fair value of positions in the portfolio (b)Other activity (c)Commodity contract net asset at end of periodYear Ended December 31,2012 2011 2010$ 3,190 $ 3,097 $ 1,718(1,800) (1,081) (943)279 1,139 2,162(5) 35 160$ 1,664 $ 3,190 $ 3,097(a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and lossesrecognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amountsrelated to positions entered into and settled in the same month.(b) Represents unrealized net gains recognized, reflecting net gains related to positions in the natural gas price hedging program(see discussion above under "Significant Activities and Events and Items Influencing Future Performance -Natural GasPrice Hedging Program and Other Hedging Activities"), partially offset by net losses related to other hedging positions.Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into andsettled in the same month.(c) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt orpayment of cash or other consideration, generally related to options purchased/sold. The 2010 amount includes a $116million noncash gain on termination of a long-term power sales contract.Maturity Table -The following table presents the net commodity contract asset arising from recognition of fair values atDecember 31, 2012, scheduled by the source of fair value and contractual settlement dates of the underlying positions.Source of fair valuePrices actively quotedPrices provided by other external sourcesPrices based on modelsTotalPercentage of total fair valueMaturity dates of unrealized commodity contract net asset at December 31, 2012Less than Excess of1 year 1-3 years 4-5 years 5 years Total(25) $ (3) $ -$ -$ (28)1,089 574 --1,66334 (5) --291,098 $ 566 $ -$ -$ 1,66466% 34% --% --% 100%The "prices actively quoted" category reflects only exchange-traded contracts for which active quotes are readily available.The "prices provided by other external sources" category represents forward commodity positions valued using prices for whichover-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT's North Hub extendthrough 2014 and over-the-counter quotes for natural gas generally extend through 2016, depending upon delivery point. The"prices based on models" category reflects non-exchange-traded options valued using option pricing models. In addition, thiscategory contains other contractual arrangements that may have both forward and option components, as well as other contractsthat are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 11 to FinancialStatements for fair value disclosures and discussion of fair value measurements.64 Table of ContentsFINANCIAL CONDITIONLiquidity and Capital ResourcesOperating Cash FlowsYear Ended December 31, 2012 Compared to Year Ended December 31, 2011 -Cash used in operating activities totaled$240 million compared to cash provided by operating activities of $1.236 billion in 2011. The change of $1.476 billion reflectednet changes in margin deposits totaling $1.0 billion. The change in margin deposits largely relates to the natural gas hedgingprogram; in 2012 more margin deposits were returned to counterparties due to settlement of maturing positions than were receivedfrom counterparties due to decreases in natural gas prices, while activity in 2011 reflected the opposite. The change in cash flowsalso reflected an increase of $194 million in working capital used reflecting timing of accounts payable and accrued expensepayments, $95 million in higher cash interest payments and cash settlements with EFH Corp. of $91 million related to pensionplan actions (see Note 13 to Financial Statements).Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 -Cash provided by operating activitiesdecreased $21 million to $1.236 billion in 2011. The change included the effect of amended accounting standards related to theaccounts receivable securitization program (see Note 7 to Financial Statements), under which the $383 million of funding underthe program at the January 1, 2010 adoption was reported as a use of operating cash flows and a source of financing cash flows.Excluding this accounting effect, cash provided by operating activities declined $404 million. This decrease reflected lower cashearnings due to the low wholesale power price environment, lower generation and higher fuel and operating costs at our legacygeneration facilities and an approximately $230 million increase in cash interest payments, partially offset by the contributionfrom the new lignite-fueled generation units (see Results of Operations). These effects were partially offset by a $408 millionincrease in net margin deposits received.Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statementof income by $178 million, $237 million and $276 million for the years ended December 31, 2012, 2011 and 2010, respectively.The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent withindustry practice, and amortization of intangible net assets arising from purchase accounting that is reported in various otherincome statement line items including operating revenues and fuel and purchased power costs and delivery fees.Financing Cash FlowsYear Ended December 31, 2012 Compared to Year Ended December 31, 2011 -Cash provided by financing activitiestotaled $1.161 billion in 2012 compared to cash used in financing activities of $973 million in 2011. Activity in 2012 reflectedan increase in borrowings of $1.384 billion under the TCEH Revolving Credit Facility (see Note 8 to Financial Statements),partially offset by a $159 million payment to settle transition bond reimbursement agreements with Oncor (see Note 15 to FinancialStatements). Activity in 2011 reflected the amendment and extension of the TCEH Senior Secured Facilities, includingapproximately $800 million in transaction costs, and repayment of certain debt securities, including $415 million of pollutioncontrol revenue bonds, as discussed in Note 8 to Financial Statements.Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 -Cash used in financing activities totaled$973 million in 2011 compared to cash provided by financing activities of $27 million in 2010. Activity in 2011 reflected theamendment and extension of the TCEH Senior Secured Facilities, including approximately $800 million in transaction costs, andrepayment of certain debt securities, including $415 million of pollution control revenue bonds, as discussed in Note 9 to FinancialStatements. Activity in 2010 reflected a $96 million source of financing cash flows, reflecting a $383 million effect of an accountingchange related to the accounts receivable securitization program as discussed above, net of a $287 million reduction of borrowingsunder the program.See Note 8 to Financial Statements for further detail of short-term borrowings and long-term debt.65 Table of ContentsInvesting Cash FlowsYear Ended December 31, 2012 Compared to Year Ended December 31, 2011 -Cash provided by investing activitiestotaled $134 million in 2012 compared to cash used of$ 190 million in 2011. Net repayments of notes due from affiliates increased$580 million in 2012 to $926 million (see Note 15 to Financial Statements). Capital expenditures (excluding nuclear fuel purchases)increased $101 million to $631 million in 2012 reflecting increased environmental-related spending. Nuclear fuel purchasesincreased $81 million to $213 million due to advance purchases necessary to fabricate fuel assemblies in time for the two nuclearunit refueling outages planned for 2014. Other decreases reflected an asset sale in 2011 and changes in restricted cash.Capital expenditures, including nuclear fuel, in 2012 totaled $844 million and consisted of:* $339 million for major maintenance, primarily in existing generation operations;* $270 million for environmental expenditures related to generation units;* $213 million for nuclear fuel purchases, and* $22 million for information technology, nuclear generation development and other corporate investments.Cash capital expenditures for 2012 are net of $19 million of reimbursements from the DOE related to dry cask storage. Weexpect to be reimbursed for our allowable costs of constructing dry cask storage for spent nuclear fuel through 2013 in accordancewith a settlement agreement with the DOE.Year Ended December 31, 2011 Compared to Year Ended December 31, 2010-- Cash used in investing activities totaled$190 million and $1.338 billion in 2011 and 2010, respectively. Investing activities reflected net repayments on notes receivablefrom affiliates totaling $346 million in 2011 and net loans under the notes totaling $503 million in 2010. Capital expendituresdecreased $266 million to $530 million in 2011 driven by a decrease in spending related to the construction of new generationfacilities and timing and scope of maintenance projects. Nuclear fuel purchases increased $26 million to $132 million in 2011reflecting the refueling of both nuclear-fueled generation units in 2011.Capital expenditures, including nuclear fuel, in 2011 totaled $662 million and consisted of:* $338 million for major maintenance, primarily in existing generation operations;* $142 million for environmental expenditures related to generation units;* $132 million for nuclear fuel purchases and* $50 million for information technology, nuclear generation development and other corporate investments.Cash capital expenditures in 2011 are net of $24 million of reimbursements from the DOE related to dry cask storage.Debt FinancingActivity -Activities related to short-term borrowings and long-term debt during the year ended December31, 2012 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capitalleases and exclude amounts related to debt discount, financing and reacquisition expenses):RepaymentsandBorrowings RepurchasesTCEH (a) $ 196 $ (30)EFCH -(10)EFH Corp. (pushed down to EFCH) (b) 27 (284)Total long-term 223 (324)Total short-term -TCEH (c) 1,384 --Total $ 1,607 $ (324)(a) Borrowings represent $181 million of noncash principal increases of TCEH Toggle Notes issued in May and November2012 in payment of accrued interest and $15 million of sale/leaseback and other lease transactions for mining equipment.Repayments represent $16 million of payments of principal at scheduled maturity dates and $14 million of payments ofcapital lease liabilities.(b) Borrowings represent noncash principal increases of EFH Corp. Toggle Notes issued in May and November 2012 in paymentof accrued interest. Repayments represent noncash retirements related to December 2012 debt exchanges.(c) Short-term amount represents net borrowings under the TCEH Revolving Credit Facility.66 Table of ContentsSee Note 8 to Financial Statements for further detail of long-term debt and other financing arrangements.Available Liquidity-- The following table summarizes changes in available liquidity for the year ended December 31,2012.Available LiquidityDecember 31, 2012 December 31, 2011 ChangeCash and cash equivalents $ 1,175 $ 120 $ 1,055TCEH Revolving Credit Facility -1,384 (1,384)TCEH Letter of Credit Facility 183 169 14Total liquidity $ 1,358 $ 1,673 $ (315)Available liquidity decreased $315 million since December 31, 2011 reflecting cash used for both capital expenditures(including nuclear fuel purchases) and operating activities totaling $1.1 billion, partially offset by EFH Corp.'s net repayment of$894 million of TCEH Demand Notes. EFH Corp. repaid the remaining balance of $698 million of TCEH Demand Notes inJanuary 2013.Debt Capacity -We believe that TCEH is permitted under its applicable debt agreements to issue additional senior secureddebt (in each case, subject to certain exceptions and conditions set forth in its applicable debt documents) as follows:" approximately $2.3 billion of additional aggregate principal amount of debt secured by substantially all of the assets ofTCEH and certain of its subsidiaries (of which $410 million can be on a first-priority basis and the remainder on a second-priority basis) and" an unlimited amount of additional first-priority debt in order to refinance the first-priority debt outstanding under theTCEH Senior Secured Facilities.These amounts are estimates based on our current interpretation of the covenants set forth in our debt agreements and donot take into account exceptions in the debt agreements that may allow for the incurrence of additional secured debt, including,but not limited to, acquisition debt, refinancing debt, capital leases and hedging obligations. Moreover, such amounts could changefrom time to time as a result of, among other things, the termination of any debt agreement (or specific terms therein) or amendmentsto the debt agreements that result from negotiations with new or existing lenders. In addition, covenants included in agreementsgoverning additional future debt may impose greater restrictions on our incurrence of secured or unsecured debt. Consequently,the actual amount of senior secured or unsecured debt that we are permitted to incur under our debt agreements could be materiallydifferent than the amounts provided above.Liquidity Needs, Including Capital Expenditures -Capital expenditures and nuclear fuel purchases for 2013 are expectedto total approximately $720 million and include:* $560 million for investments in generation facilities, including approximately:* $460 million for major maintenance and* $100 million for environmental expenditures related to the MATS and other regulations;* $140 million for nuclear fuel purchases and* $20 million for information technology, nuclear generation development and other corporate investments.We expect cash flows from operations, cash on hand and availability under our credit facilities discussed in Note 8 to FinancialStatements to provide sufficient liquidity to fund our current obligations, projected working capital requirements and capitalspending for at least the next twelve months. See Note I to Financial Statements for further discussion of liquidity considerations.Liquidity Effects of Commodity Hedging and Trading Activities -Commodity hedging and trading transactions typicallyrequire a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or tradinginstrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other formsof credit support to satisfy such collateral posting obligations. At December 31,2012, approximately 85% of the long-term naturalgas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pani passu with the TCEHSenior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral postingrequirements for those hedging transactions. See Note 8 to Financial Statements for more information about the TCEH SeniorSecured Facilities.67 Table of ContentsExchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take intoaccount the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin postedto take into account changes in the value of the underlying commodity). The amount of initial margin required is generally definedby exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factorsincluding market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other formsas negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and othercorporate purposes, including reducing short-term borrowings under credit facilities, or is required to be deposited in a separateaccount and restricted from being used for working capital and other corporate purposes. At December 31, 2012, all cash collateralheld was unrestricted. With respect to over-the-counter transactions, counterparties generally have the right to substitute lettersof credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterpartiesthereby reducing liquidity in the event that it was not restricted. See Note 16 to Financial Statements regarding restricted cash.With the natural gas price hedging program, increases in natural gas prices generally result in increased cash collateral andletter of credit postings to counterparties. At December 31, 2012, approximately 65 million MMBtu of positions related to thenatural gas price hedging program were not directly secured on an asset-lien basis and thus are subject to cash collateral postingrequirements.At December 31,2012, TCEH received or posted cash and letters of credit for commodity hedging and trading activities asfollows:* $69 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), ascompared to $50 million posted at December 31, 2011;* $598 million in cash has been received from counterparties, net of $2 million in cash posted, for over-the-counter andother non-exchange cleared transactions, as compared to $1.055 billion received, net of $6 million in cash posted, atDecember 31, 2011;* $376 million in letters of credit have been posted with counterparties, as compared to $363 million posted at December 31,2011, and* $22 million in letters of credit have been received from counterparties, as compared to $103 million received atDecember 31, 2011.Income Tax Payments -In the next twelve months, income tax payments to EFH Corp. related to the Texas margin taxare expected to total approximately $40 million, and we do not expect to make any payments to EFH Corp. related to federalincome taxes. Net payments totaled $84 million, $123 million and $49 million for the years ended December 31, 2012, 2011 and2010, respectively. (See Note 15 to Financial Statements.)We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions,but expect that no material federal income tax payments related to such positions will be made in the next 12 months (see Note 4to Financial Statements).Interest Rate Swap Transactions -See Note 8 to Financial Statements for discussion of TCEH's interest rate swaps.Accounts Receivable Securitization Program -TCEH participates in an accounts receivable securitization program withfinancial institutions. In accordance with transfers and servicing accounting standards, the trade accounts receivable amountsunder the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Underthe program, TXU Energy (originator) sells retail trade accounts receivable to TXU Energy Receivables Company, a consolidated,wholly-owned, bankruptcy-remote, direct subsidiary of TCEH. TXU Energy Receivables Company borrows funds from entitiesestablished for this purpose by the participating financial institutions using the accounts receivable as collateral. All new tradereceivables under the program generated by the originator are continuously purchased by TXU Energy Receivables Companywith the proceeds from collections of receivables previously purchased. Funding under the program and its predecessor totaled$82 million and $104 million at December 31, 2012 and 2011, respectively. See Note 7 to Financial Statements.Capitalization -Our capitalization ratios consisted of 152.2% and 133.9% long-term debt, less amounts due currently, and(52.2)% and (33.9)% common stock equity, at December 31, 2012 and 2011, respectively. Total debt to capitalization, includingshort-term debt, was 146.9%. and 132.8% at December 31, 2012 and 2011, respectively.68 Table of ContentsFinancial Covenants, Credit Rating Provisions and Cross Default Provisions -The terms of the TCEH Senior SecuredFacilities contain a maintenance covenant with respect to leverage ratio. At December 31, 2012, we were in compliance with suchcovenant.Covenants and Restrictions under Financing Arrangements -The TCEH Senior Secured Facilities and the indenturesgoverning substantially all of the debt we have issued in connection with, and subsequent to, the Merger contain covenants thatcould have a material impact on our liquidity and operations. In particular, the TCEH Senior Secured Facilities include a requirementto timely deliver to the lenders copies of audited annual financial statements that are not qualified as to the status of TCEH andits subsidiaries as a going concern.Adjusted EBITDA (as used in the maintenance covenant contained in the TCEH Senior Secured Facilities) for the yearended December 31,2012 totaled $3.574 billion for TCEH. See Exhibits 99(b) and 99(c) for a reconciliation of net loss to AdjustedEBITDA for TCEH and EFH Corp., respectively, for the years ended December 31, 2012 and 2011.The table below summarizes TCEH's secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEHSenior Secured Facilities and various other financial ratios of EFH Corp. and TCEH that are applicable under certain other thresholdsin the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Notes,the TCEH Senior Secured Second Lien Notes and the EFH Corp. Senior Notes at December 31,2012 and 2011. The debt incurrenceand restricted payments/limitations on investments covenants thresholds described below represent levels that must be met inorder for EFH Corp. or TCEH to incur certain permitted debt or make certain restricted payments and/or investments. EFCH andits consolidated subsidiaries are in compliance with their maintenance covenants. In January 2013, in accordance with amendmentsto the terms of the EFH Corp. Senior Secured Notes and their governing indentures, restrictive covenants to the notes were removed.Accordingly, the related coverage ratios are not reflected below (see Note 8 to Financial Statements).December 31, December 31,2012 2011Threshold Level atDecember 31, 2012Maintenance Covenant:TCEH Senior Secured Facilities:Secured debt to Adjusted EBITDA ratio (a)Debt Incurrence Thresholds:TCEH Senior Notes, Senior Secured Notes and SeniorSecured Second Lien Notes:TCEH fixed charge coverage ratioTCEH Senior Secured Facilities:TCEH fixed charge coverage ratioRestricted Payments/Limitations on Investments Thresholds:EFH Corp. Senior Notes:General restrictions (Sponsor Group payments):EFH Corp. leverage ratioTCEH Senior Notes, Senior Secured Notes and SeniorSecured Second Lien Notes:TCEH fixed charge coverage ratioTCEH Senior Secured Facilities:Payments to Sponsor Group:TCEH total debt to Adjusted EBITDA ratio5.88 to 1.00 5.78 to 1.00 Must not exceed 8.00 to 1.00 (b)1.2 to 1.0 1.3 to 1.01.2 to 1.0 1.3 to 1.0At least 2.0 to 1.0At least 2.0 to 1.010.1 to 1.0 9.7 to 1.0 Equal to or less than 7.0 to 1.01.2 to 1.0 1.3 to 1.0At least 2.0 to 1.08.5 to 1.0 8.7 to 1.0 Equal to or less than 6.5 to 1.0(a) At December 31, 2012, includes actual Adjusted EBITDA for the more recently constructed Oak Grove (1 and 2) generationunits and the Sandow 5 generation unit and all outstanding debt under the Delayed Draw Term Loan. At December 31,2011,includes pro forma Adjusted EBITDA for the Oak Grove 2 unit as well as actual Adjusted EBITDA for Sandow 5 and OakGrove I units and all outstanding debt under the Delayed Draw Term Loan.(b) Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities and up to $1.5 billion ($906million excluded at December 31, 2012) principal amount of TCEH senior secured first lien notes whose proceeds are usedto prepay term loans or deposit letter of credit loans under the TCEH Senior Secured Facilities.69 Table of ContentsMaterial Credit Rating Covenants and Credit Worthiness Effects on Liquidity--As a result of TCEH's non-investment gradecredit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, at December 31, 2012,counterparties to those contracts could have required TCEH to post up to an aggregate of $20 million in additional collateral. Thisamount largely represents the below market terms of these contracts at December 31, 2012; thus, this amount will vary dependingon the value of these contracts on any given day.Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REPto support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under thesetariffs, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equalto estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as thetime period of transition charges covered, varies by utility. At December 31, 2012, TCEH has posted collateral support in theform of letters of credit to the applicable utilities in an aggregate amount equal to $26 million, with $11 million of this amountposted for the benefit of Oncor.The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customerdeposits, if necessary. Under these rules, at December 31, 2012, TCEH posted letters of credit in the amount of $71 million, whichare subject to adjustments.The RRC has rules in place to assure that parties can meet their mining reclamation obligations, including through self-bonding when appropriate. If Luminant Generation Company LLC (a subsidiary of TCEH) does not continue to meet the self-bonding requirements as applied by the RRC, TCEH may be required to post cash, letter of credit or other tangible assets ascollateral support in an amount currently estimated to be approximately $850 million to $1.1 billion. The actual amount (ifrequired)could vary depending upon numerous factors, including the amount of Luminant Generation Company LLC's self-bond acceptedby the RRC and the level of mining reclamation obligations.ERCOT has rules in place to assure adequate credit worthiness of parties that participate in the "day-ahead," "real-time" andcongestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantlyin the form of letters of credit, totaling $190 million at December 31,2012 (which is subject to daily adjustments based on settlementactivity with ERCOT).Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issuesin the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in anamount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred, two or more ratingagencies downgrade Oncor's credit ratings below investment grade.Other arrangements of EFCH and its subsidiaries, including the accounts receivable securitization program (see Note 7 toFinancial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may beadjusted depending on the relevant credit ratings.Material Cross Default/Acceleration Provisions -Certain of our financing arrangements contain provisions that could resultin an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenantsthat could or does result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration"provisions.A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to theaccounts receivable securitization program, in an aggregate amount in excess of $200 million may result in a cross default underthe TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity ofoutstanding balances ($22.295 billion at December 31, 2012) under such facilities.The indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and the TCEH Senior Secured Second LienNotes contain a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtednessunder any instrument or instruments of TCEH or any of its restricted subsidiaries in an aggregate amount equal to or greater than$250 million may cause the acceleration of the TCEH Senior Notes, TCEH Senior Secured Notes and TCEH Senior SecuredSecond Lien Notes.Under the terms of a TCEH rail car lease, which had $41 million in remaining lease payments at December 31, 2012 andterminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in an aggregate principal amount of$100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively acceleratethe payment of any remaining lease payments due under the lease.70 Table of ContentsUnder the terms of another TCEH rail car lease, which had $44 million in remaining lease payments at December 31, 2012and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to thirdparty creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to theiroriginal stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of anyremaining lease payments due under the lease.The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that appliesin the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under theprogram. TXU Energy Receivables Company (a direct subsidiary of TCEH) has a cross default threshold of $50,000. If any ofthese cross default provisions were triggered, the program could be terminated.We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event ofdefault or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess ofthresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on thecontract.Each of TCEH's natural gas hedging agreements and interest rate swap agreements that are secured with a lien on its assetson a pari passu basis with the TCEH Senior Secured Facilities and TCEH Senior Secured Notes contain a cross default provision.In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but rangingfrom $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedgingagreements would have the right to terminate its hedge or interest rate swap agreement with TCEH and require all outstandingobligations under such agreement to be settled.Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to resultin a significant effect on liquidity.Long-Term ContractualObligations and Commitments-The following table summarizes our contractual cash obligationsat December 31, 2012 (see Notes 8 and 9 to Financial Statements for additional disclosures regarding these long-term debt andnoncancellable purchase obligations).One to Three to MoreLess Than Three Five Than FiveContractual Cash Obligations: One Year Years Years Years TotalLong-term debt -principal (a) $ 84 $ 7,592 $ 18,034 $ 4,762 $ 30,472Long-term debt -interest (b) 2,619 4,769 3,296 2,218 12,902Operating and capital leases (c) 56 96 123 169 444Obligations under commodity purchaseand services agreements (d) 926 1,124 503 865 3,418Total contractual cash obligations $ 3,685 $ 13,581 $ 21,956 $ 8,014 $ 47,236(a) Excludes short-term borrowings (including $2.054 billion of borrowings under the TCEH Revolving Credit Facilities thatmature in 2016, capital lease obligations (shown separately), unamortized premiums and discounts and fair value premiumsand discounts related to purchase accounting.(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interestrate swaps are calculated based on interest rates in effect at December 31, 2012.(c) Includes short-term noncancellable leases.(d) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the year-end2012 price for all periods except where contractual price adjustment or index-based prices are specified.71 Table of ContentsThe following are not included in the table above:" arrangements between affiliated entities and intercompany debt (see Note 15 to Financial Statements);" individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts withone counterparty that are more than $1 million on an aggregated basis have been included);" contracts that are cancellable without payment of a substantial cancellation penalty;" employment contracts with management, and* liabilities related to uncertain tax positions totaling $1.078 billion (as well as accrued interest totaling $172 million)discussed in Note 4 to Financial Statements as the ultimate timing of payment, if any, is not known.Guarantees -See Note 9 to Financial Statements for details of guarantees.OFF-BALANCE SHEET ARRANGEMENTSSee Notes 2 and 9 to Financial Statements regarding VIEs and guarantees, respectively.COMMITMENTS AND CONTINGENCIESSee Note 9 to Financial Statements for discussion of commitments and contingencies.CHANGES IN ACCOUNTING STANDARDSThere have been no recently issued accounting standards effective after December 31, 2012 that are expected to materiallyimpact our financial statements.72 Table of ContentsItem 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKAll dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwiseindicated.Market risk is the risk that we may experience a loss in value as a result of changes in market conditions affecting factors,such as commodity prices and interest rates, that may be experienced in the ordinary course of business. Our exposure to marketrisk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as wellas the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interestrate risk related to debt, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to managecommodity price risk.Risk OversightWe manage the commodity price, counterparty credit and commodity-related operational risk related to the competitiveenergy business within limitations established by senior management and in accordance with overall risk management policies.Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groupsthat operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies.These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value fromchanges in market conditions and include, but are not limited to, position review, Value at Risk (VaR) methodologies and stresstest scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review),operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validationand reporting, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.EFH Corp. has a corporate risk management organization that is headed by the Chief Financial Officer, who also functionsas the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respectivepolicies and procedures to ensure compliance with such limits and evaluates the risks inherent in our businesses.Commodity Price RiskThe competitive business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas andother energy-related products it markets or purchases. We actively manage the portfolio of owned generation assets, fuel supplyand retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in themarket, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices andspark spreads (differences between the market price of electricity and its cost of production).In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts withcustomers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. Wecontinuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to useconsistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.Natural Gas Price Hedging Program -See "Significant Activities and Events and Items Influencing Future Performance"above for a description of the program, including potential effects on reported results.VaR Methodology- A VaR methodology is used to measure the amount of market risk that exists within the portfolio undera variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidencelevel and considers, among other things, market movements utilizing standard statistical techniques given historical and projectedmarket prices and volatilities.A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effectiveway to estimate changes in'a portfolio's value based on assumed market conditions for liquid markets. The use of this methodrequires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., thetime necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlationdata.73 Table of ContentsTrading VaR -This measurement estimates the potential loss in fair value, due to changes in market conditions, of allcontracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five to 60 days.Year Ended December 31,2012 2011Month-end average Trading VaR: $ 7$ 4Month-end high Trading VaR:Month-end low Trading VaR:$$12 $1 $81VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting -This measurement estimates thepotential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principallyhedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holdingperiod of five to 60 days.Year Ended December 31,2012 2011Month-end average MtM VaR: $ 132 $ 195Month-end high MtM VaR: $ 206 $ 268Month-end low MtM VaR:$96 $121Earnings at Risk (EaR) -This measurement estimates the potential reduction of pretax earnings for the periods presented,due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). A95% vonfidence level and a five to 60 day holding period are assumed in determining EaR.Month-end average EaR:Month-end high EaR:Month-end low EaR:Year Ended December 31,2012 2011$ 109 $ 170$ 161 $ 228$ 77 $ 121The increase in the Trading VaR risk measure above reflected higher near-term market volatility and an increase in tradingpositions. The decreases in the MtM VaR and EaR risk measures above reflected a reduction of positions in the natural gas pricehedging program due to maturities and lower forward natural gas prices.74 Table of ContentsInterest Rate RiskThe table below provides information concerning our financial instruments at December 31,2012 and 2011 that are sensitiveto changes in interest rates, which consist of debt obligations and interest rate swaps. We have entered into interest rate swapsunder which we have exchanged fixed-rate and variable-rate interest amounts calculated with reference to specified notionalprincipal amounts at dates that generally coincide with interest payments under our credit facilities. In addition, we have enteredinto certain interest rate basis swaps to further reduce borrowing costs as discussed in Note 8 to Financial Statements. The weightedaverage interest rate presented is based on the rate in effect at the reporting date. Capital leases and the effects of unamortizedpremiums and discounts are excluded from the table. Average interest rate and average receive rate for variable rate instrumentsare based on rates in effect at December 31, 2012. See Note 8 to Financial Statements for a discussion of debt obligations.Expected Maturity DateL(millions of dollars, except percentages)2012 2012 2011 2011Total Total Total TotalThere- Carrying Fair Carrying Fair2013 2014 2015 2016 2017 after Amount Value Amount Valueong-term debt(including currentmaturities):Fixed rate debt amount(a) $ 84 $ 43 $ 3,505 $1,765 $ 70 $4,557 $10,024 $ 3,955 $10,124 $ 5,574Average interest rate 7.11% 6.36% 10.24% 11.23% 10.69% 11.72% 11.05% 11.04%Variable rate debtamount $ -$ 3.890 $ 154 $ 154 $16.045 $ 205 $20.448 $13.903 $20.447 $13166Average interest rateTotal debtDebt swapped to fixed:Amount (b)Average pay rate/-% 3.76% 4.75% 4.75% 4.74% 0.23% 4.51% 4.54%$ 84 $ 3,933 $3,659 $1,919 $16,115 $4,762 $30,472 $17,858 $30,571 $18,740$ 1,600 $16,860 $ 3,000 $ -$ 9,600 $ -8.53% 8.24% 6.85% -% 8.95% --$ --Average receive rate 4.81% 4.81% 4.87%Variable basis swaps:---% 4.88%AmountAverage pay rate$10,917 $ 1,050 $ -$ -$ -$ -$11,9670.33% 0.32% -% -% --0.33%$19,1670.39%0.26%Average receive rate 0.21% 0.21%-% --0.21%(a) Reflects the remarketing date and not the maturity date for certain debt that is subject to mandatory tender for remarketingprior to maturity. See Note 8 to Financial Statements for details concerning long-term debt subject to mandatory tender forremarketing.(b) $18.46 billion notional amount outstanding that matures in 2013 through October 2014 and $12.6 billion notional amountbeginning October 2014 that mature through October 2017. Notional amounts maturing in 2013 will be replaced by accretionof existing swaps maturing through October 2014.At December 31,2012, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $11 million, taking into account the interestrate swaps discussed in Note 8 to Financial Statements.75 Table of ContentsCredit RiskCredit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policieswith regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potentialcounterparty's financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific riskmitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negativeexposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businessesincluding methodologies to analyze counterparties' financial strength, measurement of current and potential future exposures andcontract language that provides rights for netting and setoff. Credit enhancements such as parental guarantees, letters of credit,surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed toassess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering intoan agreement with a counterparty that creates exposure. Further, we have established controls to determine and monitor theappropriateness of these limits on an ongoing basis. Prospective material changes in the payment history or financial conditionof a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. Thisprocess can result in the subsequent reduction of the credit limit or a request for additional financial assurances.Credit Exposure -Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) andnet asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $1.321billion at December 31, 2012. The components of this exposure are discussed in more detail below.Assets subject to credit risk at December 31, 2012 include $454 million in retail trade accounts receivable before taking intoaccount cash deposits held as collateral for these receivables totaling $64 million. The risk of material loss (after considerationof bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances foruncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historicalexperience, market or operational conditions and changes in the financial condition of large business customers.The remaining credit exposure arises from wholesale trade receivables, commodity contracts and hedging and tradingactivities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions,electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketingcompanies. At December 31, 2012, the exposure to credit risk from these counterparties totaled $867 million taking into accountthe netting provisions of the master agreements described above but before taking into account $612 million in credit collateral(cash, letters of credit and other credit support). The net exposure (after credit collateral) of $255 million decreased $326 millionfor the year ended December 31, 2012, driven by maturities of positions in the natural gas price hedging program.Of this $255 million net exposure, essentially all is with investment grade customers and counterparties, as determined usingpublicly available information including major rating agencies' published ratings and our internal credit evaluation process. Thosecustomers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are ratedusing internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitorsand manages credit exposure to these customers and counterparties on this basis.The following table presents the distribution of credit exposure at December 31,2012 arising from wholesale trade receivables,commodity contracts and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable andnet asset positions in the balance sheet arising from hedging and trading activities after taking into consideration netting provisionswithin each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateralincludes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 12 to FinancialStatements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.Gross Exposure by MaturityExposure GreaterBefore Credit Credit Net 2 years or Between than 5Collateral Collateral Exposure less 2-5 years years TotalInvestment grade $ 866 $ 612 $ 254 $ 866 $ -$ -$ 866Noninvestment grade I -1 1 --Totals $ 867 $ 612 $ 255 $ 867 $ -$ -$ 867Investment grade 99.9% 99.6%Noninvestment grade 0.1% 0.4%76 Table of ContentsIn addition to the exposures in the table above, contracts classified as "normal" purchase or sale and non-derivative contractualcommitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that isfavorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.Nonperformance could have a material impact on future results of operations, liquidity and financial condition.Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented 19%, 15%and 10% of the $255 million net exposure. We view exposure to these counterparties to be within an acceptable level of risktolerance due to the counterparties' credit ratings, each of which is rated as investment grade, and the importance of our businessrelationship with the counterparties.With respect to credit risk related to the natural gas price hedging program, all of the transaction volumes are withcounterparties that have an investment grade credit rating. However, there is current and potential credit concentration risk relatedto the limited number of counterparties that comprise the substantial majority of the program, with such counterparties being inthe banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that wouldrequire the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. Anevent of default by one or more hedge counterparties could subsequently result in termination-related settlement payments thatreduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts ofexpected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with thesecounterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through thevarious ongoing risk management measures described above.77 Table of ContentsFORWARD-LOOKING STATEMENTSThis report and other presentations made by us contain "forward-looking statements." All statements, other than statementsof historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that addressactivities, events or developments that we expect or anticipate to occur in the future, including such matters as financial oroperational projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, futureacquisitions or dispositions, development or operation of power generation assets, market and industry developments and thegrowth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans,""will likely," "unlikely," "expected," "anticipated," "estimated," "should," "projection," "target," "goal," "objective" and "outlook"),are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations arebased on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety byreference to the discussion of risk factors under Item 1 A, "Risk Factors" and the discussion under Item 7, "Management's Discussionand Analysis of Financial Condition and Results of Operations" in this report and the following important factors, among others,that could cause our actual results to differ materially from those projected in such forward-looking statements:prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas,the US Congress, the US Federal Energy Regulatory Commission, the NERC, the TRE, the PUCT, the RRC, the NRC,the EPA, the TCEQ, the US Mine Safety and Health Administration and the US Commodity Futures Trading Commission,with respect to, among other things:o allowed prices;o industry, market and rate structure;o purchased power and recovery of investments;o operations of nuclear generation facilities;o operations of fossil-fueled generation facilities;o operations of mines;acquisition and disposal of assets and facilities;o development, construction and operation of facilities;° decommissioning costs;present or prospective wholesale and retail competition;o changes in tax laws and policies;o changes in and compliance with environmental and safety laws and policies, including the CSAPR, MATS andclimate change initiatives, and" clearing over the counter derivatives through exchanges and posting of cash collateral therewith;* legal and administrative proceedings and settlements;* general industry trends;" economic conditions, including the impact of an economic downturn;" our ability to collect trade receivables from counterparties;* our ability to attract and retain profitable customers;" our ability to profitably serve our customers;* restrictions on competitive retail pricing;* changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;* changes in prices of transportation of natural gas, coal, crude oil and refined products;* changes in market heat rates in the ERCOT electricity market;" our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heatrates and interest rates;* weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts ofsabotage, wars or terrorist or cybersecurity threats or activities;* population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT;* changes in business strategy, development plans or vendor relationships;" access to adequate transmission facilities to meet changing demands;" changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;" changes in operating expenses, liquidity needs and capital expenditures;" commercial bank market and capital market conditions and the potential impact of disruptions in US and internationalcredit markets;* the willingness of our lenders to extend the maturities of our debt instruments and the terms and conditions of any suchextensions;* access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability offunds in capital markets;" activity in the credit default swap market related to our debt instruments;78 Table of Contents" restrictions placed on us by the agreements governing our debt instruments;" our ability to generate sufficient cash flow to make interest payments on, or refinance, our debt instruments;" our ability to successfully execute our liability management program or otherwise address our debt maturities;* any defaults under certain of our financing arrangements that could trigger cross default or cross acceleration provisionsunder other financing arrangements;" our ability to make intercompany loans or otherwise transfer funds among different entities in our corporate structure;" competition for new energy development and other business opportunities;" inability of various counterparties to meet their obligations with respect to our financial instruments;" changes in technology used by and services offered by us;" changes in electricity transmission that allow additional electricity generation to compete with our generation assets;* significant changes in our relationship with our employees, including the availability of qualified personnel, and thepotential adverse effects if labor disputes or grievances were to occur;" changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits,pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure underERISA;" changes in assumptions used to estimate future executive compensation payments;" hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resultingfrom such hazards;" significant changes in critical accounting policies;" actions by credit rating agencies;" adverse claims by our creditors or holders of our debt securities;* our ability to effectively execute our operational strategy, and" our ability to implement cost reduction initiatives.Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, weundertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it ismade or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us topredict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors,may cause results to differ materially from those contained in any forward-looking statement. As such, you should not undulyrely on such forward-looking statements.INDUSTRY AND MARKET INFORMATIONThe industry and market data and other statistical information used throughout this report are based on independent industrypublications, government publications, reports by market research firms or other published independent sources, including certaindata published by ERCOT, the PUCT and NYMEX. We did not commission any of these publications or reports. Some data isalso based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sourceslisted above. Independent industry publications and surveys generally state that they have obtained information from sourcesbelieved to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each ofthese studies and publications is reliable, we have not independently verified such data and make no representation as to theaccuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we donot know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly,while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and wemake no assurances that the predictions contained therein are accurate.79 Table of ContentsItem 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and Shareholders of Energy Future Competitive Holdings CompanyDallas, TexasWe have audited the accompanying consolidated balance sheets of Energy Future Competitive Holdings Company (a subsidiaryof Energy Future Holdings Corp.) and subsidiaries ("EFCH") as of December 31, 2012 and 2011, and the related statements ofconsolidated income (loss), comprehensive income (loss), cash flows and equity for each of the three years in the period endedDecember 31, 2012. These financial statements are the responsibility of EFCH's management. Our responsibility is to expressan opinion on these financial statements based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statementsare free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosuresin the financial statements. An audit also includes assessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonablebasis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy FutureCompetitive Holdings Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and theircash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generallyaccepted in the United States of America.EFCH continues to experience net losses, has substantial indebtedness and has significant cash interest requirements. EFCH'sability to satisfy its obligations in October 2014, which include the maturities of $3.8 billion of Texas Competitive Electric HoldingsCompany LLC ("TCEH") Term Loan Facilities, is dependent upon the completion of one or more actions discussed in Note I tothe consolidated financial statements. Also see Note 8 to the consolidated financial statements. Additionally, as discussed in Note15 to the consolidated financial statements, TCEH has made loans, which are payable on demand, to its indirect parent, EnergyFuture Holdings Corp., with amounts outstanding as of December3 1, 2012 and 2011 of $698 million (which were repaid in January2013) and $1.592 billion, respectively.We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),EFCH's internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report datedFebruary 19, 2013 expressed an unqualified opinion on EFCH's internal control over financial reporting./s/ DELOITrE & ToucHE LLPDallas, TexasFebruary 19, 201380 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYSTATEMENTS OF CONSOLIDATED INCOME (LOSS)Operating revenuesFuel, purchased power costs and delivery feesNet gain from commodity hedging and trading activitiesOperating costsDepreciation and amortizationSelling, general and administrative expensesFranchise and revenue-based taxesImpairment of goodwill (Note 3)Other income (Note 6)Other deductions (Note 6)Interest incomeInterest expense and related charges (Note 16)Loss before income taxesIncome tax (expense) benefit (Note 5)Net lossYear Ended December 31,2012 2011 2010(millions of dollars)$ 5,636 $ 7,040 $ 8,235(2,816) (3,396) (4,371)389 1,011 2,161(888) (924) (837)(1,343) (1,470) (1,380)(659) (728) (722)(80) (96) (106)(1,200) -(4,100)13 48 903(188) (524) (18)46 86 90(2,842) (3,792) (3,067)(3,932) (2,745) (3,212)924 943 (318)$ (3,008) $ (1,802) $ (3,530)See Notes to Financial Statements.STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)Net lossOther comprehensive income, net of tax effects -cash flow hedgesderivative value net loss related to hedged transactions recognized duringthe period and reported in net loss (net of tax benefit of $3, $10 and $31)Comprehensive lossYear Ended December 31,2012 2011 2010(millions of dollars)(3,008) $ (1,802) $ (3,530)7 19 59(3,001) _$ (1,783) $ (3,471)See Notes to Financial Statements.81 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYSTATEMENTS OF CONSOLIDATED CASH FLOWSYear Ended December 31,2012 2011 2010(millions of dollars)$ (3,008) $ (1,802) $ (3,530)Cash flows -operating activities:Net lossAdjustments to reconcile net loss to cash provided by (used in) operatingactivities:Depreciation and amortizationDeferred income tax expense (benefit), netImpairment of goodwill (Note 3)Unrealized net (gain) loss from mark-to-market valuations of commoditypositionsUnrealized net (gain) loss from mark-to-market valuations of interest rateswaps (Note 8)Interest expense on toggle notes payable in additional principal (Notes 8and 16)Amortization of debt related costs, discounts, fair value discounts andlosses on dedesignated cash flow hedges (Note 16)Interest expense related to pushed-down debt of parent (Notes 8 and 16)Unsettled charges related to pension plan actions (Note 13)Impairment of emissions allowances intangible assets (Note 3)Other asset impairments (Note 6)Third-party fees related to debt amendment and extension transactions(Note 8) (reported as financing)Debt extinguishment gains (Note 6)Gain on termination of long-term power sales contract (Note 6)Bad debt expense (Note 7)Accretion expense related primarily to mining reclamation obligations(Note 16)Stock-based incentive compensation expenseNet equity loss from unconsolidated affiliateNet (gain) loss on sale of assetsOther, netChanges in operating assets and liabilities:Affiliate accounts receivable/payable, netAccounts receivable -tradeImpact of accounts receivable securitization program (Note 7)InventoriesAccounts payable -tradeCommodity and other derivative contractual assets and liabilitiesMargin deposits, netOther -net assetsOther -net liabilitiesCash provided by (used in) operating activitiesCash flows -financing activities:Issuances of long-term debt (Note 8)Repayments/repurchases of long-term debt (Note 8)Net short-term borrowings under accounts receivable securitization program(Note 7)Increase (decrease) in other short-term borrowings (Note 8)Notes due to affiliatesDecrease in income tax-related note payable to Oncor (Note 15)Settlement of reimbursement agreements with Oncor (Note 15)1,521(952)1,2001,526(166)1522017550311,707(1,116)(58)1,6565344,100(1,221)81216622778418986207217226211(687)(116)10826374341564854(2)25775(81)13(87)2219(126)6(476)(52)(251)(240)(40)(22)1,384(20)(159)(4)175(23)(126)(33)540(27)941.2365258(383)(6)(149)(44)13220(282)1.2571,750(1,408)8(455)(39)353(647)9617234(37)82 Table of ContentsContributions from noncontrolling interestsSale/leaseback of equipmentDebt amendment, exchange and issuance costs, including third-party feesexpensedOther, netCash provided by (used in) financing activitiesCash flows -investing activities:Capital expendituresNuclear fuel purchasesNotes due from affiliatesPurchase of right to use certain computer-related assets from parent (Note 3)Proceeds from sales of assetsReduction of restricted cash related to TCEH Letter of Credit Facility (Note8)Other changes in restricted cashProceeds from sales of environmental allowances and creditsPurchases of environmental allowances and creditsProceeds from sales of nuclear decommissioning trust fund securitiesInvestments in nuclear decommissioning trust fund securitiesOther, netCash provided by (used in) investing activitiesNet change in cash and cash equivalentsEffect of consolidation of VIECash and cash equivalents -beginning balanceCash and cash equivalents -ending balanceYeai2012715(5)11,161(631)(213)926(38)2129(25)106(122)1341,055120$ 1,175Ended December 31,2011 2010millions of dollars)16 32(843) (13)(2) 37(973) 27(530) (796)(132) (106)346 (503)49 141188(96) (33)10 12(17) (30)2,419 974(2,436) (990)9 (7)(190) (1,338)73 (54)747 94$ 120 $ 47See Notes to Financial Statements.83 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCONSOLIDATED BALANCE SHEETS2012 2011(millions of dollars)ASSETSCurrent assets:Cash and cash equivalentsRestricted cash (Note 16)Trade accounts receivable -net (includes $445 and $524 in pledged amounts related to aVIE (Notes 2 and 7))Notes receivable from parent (Note 15)Inventories (Note 16)Commodity and other derivative contractual assets (Note 12)Margin deposits related to commodity positionsOther current assetsTotal current assetsRestricted cash (Note 16)Notes receivable from parent (Note 15)Investments (Note 16)Property, plant and equipment -net (Note 16)Goodwill (Note 3)Identifiable intangible assets -net (Note 3)Commodity and other derivative contractual assets (Note 12)Other noncurrent assets, primarily unamortized debt amendment and issuance costsTotal assetsLIABILITIES AND EQUITYCurrent liabilities:Short-term borrowings (includes $82 and $104 related to a VIE (Notes 2 and 8))Advances from parentLong-term debt due currently (Note 8)Trade accounts payableTrade accounts and other payables to affiliatesNotes payable to parent (Note 15)Commodity and other derivative contractual liabilities (Note 12)Margin deposits related to commodity positionsAccumulated deferred income taxes (Note 5)Accrued income taxes payable to parent (Note 15)Accrued taxes other than incomeAccrued interestOther current liabilitiesTotal current liabilitiesAccumulated deferred income taxes (Note 5)Commodity and other derivative contractual liabilities (Note 12)Notes or other liabilities due to affiliates (Note 15)Long-term debt held by affiliates (Note 15)Long-term debt, less amounts due currently (Note 8)Other noncurrent liabilities and deferred credits (Note 16)Total liabilitiesCommitments and Contingencies (Note 9)Equity (Note 10):$ 1,175 $120129710 760698 670393 4181,463 2,88371 56120 594,630 5,095947 947-- 922710 62918,556 19,2184,952 6,1521,781 1,826586 1,552811 999S 32,973 $ 37,3402,136 $774796 39389 553139 20981 57894 1,784600 1,06149 5331 7417 136407 394255 2665,094 5,4073,759 4,7121,556 1,6925 138382 38229,928 30,0762,643 2,64943,367 45,05684 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCONSOLIDATED BALANCE SHEETSDecember 31,Class A common stock (shares outstanding -both periods 2,062,768)Class B common stock (shares outstanding -both periods 39,192,594)Retained deficitAccumulated other comprehensive lossEFCH shareholder's equityNoncontrolling interests in subsidiariesTotal equityTotal liabilities and equity2012 2011(millions of dollars)383 3687,282 6,983(18,129) (15,121)(42) (49)(10,506) (7,819)112 103(10,394) (7,716)$ 32,973 $ 37,340See Notes to Financial Statements85 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYSTATEMENTS OF CONSOLIDATED EQUITY(Millions of Dollars)Class A common stock without par value -authorized shares -9,000,000:Balance at beginning of periodEffects of debt push-down from EFH Corp. (Note 8)Balance at end of period (shares outstanding for all periods presented-2,062,768)Class B common stock without par value -authorized shares -171,000,000:Balance at beginning of periodEffects of debt push-down from EFH Corp. (Note 8)Effects of stock-based incentive compensation plansGain on settlement of reimbursement agreement with OncorBalance at end of period (shares outstanding for all periods presented-39,192,594)Retained deficit:Balance at beginning of periodNet loss attributable to EFCHOtherBalance at end of periodAccumulated other comprehensive loss, net of tax effects (a):Balance at beginning of periodChange during the periodBalance at end of periodEFCH shareholder's equity at end of periodNoncontrolling interests in subsidiaries (Note 10):Balance at beginning of periodEffect of consolidation of TXU Receivables CompanyInvestment in subsidiary by noncontrolling interestsOtherNoncontrolling interests in subsidiaries at end of periodTotal equity at end of periodYear Ended December 31,2012 2011 2010368 358 28315 10 75383 368 3586,98329346,79318465,3681,41782 -7,282 6,983 6,793(15,121)(3,008)(13,319)(1,802)(9,790)(3,530)-- -- 1(18,129) (15,121) (13,319)(49) (68) (127)7 19 59(42) (49) (68)(10,506) (7,819) (6,236)10387164873272 -112 103 87S (10,394) S (7,716) $ (6,149)(a) All amounts relate to cash flow hedges.See Notes to Financial Statements.86 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIESDescription of BusinessReferences in this report to "we," "our," "us" and "the company" are to EFCH and/or its subsidiaries, as apparent in thecontext. See "Glossary" for defined terms.EFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. We conduct our operationsalmost entirely through our wholly-owned subsidiary, TCEH. TCEH is a holding company for subsidiaries engaged in competitiveelectricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodityrisk management and trading activities and retail electricity sales. Key management activities, including commodity riskmanagement and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently,there are no reportable business segments.TCEH operates largely in the ERCOT market, and wholesale electricity prices in that market have generally moved with theprice of natural gas. Wholesale electricity prices have significant implications to its profitability and cash flows and, accordingly,the value of its business.Liquidity ConsiderationsEFCH has been and is expected to continue to be adversely affected by the sustained decline in natural gas prices and itseffect on wholesale and retail electricity prices in ERCOT. Further, the remaining natural gas hedges that TCEH entered intowhen forward market prices of natural gas were significantly higher than current prices will mature in 2013 and 2014. Thesemarket conditions challenge the long-term profitability and operating cash flows of EFCH's and its subsidiaries' business and theability to support their significant interest payments and debt maturities, and could adversely impact their ability to obtain additionalliquidity and service, refinance and/or extend the maturities of their outstanding debt.Note 8 provides the details of EFCH's and its consolidated subsidiaries' short-term borrowings and long-term debt, includingprincipal amounts and maturity dates, as well as details of recent debt activity, including the three-year extension of the portionof the TCEH Revolving Credit Facility that would have expired in 2013. At December 31, 2012, TCEH had $1.2 billion of cashand cash equivalents and $183 million of available capacity under its letter of credit facility. Based on the current forecast of cashfrom operating activities, which reflects current forward market electricity prices, projected capital expenditures and other cashflows, including the settlement of the TCEH Demand Notes by EFH Corp., we expect that TCEH will have sufficient liquidity tomeets its obligations until October 2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures. TCEH'sability to satisfy this obligation is dependent upon the implementation of one or more of the actions described immediately below.EFCH and its subsidiaries continue to consider and evaluate possible transactions and initiatives to address their highlyleveraged balance sheets and significant cash interest requirements and may from time to time enter into discussions with theirlenders and bondholders with respect to such transactions and initiatives. These transactions and initiatives may include, amongothers, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equity exchangesor conversions, including exchanges or conversions of debt of EFCH and TCEH into equity of EFH Corp., EFCH, TCEH and/orany of their subsidiaries. These actions could result in holders of TCEH debt instruments not recovering the full principal amountof those obligations.Basis of PresentationThe consolidated fimancial statements have been prepared in accordance with US GAAP. See Note 7 for discussion of theprospective adoption, effective January 1, 2010, of amended guidance regarding transfers of financial assets that resulted in theaccounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding underthe program reported as short-term borrowings and the prospective adoption of amended guidance that required reconsiderationof consolidation conclusions for all variable interest entities (VIEs) that resulted in the consolidation, effective January 1, 2010of TXU Receivables Company. All intercompany items and transactions have been eliminated in consolidation. Any acquisitionsof outstanding debt for cash, including notes that had been issued in lieu of cash interest, are presented in the financing activitiessection of the statement of cash flows. All dollar amounts in the financial statements and tables in the notes are stated in millionsof US dollars unless otherwise indicated.87 Table of ContentsUse of EstimatesPreparation of financial statements requires estimates and assumptions about future events that affect the reporting of assetsand liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. Inthe event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods toreflect more current information.Derivative Instruments and Mark-to-Market AccountingWe enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities and alsoenter into other derivative instruments such as options, swaps, futures and forwards primarily to manage our commodity price andinterest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instrumentsand hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses,unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the balance sheet.This recognition is referred to as "mark-to-market" accounting. The fair values of our unsettled derivative instruments undermark-to-market accounting are reported in the balance sheet as commodity and other derivative contractual assets or liabilities.We report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements we havewith counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the balancesheet. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gainsand losses and derivative assets and liabilities are reversed. See Notes 11 and 12 for additional information regarding fair valuemeasurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accountingstandards related to derivative instruments and hedging activities, we may elect the "normal" purchase and sale exemption. Acommodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physicallyreceived or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accountedfor under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of thecontract until settlement.Because derivative instruments are frequently used as economic hedges, accounting standards related to derivativeinstruments and hedging activities allow for "hedge accounting," which provides for the designation of such instruments as cashflow or fair value hedges if certain conditions are met. A cash flow hedge mitigates the risk associated with the variability of thefuture cash flows related to an asset or liability (e.g., a forecasted sale of electricity in the future at market prices or the paymentof interest related to variable rate debt), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debtwith fixed interest rate payments). In accounting for changes in the fair value of cash flow hedges, derivative assets and liabilitiesare recorded on the balance sheet with an offset to other comprehensive income to the extent the hedges are effective and thehedged transaction remains probable of occurring. If the hedged transaction becomes probable of not occurring, hedge accountingis discontinued and the amount recorded in other comprehensive income is immediately reclassified into net income. If therelationship between the hedge and the hedged transaction ceases to exist or is dedesignated, hedge accounting is discontinued,and the amounts recorded in other comprehensive income are reclassified to net income as the previously hedged transactionimpacts net income. Changes in value of fair value hedges are recorded as derivative assets or liabilities with an offset to netincome, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset tonet income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or lossassociated with the hedge is amortized into income over the remaining life of the hedged item. In the statement of cash flow, theeffects of settlements of derivative instruments are classified consistent with the related hedged transactions.To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedgeditem. Assessment of the hedge's effectiveness is tested at least quarterly throughout its term to continue to qualify for hedgeaccounting. Changes in fair value that represent hedge ineffectiveness, even if the hedge continues to be assessed as effective,are immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the changein value of the hedging instrument over the change in value of the hedged item.At December 31, 2012 and 2011, there were no derivative positions accounted for as cash flow or fair value hedges.Accumulated other comprehensive income includes amounts related to interest rate swaps previously designated as cash flowhedges that are being reclassified to net income as the hedged transactions impact net income (see Note 8).88 Table of ContentsRealized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reportedin the income statement in net gain (loss) from commodity hedging and trading activities. In accordance with accounting rules,upon settlement of physical derivative sales and purchase contracts that are marked-to-market in net income, related wholesaleelectricity revenues and fuel and purchased power costs are reported at approximated market prices, instead of the contract price.As a result, this noncash difference between market and contract prices is included in the operating revenues and fuel and purchasedpower costs and delivery fees line items ofthe income statement, with offsetting amounts included in net gain (loss) from commodityhedging and trading activities.Revenue RecognitionWe record revenue from electricity sales under the accrual method of accounting. Revenues are recognized when electricityis provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earnedfrom the meter reading date to the end of the period (unbilled revenue).We report physically delivered commodity sales and purchases in the income statement on a gross basis in revenues andfuel, purchased power and delivery fees, respectively, and we report all other commodity related contracts and financial instruments(primarily derivatives) in the income statement on a net basis in net gain (loss) from commodity hedging and trading activities.As part of ERCOT's transition to a nodal wholesale market effective December 1, 2010, volumes under nontrading bilateralpurchase and sales contracts, including contracts intended as hedges, are no longer scheduled as physical power with ERCOT.Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, effective with thenodal market implementation, such contracts are reported net in the income statement in net gain (loss) from commodity hedgingand trading activities instead of reported gross as wholesale revenues or purchased power costs. As a result of the changes inwholesale market operations, effective with the nodal market implementation, if volumes delivered to our retail and wholesalecustomers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues,and if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record additional purchasedpower costs. The additional wholesale revenues or purchased power costs are offset in net gain (loss) from commodity hedgingand trading activities.Impairment of Long-Lived AssetsWe evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications ofimpairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are lessthan the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying valueexceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, ifapplicable. See Note 3 for discussion of impairments of intangible assets and mining-related assets in 2012 and 2011.Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives basedon the expected realization of economic effects. See Note 3 for additional information.Goodwill and Intangible Assets with Indefinite LivesWe evaluate goodwill and intangible assets with indefinite lives for impairment at least annually (at December 1). See Note3 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations and goodwillimpairments recorded in 2012, 2010 and 2009.Amortization of Nuclear FuelAmortization of nuclear fuel is calculated on the units-of-production method and is reported as fuel costs.Major MaintenanceMajor maintenance costs incurred during generation plant outages and the costs of other maintenance activities are chargedto expense as incurred and reported as operating costs.89 Table of ContentsDefined Benefit Pension Plans and OPEB PlansWe bear a portion of the costs of the EFH Corp. sponsored pension and OPEB plans offering pension benefits based oneither a traditional defined benefit formula or a cash balance formula to eligible employees and also offering certain health careand life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from thecompany. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. Undermultiemployer plan accounting, EFH Corp. has elected to not allocate retirement plan assets and liabilities to us. See Note 13 foradditional information regarding pension and OPEB plans, including a discussion of amendments to the EFH Corp. pension planapproved in August 2012.Stock-Based Incentive CompensationEFH Corp.'s 2007 Stock Incentive Plan authorizes discretionary grants to directors, officers and qualified managerialemployees of EFH Corp. or its affiliates of non-qualified stock options, stock appreciation rights, restricted shares, shares ofcommon stock, the opportunity to purchase shares of common stock and other stock-based awards. Stock-based compensationexpense is recognized over the vesting period based on the grant-date fair value of those awards. See Note 14 for informationregarding stock-based incentive compensation.Sales and Excise TaxesSales and excise taxes are accounted for as a "pass through" item on the balance sheet with no effect on the income statement;i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability tothe taxing jurisdiction.Franchise and Revenue-Based TaxesUnlike sales and excise taxes, franchise and gross receipt taxes are not a "pass through" item. These taxes are assessed tous by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as anexpense. Rates we charge to customers are intended to recover our costs, including the franchise and gross receipt taxes, but weare not acting as an agent to collect the taxes from customers.Income TaxesEFH Corp. files a consolidated federal income tax return; however, our income tax expense and related balance sheet amountsare recorded as if we file separate corporate income tax returns. Deferred income taxes are provided for temporary differencesbetween the book and tax basis of assets and liabilities as required under accounting rules. See Note 5.We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 4.Accounting for ContingenciesOur financial results may be affected byjudgments and estimates related to loss contingencies. Accruals for loss contingenciesare recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred andthat such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts andcircumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 9 for a discussion ofcontingencies.Cash and Cash EquivalentsFor purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity ofthree months or less are considered to be cash equivalents.Restricted CashThe terms of certain agreements require the restriction of cash for specific purposes. At December 31, 2012, $947 millionof cash was restricted to support letters of credit. See Notes 8 and 16 for more details regarding restricted cash.90 Table of ContentsProperty, Plant and EquipmentAs a result of purchase accounting, carrying amounts of property, plant and equipment were adjusted to estimated fair valuesat the Merger date. Subsequent additions have been recorded at cost. The cost of self-constructed property additions includesmaterials and both direct and indirect labor and applicable overhead, including payroll-related costs.Depreciation of our property, plant and equipment is calculated on a straight-line basis over the estimated service lives ofthe properties. Depreciation expense is calculated on a component asset-by-asset basis. Estimated depreciable lives are based onmanagement's estimates of the assets' economic useful lives. See Note 16.Asset Retirement ObligationsA liability is initially recorded at fair value for an asset retirement obligation associated with the retirement of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. These liabilities primarily relate to nucleargeneration plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatmentfacilities and generation plant asbestos removal and disposal costs. The obligation is initially measured at fair value. Over time,the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining usefullives of the assets. See Note 16.Capitalized InterestInterest related to qualifying construction projects and qualifying software projects is capitalized in accordance withaccounting guidance related to capitalization of interest cost. See Note 16.InventoriesInventories are reported at the lower of cost (on a weighted average basis) or market unless expected to be used in thegeneration of electricity. Also see discussion immediately below regarding environmental allowances and credits.Environmental Allowances and CreditsWe account for all environmental allowances and credits as identifiable intangible assets with finite lives that are subject toamortization. The recorded values of these intangible assets were originally established reflecting fair value determinations as ofthe date of the Merger under purchase accounting. Amortization expense associated with these intangible assets is recognized ona unit of production basis as the allowances or credits are consumed in generation operations. The environmental allowances andcredits are assessed for impairment when conditions or events occur that could affect the carrying value of the assets and areevaluated with the generation units to the extent they are planned to be consumed in generation operations. See Note 6 for detailsof impairment amounts recorded in 2011.InvestmentsInvestments in a nuclear decommissioning trust fund are carried at current market value in the balance sheet. Assets relatedto employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current marketvalue. See Note 16 for discussion of these and other investments.Noncontrolling InterestsSee Note 10 for discussion of accounting for noncontrolling interests in subsidiaries.Push-Down of EFH Corp. DebtIn accordance with SEC Staff Accounting Bulletin (SAB) Topic 5-J, we reflect amounts of certain EFH Corp. Senior Notesand EFH Corp. Senior Secured Notes on our balance sheet and the related interest expense in our income statement. The amountreflected on our balance sheet was calculated based upon the relative equity investment of EFCH and EFIH in their respectiveoperating subsidiaries at the time of the Merger (see Note 8).91 Table of ContentsFair Value of Nonderivative Financial InstrumentsThe carrying amounts of financial assets classified as current assets and the carrying amounts of financial liabilities classifiedas current liabilities approximate fair value due to the short maturity of such balances, which include cash equivalents, accountsreceivable and accounts payable.92 Table of Contents2. CONSOLIDATION OF VARIABLE INTEREST ENTITIESA variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level ofcontrol over the entity or results in economic risks to us. Accounting standards require consolidation of a VIE if we have (a) thepower to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (primarybeneficiary). In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decisionmaking processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationshipsamong the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE. There are nomaterial investments accounted for under the equity or cost method.Consolidated VIEsSee discussion in Note 7 regarding the VIE related to our accounts receivable securitization program that is consolidatedunder the accounting standards because TCEH owns and controls TXU Energy (the primary beneficiary ofTXU Energy ReceivablesCompany). We consolidated the previous program, which was terminated in November 2012, under the accounting standardsbecause TCEH (as the owner of TXU Energy) was the primary beneficiary of TXU Receivables Company, which is owned andcontrolled by our parent, EFH Corp.We also consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEHand Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existingComanche Peak nuclear-fueled generation facility using MHI's US-Advanced Pressurized Water Reactor technology and to obtaina combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries ofTCEH and MHI that hold 88% and 12% of CPNPC's equity interests, respectively (see Note 10).The carrying amounts and classifications of the assets and liabilities related to our consolidated VIEs are as follows:December 31, December 31, December 31, December 31,Assets: 2012 2011 Liabilities: 2012 2011Cash and cash equivalents $ 43 $ 10 Short-term borrowings $ 82 $ 104Accounts receivable 445 525 Trade accounts payable 1 1Property, plant and equipment 134 132 Other current liabilities 7 9Other assets, including $12million and $2 million ofcurrent assets 16 6Total assets $ 638 $ 673 Total liabilities $ 90 $ 114The assets of our consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of our consolidatedVIEs do not have recourse to our assets to settle the obligations of the VIE.93 Table of Contents3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETSGoodwillThe following table provides information regarding our goodwill balance. There were no changes to the goodwill balancefor the year ended December 31, 2011. None of the goodwill is being deducted for tax purposes.Goodwill before impairment charges $ 18,322Accumulated impairment charges through 2011 (a) (12,170)Balance at December 31, 2011 6,152Additional impairment charge in 2012 (1,200)Balance at December 31, 2012 (b) $ 4,952(a) Includes $4.1 billion recorded in 2010 and $8.070 billion largely recorded in 2008 as described below.(b) Net of accumulated impairment charges totaling $13.370 billion.Goodwill ImpairmentsGoodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (wehave selected a December 1 test date) or whenever events or changes in circumstances indicate an impairment may exist.Because our analyses indicate that the carrying value of TCEH exceeds its estimated fair value (enterprise value), we performthe following steps in testing goodwill for impairment: first, we estimate the debt-free enterprise value of the business as of thetesting date (December 1 for annual testing) taking into account future estimated cash flows and current securities values ofcomparable companies; second, we estimate the fair values of the individual operating assets and liabilities of the business at thatdate; third, we calculate "implied" goodwill as the excess of the estimated enterprise value over the estimated value of the netoperating assets; and finally, we compare the implied goodwill amount to the carrying value of goodwill and, if the carrying amountexceeds the implied value, we record an impairment charge for the amount the carrying value of goodwill exceeds implied goodwill.Changes in circumstances that we monitor closely include trends in natural gas prices. Wholesale electricity prices in theERCOT market, in which TCEH largely operates, have generally moved with natural gas prices as marginal electricity demandis generally supplied by natural gas-fueled generation facilities. Accordingly, declining natural gas prices, which we haveexperienced since mid-2008, negatively impact our profitability and cash flows and reduce the value of our generation assets,which consist largely of lignite/coal and nuclear-fueled facilities. While we have mitigated these effects with hedging activities,we are significantly exposed to this price risk. This market condition increases the risk of a goodwill impairment.Key inputs into our goodwill impairment testing at December 1, 2012 were as follows.* The carrying value (excluding debt) of TCEH exceeded its estimated enterprise value by approximately 40%.* Enterprise value was estimated using a two-thirds weighting ofvalue based on internally developed cash flow projectionsand a one-third weighting of value using implied cash flow multiples based on current securities values of comparablepublicly traded companies.The discount rate applied to internally developed cash flow projections was 9.25%. The discount rate represents theweighted average cost of capital consistent with the risk inherent in future cash flows, taking into account the capitalstructure, debt ratings and current debt yields of comparable public companies as well as an estimate of return on equitythat reflects historical market returns and current market volatility for the industry.* The cash flow projections assume rising wholesale electricity prices, though the forecasted electricity prices are lessthan those assumed in the cash flow projections used in the 2011 goodwill impairment testing.* Enterprise value based on internally developed cash flow projections reflected annual estimates through 2018, with aterminal year value calculated using the "Gordon Growth Formula."Changes in the above and other assumptions could materially affect the calculated amount of implied goodwill.94 Table of ContentsIn the fourth quarter 2012, we recorded a $1.2 billion noncash goodwill impairment charge. This amount represents our bestestimate of impairment pending finalization of the fair value calculations, which is expected in the first quarter 2013. The impairmentcharge reflected a decline in the estimated enterprise value of TCEH. The decline was due largely to lower wholesale electricityprices, reflecting the sustained decline in natural gas prices, and the maturing of positions in our natural gas hedge program, asreflected in our cash flow projections, as well as declines in market values of securities of comparable companies. The impairmenttest was based upon values at the December 1, 2012 test date.In the third quarter 2010, we recorded a $4.1 billion noncash goodwill impairment charge. The impairment charge reflecteda decline in the estimated enterprise value of TCEH. The decline was due largely to lower wholesale electricity prices, reflectingthe sustained decline in natural gas prices, as reflected in our cash flow projections, as well as declines in market values of securitiesof comparable companies. The impairment test was based upon values as of the July 31, 2010 test date.In the first quarter 2009, we completed the fair value calculations supporting a $8.070 billion goodwill impairment charge,substantially all of which was recorded in 2008. This charge was the first goodwill impairment recorded subsequent to the Mergerdate.The impairment determinations involved significant assumptions andjudgments. The calculations supporting the estimatesof the enterprise value of our business and the fair values of its operating assets and liabilities utilized models that take intoconsideration multiple inputs, including commodity prices, discount rates, debt yields, the effects of environmental rules, securitiesprices of comparable publicly traded companies and other inputs, assumptions regarding each of which could have a significanteffect on valuations. The fair value measurements resulting from these models are classified as non-recurring Level 3 measurementsconsistent with accounting standards related to the determination of fair value (see Note 11). Because of the volatility of thesefactors, we cannot predict the likelihood of any future impairment.Identifiable Intangible AssetsIdentifiable intangible assets reported in the balance sheet are comprised of the following:December 31, 2012December 31, 2011Identifiable Intangible AssetRetail customer relationshipFavorable purchase and sales contractsSoftware and other computer-relatedassetsEnvironmental allowances and credits (a)Mining development costsTotal intangible assets subject toamortizationRetail trade name (not subject toamortization)Mineral interests (not currently subject toamortization) (b)Total intangible assetsGross GrossCarrying Accumulated Carrying AccumulatedAmount Amortization Net Amount Amortization Net$ 463 $ 378 $ 85 $ 463 $ 344 S 119552 314 238 548 288 26032059411239320820124158279 162375 207163 82 81 140 55 85$ 2,092 $ 1,279813 $ 1,974 $ 1,141955833955131,78138$ 1,826(a) See discussion below regarding impairment of emission allowance intangible assets reported in other deductions in thethird quarter 2011 as a result of the EPA's issuance of the CSAPR in July 2011.(b) In 2012, we recorded an impairment charge (reported in other deductions) totaling $24 million related to certain mineralinterests whose fair value declined as a result of lower expected natural gas drilling activity and prices. The impairmentwas based on a Level 3 valuation (see Note 11).95 Table of ContentsAmortization expense related to intangible assets (including income statement line item) consisted of:Identifiable Intangible AssetRetail customer relationshipFavorable purchase and salescontractsSoftware and other computer-related assetsEnvironmental allowances andcreditsMining development costsTotal amortization expenseIncome Statement LineDepreciation andamortizationOperating revenues/fuel,purchased power costs anddelivery feesDepreciation andamortizationFuel, purchased power costsand delivery feesDepreciation andamortizationUseful lives atDecember 31, 2012 Year Ended December 31,(weighted average inyears) 2012 2011 20105 $ 34 $ 51 $ 78II525341831297135239225327 38 11$ 138 $ 220 $ 239Following is a description of the separately identifiable intangible assets recorded as part of purchase accounting for theMerger. The intangible assets were recorded at estimated fair value as of the Merger date, based on observable prices or estimatesof fair value using valuation models.* Retail customer relationship- Retail customer relationship intangible asset represents the fair value of the non-contractedcustomer base and is being amortized using an accelerated method based on customer attrition rates and reflecting theexpected pattern in which economic benefits are realized over their estimated useful life." Favorable purchase and sales contracts -Favorable purchase and sales contracts intangible asset primarily representsthe above market value of commodity contracts for which: (i) we had made the "normal" purchase or sale electionallowed by accounting standards related to derivative instruments and hedging transactions or (ii) the contracts did notmeet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of thecontracts. Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits(see Note 16)." Retail trade name -The trade name intangible asset represents the fair value of the TXU Energy trade name, and wasdetermined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairmentat least annually in accordance with accounting guidance related to goodwill and other intangible assets." Environmental allowances and credits -This intangible asset represents the fair value of environmental credits,substantially all of which were expected to be used in our power generation activities. These credits are amortizedutilizing a units-of-production method.EstimatedAmortization of Intangible Assets -The estimated aggregate amortization expense of intangible assets for eachof the next five fiscal years is as follows:Estimated AmortizationYear Expense2013 $ 1302014201520162017$$$$113102846696 Table of ContentsCross-State Air Pollution Rule Issued by the EPAIn July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR), compliance with which would have requiredsignificant additional reductions of sulfur dioxide (S02) and nitrogen oxide (NO.) emissions from our fossil-fueled generationunits. In order to meet the emissions reduction requirements by the dates mandated in July 2011, we determined it would benecessary to idle two of our lignite/coal-fueled generation units at our Monticello facility by the end of 2011, switch the fuel weuse at three lignite/coal-fueled generation units from a blend of Texas lignite and Wyoming Powder River Basin coal to 100 percentPowder River Basin coal, cease lignite mining operations that serve our Big Brown and Monticello generation facilities in the firstquarter 2012 and construct upgraded scrubbers at five of our lignite/coal-fueled generation units. The action plan to cease operationsat the mines required an evaluation of the remaining useful lives and recoverability of recorded values of tangible and intangibleassets related to the mines. This evaluation resulted in the recording of accelerated depreciation and amortization expense in thethird and fourth quarters of 2011 related to mine assets totaling $44 million. Also, in the third quarter 2011, we recorded assetimpairments totaling $9 million related to capital projects in progress at the mines.Additionally, because of emissions allowance limitations under the CSAPR, we would have had excess SO2 emissionallowances under the Clean Air Act's existing acid rain cap-and-trade program, and market values of such allowances were estimatedto be de minimis based on Level 3 fair value estimates, which are described in Note 11. Accordingly, we recorded a noncashimpairment charge of $418 million (before deferred income tax benefit) related to our existing SO2 emission allowance intangibleassets in the third quarter 2011. SO2 emission allowances granted to us were recorded as intangible assets at fair value in connectionwith purchase accounting related to the Merger in October 2007.In light of ajudicial stay of the CSAPR at the end of 2011 and the U.S. Court ofAppeals' for the District of Columbia CircuitAugust 2012 decision to vacate the CSAPR and remand it to the EPA for further proceedings (see Note 9), we did not idle the twoMonticello generation units at the end of 2011 and have continued mining lignite at the mines that serve the Big Brown andMonticello generation facilities.97 Table of Contents4. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXESAccounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed andassessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to theultimate outcome, regardless of whether this assessment is favorable or unfavorable.EFH Corp. and its subsidiaries file or have filed income tax returns in US federal, state and foreign jurisdictions and aresubject to examinations by the IRS and other taxing authorities. Examinations of income tax returns filed by EFH Corp. and anyof its subsidiaries for the years ending prior to January 1, 2007 are complete, but the tax years 1997 to 2006 remain in appealswith the IRS, with closing agreements reached on such appeals for tax years 1997 to 2002 currently under review by the IRS JointCommittee. Federal income tax returns are under examination for tax years 2007 to 2009. Texas franchise and margin tax returnsare under examination or still open for examination for tax years beginning after 2002.The EFH Corp. IRS audit for the years 2003 through 2006 was concluded in June 2011. A significant number of proposedadjustments are in appeals with the IRS. The results of the audit did not affect management's assessment of issues for purposesof determining the liability for uncertain tax positions.We classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded relatedto interest and penalties totaled an expense of $13 million and $15 million in 2012 and 2011, respectively, and a benefit of $8million in 2010 (all amounts after tax).Noncurrent liabilities included a total of $172 million and $151 million in accrued interest at December 31, 2012 and 2011,respectively. The federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferredincome taxes.The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in theconsolidated balance sheet, during the years ended December 31, 2012, 2011 and 2010:Year Ended December 31,2012 2011 2010Balance at January 1, excluding interest and penalties $ 1,069 $ 931 $ 903Additions based on tax positions related to prior years 19 80 26Reductions based on tax positions related to prior years (33) (6) (70)Additions based on tax positions related to the current year 23 64 72Balance at December 31, excluding interest and penalties $ 1,078 $ 1,069 $ 931Of the balance at December 31,2012, $1.010 billion represents tax positions for which the uncertainty relates to the timingof recognition in tax returns. The disallowance of such positions would not affect the effective tax rate, but could accelerate thepayment of cash to the taxing authority to an earlier period.With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should EFH Corp. sustainsuch positions on income tax returns previously filed, our liabilities recorded would be reduced by $68 million, and accrued interestwould be reversed resulting in a $11 million after-tax benefit, resulting in increased net income and a favorable impact on theeffective tax rate.Other than the items discussed above, we do not expect the total amount of liabilities recorded related to uncertain taxpositions will significantly increase or decrease within the next 12 months.98 Table of Contents5. INCOME TAXESEFH Corp. files a US federal income tax return that includes the results of EFCH and TCEH. EFH Corp. and its subsidiaries(including EFCH and TCEH) are bound by a Federal and State Income Tax Allocation Agreement, which provides, among otherthings, that each of EFCH, TCEH and any other subsidiaries under the agreement is required to make payments to EFH Corp. inan amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate taxreturn.The components of our income tax expense (benefit) are as follows:Year Ended December 31,2012 2011 2010Current:US FederalStateTotal currentDeferred:US FederalStateTotal deferredTotal$(7) $125 $(254)35 48 3928 173 (215)(932)(1,120)521(20) 4 12(952) (1,116) 533$ (924) $ (943) $ 318Reconciliation of income taxes computed at the US federal statutory rate to income tax expense:Loss before income taxesIncome taxes at the US federal statutory rate of 35%Nondeductible goodwill impairmentTexas margin tax, net of federal benefitLignite depletion allowanceProduction activities deductionInterest accrued for uncertain tax positions, net of taxNondeductible interest expenseReversal of previously disallowed interest resulting from debtexchangesOtherIncome tax expense (benefit)Effective tax rateYear Ended December 31,2012 2011 2010$ (3,932) $ (2,745) $ (3,212)$ (1,376) $ (961) $ (1,124)420 -1,4359 33 31(19) (23) (21)-(20) -14201514(1)(8)9(13)8 -9$ (924) $ (943) $ 31823.5% 34.4% (9.9)%99 Table of ContentsDeferred Income Tax BalancesDeferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2012 and 2011 areas follows:December 31, 2012 December 31,2011Total Current Noncurrent Total Current NoncurrentDeferred Income Tax AssetsAlternative minimum tax creditcarryforwardsNet operating loss (NOL)carryforwardsUnfavorable purchase and salescontractsDebt extinguishment gainsEmployee benefit obligationsAccrued interestOtherTotalDeferred Income Tax LiabilitiesProperty, plant and equipmentCommodity contracts and interestrate swapsIdentifiable intangible assetsDebt fair value discountsOtherTotalNet Deferred Income Tax Liability$ 222 $428-$ 222 $ 231 $-$ 231221749424282217494276762317485023174850235 235 184 -184130 -130 246 -2462,027 -2,027 1,766 -1,7664,353729522213-- 4,353316985222134,2861,373619217-4,28631 1,342-619-- 21718 18 -36 22 145,835 49 5,786 6,531 53 6,478$ 3,808 $ 49 $ 3,759 $ 4,765 $ 53 $ 4,712_ =At December 31, 2012, we had $222 million of alternative minimum tax credit carryforwards (AMT) available to offsetfuture tax payments. The AMT credit carryforwards have no expiration date. At December 31, 2012, we had net operating loss(NOL) carryforwards for federal income tax purposes of $1.223 billion that expire between 2028 and 2033. The NOL carryforwardscan be used to offset future taxable income. We expect to utilize all of our NOL carryforwards prior to their expiration dates.The income tax effects of the components included in accumulated other comprehensive income at December 31, 2012 and2011 totaled a net deferred tax asset of $23 million and $26 million, respectively.See Note 4 for discussion regarding accounting for uncertain tax positions.100 Table of Contents6. OTHER INCOME AND DEDUCTIONSYear Ended December 312012 2011 2010Other income:Consent fee related to novation of hedge positionsbetween counterpartiesInsurance/litigation settlementsSales tax refundsDebt extinguishment gainsSettlement of counterparty bankruptcy claims (a)Property damage claimFranchise tax refundGain on termination of long-term power sales contract(b)Gain on sale of land/water rightsGain on sale of interest in natural gas gathering pipelinebusinessAll otherTotal other incomeOther deductions:Charges related to pension plan actions (Note 13)Impairment of mineral interests (Note 3)Other asset impairmentsCounterparty contract settlementLoss on sales of landNet third-party fees paid in connection with theamendment and extension of the TCEH Senior SecuredFacilities (Note 8)Impairment of emission allowances (Note 3) (c)Impairment of assets related to mining operations (c)OtherTotal other deductions$6$2535687217611644--375 9 11$ 13 $ 48 $ 903$ 141 -- -24 --5 --4 --4 --186418 -9 -9 11 18$ 188 $ 524 $ 18(a) Represents net cash received as a result of the settlement of bankruptcy claims against a hedging/trading counterparty. Areserve of $26 million was established in 2008 related to amounts then due from the counterparty.(b) In November 2010, the counterparty to a long-term power sales agreement terminated the contract, which had a remainingterm of 27 years. The contract was a derivative and subject to mark-to-market accounting. The termination resulted in anoncash gain of $116 million, which represented the derivative liability as of the termination date.(c) Charges resulting from the EPA's issuance of the CSAPR in July 2011, including a $418 million impairment charge forexcess emission allowances and $9 million in mining asset write-offs (see Note 3).101 Table of Contents7. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAMIn November 2012, TCEH entered into a new accounts receivable securitization program, and EFH Corp. terminated theprevious program. Upon termination of the program, TXU Energy repurchased receivables previously sold and then sold themto TXU Energy Receivables Company, a new entity that is described below. Except as noted below, the new program is substantiallythe same as the terminated program.Under the program, TXU Energy (originator) sells all of its trade accounts receivable to TXU Energy Receivables Company,which is an entity created for the special purpose of purchasing receivables from the originator and is a consolidated, wholly-owned, bankruptcy-remote subsidiary of TCEH. TXU Energy Receivables Company borrows funds from entities established forthis purpose by the participating financial institutions (funding entities) using the accounts receivable as collateral. A directsubsidiary of EFH Corp. with similar characteristics performed these functions under the terminated program by selling undividedinterests in the purchased accounts receivable to the funding entities.The trade accounts receivable amounts under the program are reported in the financial statements as pledged balances, andthe related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the program activity was accountedfor as a sale of accounts receivable, under accounting rules then applicable to the program, which resulted in the funding beingrecorded as a reduction of accounts receivable.The maximum funding amount currently available under the program is $200 million, which approximates the expectedusage and applies only to receivables related to non-executory retail sales contracts, as compared to $350 million under theterminated program. Program funding decreased to $82 million at December 31, 2012 from $104 million at December 31, 2011.Because TCEH's credit ratings were lower than Ba3/BB-, under the terms of the program, available funding is reduced by theamount of customer deposits held by the originator, which totaled $36 million at December 31, 2012.TXU Energy Receivables Company issues a subordinated note payable to the originator for the difference between the faceamount of the accounts receivable purchased, less a discount, and cash paid to the originator. Because the subordinated note islimited to 25% of the uncollected accounts receivable purchased, and the amount of borrowings are limited by terms of the financingagreement, any additional funding to purchase the receivables is sourced from cash on hand and/or capital contributions fromTCEH. Under the program, the subordinated note issued by TXU Energy Receivables Company is subordinated to the securityinterests ofthe funding entities. There was no subordinated note limit under the terminated program. The balance ofthe subordinatednote payable, which is eliminated in consolidation, totaled $97 million and $420 million at December 31, 2012 and December 3 1,2011, respectively.All new trade receivables under the program generated by the originator are continuously purchased by TXU EnergyReceivables Company with the proceeds from collections of receivables previously purchased and, as necessary, increasedborrowings or funding sources as described immediately above. Changes in the amount ofborrowings by TXU Energy ReceivablesCompany reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such aschanges in sales prices and volumes.The discount from face amount on the purchase of receivables from the originator principally funds program fees paid tothe funding entities. The program fees consist primarily of interest costs on the underlying financing and are reported as interestexpense and related charges. The discount also funds a servicing fee, which is reported as SG&A expense, paid by TXU EnergyReceivables Company to TXU Energy, which provides recordkeeping services and is the collection agent under the program.Program fee amounts were as follows:Year Ended December 31,2012 2011 2010Program fees $9 $9 $10Program fees as a percentage of average funding(annualized) 6.7% 6.4% 3.8%102 Table of ContentsActivities of TXU Energy Receivables Company and TXU Receivables Company were as follows:Year Ended December 31,2012 2011 2010Cash collections on accounts receivable $ 4,566 $ 5,080 $ 6,334Face amount of new receivables purchased (4,496) (4,992) (6,100)Discount from face amount of purchased receivables 11 11 12Program fees paid to funding entities (9) (9) (10)Servicing fees paid for recordkeeping and collection services (2) (2) (2)Increase (decrease) in subordinated notes payable (323) (96) 53Capital contribution from TCEH, net of cash held 275 --Cash flows used by (provided to) originator under the program S 22 $ (8) $ 287Under the previous accounting rules, changes in funding under the program were reported as operating cash flows. Theaccounting rules effective January 1, 2010 required that the amount of funding under the program as of the adoption date ($383million) be reported as a use of operating cash flows and a source of financing cash flows, with all subsequent changes in fundingreported as financing activities.The new program extends the expiration date by two years to November 2015, provided that the expiration date will changeto June 2014 if at that time more than $500 million aggregate principal amount of the term loans and deposit letter of credit loansunder the TCEH Senior Secured Facilities maturing prior to October 2017 remain outstanding. The new program is subject to thesame financial maintenance covenant as the TCEH Senior Credit Facilities as discussed in Note 8. The program may be terminatedupon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the soldreceivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputesand other allowances) or the days outstanding ratio exceed stated thresholds, unless the funding entities waive such events oftermination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXUEnergy Receivables Company defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities,or if EFH Corp., TCEH, any affiliate of TCEH acting as collection agent, any parent guarantor of the originator or the originatordefaults in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for suchentities. At December 31, 2012, there were no such events of termination.If the program was terminated, TCEH's liquidity would be reduced because collections of sold receivables would be usedby TXU Energy Receivables Company to repay borrowings from the funding entities instead of purchasing new receivables. Weexpect that the level of cash flows would normalize in approximately 16 to 30 days following termination.Trade Accounts ReceivableDecember 31,2012 2011Wholesale and retail trade accounts receivable, including $454 and $524 in pledgedretail receivables $ 719 $ 787Allowance for uncollectible accounts (9) (27)Trade accounts receivable -reported in balance sheet $ 710 $ 760Gross trade accounts receivable at December 31,2012 and 2011 included unbilled revenues of $260 million and $269 million,respectively.103 Table of ContentsAllowance for Uncollectible Accounts ReceivableAllowance for uncollectible accounts receivable at beginning of period $Increase for bad debt expenseDecrease for account write-offsReversal of reserve related to counterparty bankruptcy (Note 6)Allowance for uncollectible accounts receivable at end of period $Year Ended December 31,2012 2011 201027 $ 64 $ 8126(44)56(67)108(125)-(26) -9 $ 27 $ 64104 Table of Contents8. SHORT-TERM BORROWINGS AND LONG-TERM DEBTShort-Term BorrowingsAt December 31, 2012, outstanding short-term borrowings totaled $2.136 billion, which included $2.054 billion under theTCEH Revolving Credit Facility at a weighted average interest rate of 4.40%, excluding customary fees, and $82 million underthe accounts receivable securitization program discussed in Note 7.At December 31, 2011, outstanding short-term borrowings totaled $774 million, which included $670 million under theTCEH Revolving Credit Facility at a weighted average interest rate of 4.46%, excluding certain customary fees, and $104 millionunder the accounts receivable securitization program.Credit FacilitiesCredit facilities with cash borrowing and/or letter of credit availability at December 31, 2012 are presented below. Thefacilities are all senior secured facilities of TCEH.December 31, 2012Letters of CashFacility Maturity Date Facility Limit Credit Borrowings AvailabilityTCEH Revolving Credit Facility (a) October 2013 $ 645 $ -$ 645 $ -TCEH Revolving Credit Facility (a) October 2016 1,409 -1,409TCEH Letter of Credit Facility (b) October 2017 (b) 1,062 1,062 --Total TCEH $ 3,116 $ -$ 3,116 $ -(a) Facility used for borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. AtDecember 31, 2012, borrowings under the facility maturing October 2013 bear interest at LIBOR plus 3.50%, and acommitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion ofthe facility. At December 31, 2012, borrowings under the facility maturing October 2016 bear interest at LIBOR plus4.50%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 1.00% of the average daily unusedportion of the facility. In January 2013, commitments maturing in 2013 were extended to 2016 as discussed below.(b) Facility, $42 million of which matures in October 2014, used for issuing letters of credit for general corporate purposes,including, but not limited to, providing collateral support under hedging arrangements and other commodity transactionsthat are not secured by a first-lien interest in the assets of TCEH. The borrowings under this facility have been recordedby TCEH as restricted cash that supports issuances of letters of credit and are classified as long-term debt. At December31, 2012, the restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009 relatedto an office building financing. At December 31, 2012, the restricted cash supports $764 million in letters of creditoutstanding, leaving $183 million in available letter of credit capacity.Amendment and Extension of TCEH Revolving Credit Facility -In January 2013, the Credit Agreement governing theTCEH Senior Secured Facilities was amended to extend the maturity date of the $645 million of commitments maturing in October2013 to October 2016, bringing the maturity date of the entire commitment of $2.054 billion to October 2016. The extendedcommitments will have the same terms and conditions as the existing commitments expiring in October 2016 under the CreditAgreement. Fees in consideration for the extension were settled through the incurrence of $340 million principal amount ofincremental TCEH Term Loan Facilities maturing in October 2017. In connection with the extension request, TCEH eliminatedits ability to draw letters of credit under the TCEH Revolving Credit Facility. At the date of the extension, there were no outstandingletters of credit under the TCEH Revolving Credit Facility.105 Table of ContentsLone-Terin DebtAt December 31, 2012 and 2011, long-term debt consisted of the following:TCEHSenior Secured Facilities:3.746% TCEH Term Loan Facilities maturing October 10, 2014 (a)(b)3.712% TCEH Letter of Credit Facility maturing October 10, 2014 (b)4.746% TCEH Term Loan Facilities maturing October 10, 2017 (a)(b)(c)4.712% TCEH Letter of Credit Facility maturing October 10, 2017 (b)11.5% Fixed Senior Secured Notes due October 1, 202015% Fixed Senior Secured Second Lien Notes due April 1, 202115% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B10.25% Fixed Senior Notes due November 1, 2015 (c)10.25% Fixed Senior Notes due November 1, 2015, Series B (c)10.50 / 11.25% Senior Toggle Notes due November 1, 2016Pollution Control Revenue Bonds:Brazos River Authority:5.40% Fixed Series 1994A due May 1, 20297.70% Fixed Series 1999A due April 1, 20336.75% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (e)7.70% Fixed Series 1999C due March 1, 20328.25% Fixed Series 2001A due October 1, 20308.25% Fixed Series 2001D-1 due May 1, 20330.143% Floating Series 2001D-2 due May 1, 2033 (f)0.400% Floating Taxable Series 20011 due December 1, 2036 (g)0. 143% Floating Series 2002A due May 1, 2037 (f)6.75% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (e)6.30% Fixed Series 2003B due July 1, 20326.75% Fixed Series 2003C due October 1, 20385.40% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (e)5.00% Fixed Series 2006 due March 1, 2041Sabine River Authority of Texas:6.45% Fixed Series 2000A due June 1, 20215.20% Fixed Series 2001C due May 1, 20285.80% Fixed Series 2003A due July 1, 20226.15% Fixed Series 2003B due August 1, 2022Trinity River Authority of Texas:6.25% Fixed Series 2000A due May 1, 2028Unamortized fair value discount related to pollution control revenue bonds (h)Other:7.46% Fixed Secured Facility Bonds with amortizing payments through January 20157% Fixed Senior Notes due March 15, 2013Capital leasesOtherUnamortized discountUnamortized fair value discount (h)Total TCEHDecember 31,2012 20113,809 $ 3,80942 4215,370 15,3701,020 1,0201,750 1,750336 3361,235 1,2352,046 2,0461,442 1,4421,749 1,56839 39111 11116 1650 5071 71171 17197 9762 6245 4544 4439 3952 5231 31100 10051 5170 7012 1245 4514 14(112) (120)12 285 564 633 3(10) (11)(1) (1)29,880 29,705106 Table of ContentsDecember 31,2012 2011EFCH (parent entity)9.58% Fixed Notes due in annual installments through December 4, 2019 (i)8.254% Fixed Notes due in quarterly installments through December 31, 2021 (i)1.113% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (b)8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037Unamortized fair value discount (h)SubtotalEFH Corp. debt pushed down (i)10% Fixed Senior Secured First Lien Notes due January 15, 20209.75% Fixed Senior Secured First Lien Notes due October 15, 201910.875% Fixed Senior Notes due November 1, 201711.25 / 12.00% Senior Toggle Notes due November 1, 2017Unamortized premiumSubtotal -EFH Corp. debt pushed downTotal EFCH (parent entity)Total EFCH consolidatedLess amount due currentlyLess amount held by affiliates (Note 15)Total long-term debt353918414318(7) (8)76 8533058323033058982183450 707526 79230,406 30,497(96) (39)(382) (382)$ 29,928 $ 30,076(a) Interest rate swapped to fixed on $18.46 billion principal amount of maturities through October 2014 and up to an aggregate$12.6 billion principal amount from October 2014 through October 2017.(b) Interest rates in effect at December 31, 2012.(c) As discussed below and in Note 15, principal amounts of notes/term loans totaling $382 million at both December 31, 2012and 2011 were held by EFH Corp. and EFIH.(d) Interest rate in effect at December 31, 2012, excluding a quarterly maintenance fee of $11 million. See "Credit Facilities"above for more information.(e) These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatoryremarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.(f) Interest rates in effect at December 31, 2012. These series are in a daily interest rate mode and are classified as long-termas they are supported by long-term irrevocable letters of credit.(g) Interest rate in effect at December 31, 2012. This series is in a weekly interest rate mode and is classified as long-term asit is supported by long-term irrevocable letters of credit.(h) Amount represents unamortized fair value adjustments recorded under purchase accounting.(i) EFCH's obligations with respect to these financings are guaranteed by EFH Corp. and secured on a first-priority basis by,among other things, an undivided interest in the Comanche Peak nuclear generation facility.(j) Represents 50% of the amount of these EFH Corp. securities guaranteed by, and pushed down to (pushed-down debt), EFCH(parent entity) per the discussion below under "Guarantees and Push Down of EFH Corp. Debt."Debt Amounts Due CurrentlyAmounts due currently (within twelve months) at December 31, 2012 total $96 million and consist of $60 million principalamount of TCEH pollution control revenue bonds (PCRBs) subject to mandatory tender and remarketing in April 2013, which weexpect to repurchase in April 2013, and $36 million of scheduled installment payments on capital leases and debt securities.107 Table of ContentsDebt Related Activity in 2013Issuance of EFIH 10% Senior Secured Notes and EFIH 11.25 %/12.25% Toggle Notes in Exchange for EFH Corp. DebtGuaranteed by EFCH -In exchanges in January 2013, EFIH and EFIH Finance issued $1.302 billion principal amount of EFIH10% Senior Secured Notes due 2020 (EFIH 10% Notes) for $1.310 billion total principal amount of EFH Corp. and EFIH seniorsecured notes consisting of: (i) $113 million principal amount of EFH Corp. 9.75% Senior Secured Notes due 2019 (EFH Corp.9.75% Notes), (ii) $1.058 billion principal amount of EFH Corp. 10% Senior Secured Notes due 2020 (EFH Corp. 10% Notes),and (iii) $139 million principal amount of EFIH senior secured notes.In connection with these debt exchange transactions, EFH Corp. received the requisite consents from holders of the EFHCorp. 9.75% Notes and EFH Corp. 10% Notes applicable to certain amendments to the respective indentures governing suchnotes. These amendments, among other things, made EFCH and EFIH unrestricted subsidiaries under the EFH Corp. 9.75% Notesand EFH Corp. 10% Notes, thereby eliminating EFCH's and EFIH's guarantees of the notes.In additional exchanges in January 2013, EFIH and EFIH Finance issued $89 million principal amount of 11.25%/12.25%Toggle Notes due 2018 (EFIH Toggle Notes) for $95 million total principal amount of EFH Corp. senior notes consisting of: (i)$31 million principal amount of EFH Corp. 10.875% Senior Notes due 2017 (EFH Corp. 10.875% Notes), (ii) $33 million principalamount of EFH Corp. 11.25%/12.00% Senior Toggle Notes due 2017 (EFH Corp. Toggle Notes) and (iii) $31 million principalamount of other EFH Corp. unsecured debt.Largely in early 2013, EFIH returned $6.518 billion principal amount of EFH Corp. debt guaranteed by EFCH that EFIHreceived in debt exchanges as a dividend to EFH Corp., which cancelled it. The debt returned included $1.754 billion principalamount of EFH Corp. 10.875% Notes, $3.593 billion principal amount of EFH Corp. Toggle Notes, $1.058 billion principal amountof EFH Corp. 10% Notes and $113 million principal amount of EFH Corp. 9.75% Notes.After these early 2013 transactions, EFCH guarantees only $60 million principal amount of EFH Corp. debt as discussedbelow in "Guarantees and Push Down of EFH Corp. Debt."Debt RelatedActivity in 2012Repayments of long-term debt in the year ended December 31, 2012 totaled $40 million and consisted of $26 million ofpayments of principal at scheduled maturity dates and $14 million of contractual payments under capital leases.Issuance of EFIH Toggle Notes in Exchange for EFH Corp. Debt Guaranteed by EFCH -In exchanges in December2012, EFIH and EF1H Finance issued $1.304 billion principal amount of EFIH Toggle Notes in exchange for $1.761 billion totalprincipal amount of EFH Corp. debt consisting of $132 million of EFH Corp. 10.875% Notes, $432 million of EFH Corp. ToggleNotes and $1.197 billion of other EFH Corp. unsecured debt. The EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes inthese exchanges were guaranteed by EFCH as discussed below in "Guarantees and Push Down of EFH Corp. Debt."Debt Related Activity in 2011Issuances of debt for cash in 2011 consisted of the $1.750 billion principal amount of TCEH 11.5% Senior Secured Notesdiscussed below (net proceeds of $1.703 billion).Repayments of long-term debt in 2011 totaled $1.408 billion and included $958 million of long-term debt borrowings underthe TCEH Senior Secured Facilities as discussed below, $437 million of principal payments at scheduled maturity or remarketingdates (including $415 million of pollution control revenue bonds) and $13 million of contractual payments under capitalized leaseobligations. In addition, short-term borrowings of $455 million under the TCEH Revolving Credit Facility were repaid.108 Table of ContentsAmendment and Extension of TCEH Senior Secured Facilities -Borrowings under the TCEH Senior Secured Facilitiestotaled $22.295 billion at December 31, 2012 and consisted of:* $3.809 billion of TCEH Term Loan Facilities maturing in October 2014 with interest payable at LIBOR plus 3.50%;* $15.370 billion of TCEH Term Loan Facilities maturing in October 2017 with interest payable at LIBOR plus 4.50%;* $42 million of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2014 with interest payableat LIBOR plus 3.50% (see discussion under "Credit Facilities" above);* $1.020 billion of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2017 with interest payableat LIBOR plus 4.50% (see discussion under "Credit Facilities" above), and* Amounts borrowed under the TCEH Revolving Credit Facility, which may be reborrowed from time to time until October2016 and represent the entire amount of commitments under the facility totaling $2.054 billion at December 31, 2012.See "Credit Facilities" above for discussion regarding the $645 million in commitments maturing in 2013 that wereextended to 2016 in January 2013.The TCEH Commodity Collateral Posting Facility, under which there were no borrowings in 2012, matured in December2012.In April 2011, (i) the Credit Agreement governing the TCEH Senior Secured Facilities was amended, (ii) the maturity datesof approximately 80% of the borrowings under the term loans (initial term loans and delayed draw term loans) and deposit letterof credit loans under the TCEH Senior Secured Facilities and approximately 70% of the commitments under the TCEH RevolvingCredit Facility were extended, (iii) borrowings totaling $1.604 billion under the TCEH Senior Secured Facilities were repaid fromproceeds of issuance of $1.750 billion principal amount of TCEH 11.5% Senior Secured Notes as discussed below and (iv) theamount of commitments under the TCEH Revolving Credit Facility was reduced by $646 million.The amendment to the Credit Agreement included, among other things, amendments to certain covenants contained in theTCEH Senior Secured Facilities (including the financial maintenance covenant), as well as acknowledgment by the lenders that(i) the terms of the intercompany notes receivable (as described below) from EFH Corp. payable to TCEH complied with theTCEH Senior Secured. Facilities, including the requirement that these loans be made on an "arm's-length" basis, and (ii) nomandatory repayments were required to be made by TCEH relating to "excess cash flows," as defined under covenants of theTCEH Senior Secured Facilities, for fiscal years 2008, 2009 and 2010.As amended, the maximum ratios for the secured debt to Adjusted EBITDA financial maintenance covenant are 8.00 to 1.00for test periods through December 31, 2014, and decline over time to 5.50 to 1.00 for the test periods ending March 31, 2017 andthereafter. In addition, (i) up to $1.5 billion principal amount of TCEH senior secured first lien notes (including $906 million ofthe TCEH Senior Secured Notes discussed below), to the extent the proceeds are used to repay term loans and deposit letter ofcredit loans under the TCEH Senior Secured Facilities and (ii) all senior secured second lien debt will be excluded for the purposesof the secured debt to Adjusted EBITDA financial maintenance covenant.The amendment contained certain provisions related to TCEH Demand Notes that arise from cash loaned for (i) debt principaland interest payments (P&I Note) and (ii) other general corporate purposes of EFH Corp. (SG&A Note). TCEH also agreed inthe Amendment:" not to make any further loans to EFH Corp. under the SG&A Note (at December 31, 2012, the outstanding balance ofthe SG&A Note was $233 million, reflecting the repayment discussed below);" that borrowings outstanding under the P&I Note will not exceed $2.0 billion in the aggregate at any time (at December 31,2012, the outstanding balance of the P&I Note was $465 million), and" that the sum of(i) the outstanding indebtedness (including guarantees) issued by EFH Corp. or any subsidiary of EFHCorp. (including EFIH) secured by a second-priority lien on the equity interests that EFIH owns in Oncor Holdings(EFIH Second-Priority Debt) and (ii) the aggregate outstanding amount of the SG&A Note and P&I Note will not exceed,at any time, the maximum amount of EFIH Second-Priority Debt permitted by the indenture governing the EFH Corp.10% Notes as in effect on April 7, 2011.Further, in connection with the amendment, in April 2011 the following actions were completed related to the intercompanyloans:* EFH Corp. repaid $770 million of borrowings under the SG&A Note (using proceeds from TCEH's repayment of the$770 million TCEH borrowed from EFH Corp. in January 2011 under a demand note), and* EFIH and EFCH guaranteed, on an unsecured basis, the remaining balance of the SG&A Note (consistent with theexisting EFIH and EFCH unsecured guarantees of the P&I Note and the EFH Corp. Senior Notes discussed below).109 Table of ContentsPursuant to the extension of the TCEH Senior Secured Facilities in April 2011:" the maturity of$15.370 billion principal amount of first lien term loans held by accepting lenders (including $19 millionof term loans held by EFH Corp.) was extended from October 10, 2014 to October 10, 2017 and the interest rate withrespect to the extended term loans was increased from LIBOR plus 3.50% to LIBOR plus 4.50%;* the maturity of S 1.020 billion principal amount of first lien deposit letter of credit loans held by accepting lenders wasextended from October 10, 2014 to October 10, 2017 and the interest rate with respect to the extended deposit letter ofcredit loans was increased from LIBOR plus 3.50% to LIBOR plus 4.50%, and" the maturity of $1.409 billion of the commitments under the TCEH Revolving Credit Facility held by accepting lenderswas extended from October 10, 2013 to October 10, 2016, the interest rate with respect to the extended revolvingcommitments was increased from LIBOR plus 3.50% to LIBOR plus 4.50% and the undrawn fee with respect to suchcommitments was increased from 0.50% to 1.00%.Upon the effectiveness of the extension, TCEH paid an up-front extension fee of 350 basis points on extended term loansand extended deposit letter of credit loans.Each of the loans described above that matures in 2016 or 2017 includes a "springing maturity" provision pursuant to which(i) in the event that more than $500 million aggregate principal amount of the TCEH 10.25% Notes due in 2015 (other than notesheld by EFH Corp. or its controlled affiliates at March 31,2011 to the extent held at the determination date as defined in the CreditAgreement) or more than $150 million aggregate principal amount of the TCEH Toggle Notes due in 2016 (other than notes heldby EFH Corp. or its controlled affiliates at March 31, 2011 to the extent held at the determination date as defined in the CreditAgreement), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (ii) TCEH'stotal debt to Adjusted EBITDAratio (as defined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at the applicabledetermination date, then the maturity date of the extended loans will automatically change to 90 days prior to the maturity dateof the applicable notes.Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are severaland not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH's available liquidity could be reduced by an amountup to the aggregate amount of such lender's commitments under the TCEH Senior Secured Facilities.The TCEH Senior Secured Facilities are fully and unconditionally guaranteed jointly and severally on a senior secured basisby EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US subsidiary of TCEH.The TCEH Senior Secured Facilities, along with the TCEH Senior Secured Notes and certain commodity hedging transactionsand the interest rate swaps described under "TCEH Interest Rate Swap Transactions" below, are secured on a first priority basisby (i) substantially all of the current and future assets of TCEH and TCEH's subsidiaries who are guarantors of such facilities and(ii) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.The TCEH Senior Secured Facilities contain customary negative covenants that, among other things, restrict, subject tocertain exceptions, TCEH and its restricted subsidiaries' ability to:* incur additional debt;* create additional liens;" enter into mergers and consolidations;* sell or otherwise dispose of assets;" make dividends, redemptions or other distributions in respect of capital stock;" make acquisitions, investments, loans and advances, and" pay or modify certain subordinated and other material debt.The TCEH Senior Secured Facilities contain certain customary events of default for senior leveraged acquisition fimancings,the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.110 Table of ContentsAccounting and Income Tax Effects of the Amendment and Extension -Based on application of the accounting rules,including analyses ofdiscounted cash flows, the amendment and extension transactions were determined not to be an extinguishmentof debt. Accordingly, no gain was recognized, and transaction costs totaling $699 million, consisting of consent and extensionpayments to loan holders, were capitalized. Amounts capitalized will be amortized to interest expense through the maturity datesof the respective loans. Net third party fees related to the amendment and extension totaling $86 million were expensed (see Note6).The transactions were determined to be a significant modification of debt for federal income tax purposes, resulting in taxablecancellation of debt income of approximately $2.5 billion. The income will be reversed as deductions in future years (through2017), and consequently a deferred tax asset has been recorded. The effect of the income on federal income taxes payable relatedto 2011 was largely offset by current year deductions, including the impact of bonus depreciation, and utilization of approximately$660 million in operating loss carryforwards. The transactions resulted in a cash charge under the Texas margin tax of$13 million(reported as income tax expense).Issuance of TCEH 11.5% Senior Secured Notes -In April 2011, TCEH and TCEH Finance issued $1.750 billion principalamount of 11.5% Senior Secured Notes due 2020, and used the proceeds, net of issuance fees and a $12 million discount, to:" repay $770 million principal amount of term loans under the TCEH Senior Secured Facilities (representing amortizationpayments that otherwise would have been paid from March 2011 through September 2014, including $1 million of termloans held by EFH Corp.);" repay $188 million principal amount of deposit letter of credit loans under the TCEH Senior Secured Facilities;" repay $646 million of borrowings under the TCEH Revolving Credit Facility (with commitments under the facility beingreduced by the same amount), and" fund $99 million of the $785 million of total transaction costs associated with the amendment and extension of theTCEI Senior Secured Facilities discussed above, with the remainder of the transaction costs paid with cash on hand,including the proceeds from EFH Corp.'s payment on the SG&A Note discussed above.Issuance of EFIH 11% Senior Secured Second Lien Notes in Exchange for EFH Corp. Debt -In April 2011, EFIH andEFIH Finance issued $406 million principal amount of 11% Senior Secured Second Lien Notes due 2021 in exchange for $428million of EFH Corp. debt consisting of $163 million principal amount of EFH Corp. 10.875% Notes due 2017, $229 millionprincipal amount of EFH Corp. Toggle Notes due 2017 and $36 million principal amount of EFH Corp. 5.55% Series P SeniorNotes due 2014 (EFH Corp. 5.55% Notes). Prior to the exchange, 50% of the outstanding EFH Corp. 10.875% Notes and ToggleNotes had been pushed down to EFCH for reporting purposes.October 2011 EFH Corp. Debt Exchange -In a private exchange in October 2011, EFH Corp. issued $53 million principalamount of new EFH Corp. Toggle Notes in exchange for $65 million principal amount of EFH Corp. 5.55% Notes. The new EFHCorp. Toggle Notes, which were subject to push down to our balance sheet, had substantially the same terms and conditions andwere subject to the same indenture as the existing EFH Corp. Toggle Notes. A premium totaling $6 million was recorded on thetransaction and was being amortized to interest expense over the life of the new notes until the notes were acquired in the December2012 debt exchanges discussed above. Concurrent with the exchange, EFIH returned $53 million principal amount of EFH Corp.Toggle Notes that it had received in prior debt exchange transactions as a dividend to EFH Corp., which cancelled the notes.2011 EF1I Corp. Debt Repurchases -In the fourth quarter 2011, EFH Corp. repurchased $40 million principal amount ofTCEH 10.25% Notes due 2015 and $7 million principal amount of EFH Corp. 5.55% Notes in private transactions for $20 millionin cash. EFH Corp. retired the 5.55% Notes and held the TCEH 10.25% Notes as an investment.111 Table of ContentsMaturitiesLong-term debt maturities at December 31, 2012 are as follows:Year2013 (a) $ 842014 (a) 3,9332015 (a) 3,6592016 (a) 1,9192017 (a) (b) 16,115Thereafter (a) 4,762Unamortized discounts (c) (130)Capital lease obligations 64Total $ 30,406(a) Long-term debt maturities for EFCH (parent entity), including pushed down debt, total $11 million, $12 million, $13 million,$15 million, $69 million and $413 million for 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.(b) TCEH Senior Secured Facilities due in 2017 are subject to a "springing maturity" provision as discussed above.(c) Unamortized fair value discounts for EFCH (parent entity) total $7 million.Guarantees and Push Down of EFH Corp. DebtMerger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing at the time of the Merger. Debtissued in exchange for Merger-related debt is considered Merger-related. Debt issuances are considered Merger-related debt tothe extent the proceeds are used to repurchase Merger-related debt. Merger-related debt of EFH Corp. (parent) that is fully andunconditionally guaranteed on ajoint and several basis by EFIH and EFCH (parent entity) is subject to push down in accordancewith SEC Staff Accounting Bulletin Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected inour financial statements. Merger-related debt of EFH Corp. held as an investment by its subsidiaries is not subject to push down.The amount reflected in our balance sheet as pushed down debt ($450 million and $707 million at December 31, 2012 and2011, respectively, as shown in the long-term debt table above) represents 50% of the principal amount (plus unamortized premium)of the EFH Corp. Merger-related debt guaranteed by EFCH (parent entity). This percentage reflects the fact that at the time ofthe Merger, the equity investments of EFCH (parent entity) and EFIH in their respective operating subsidiaries were essentiallyequal amounts. Because payment of principal and interest on the debt is the responsibility of EFH Corp., we record the settlementof such amounts as noncash capital contributions from EFH Corp.112 Table of ContentsThe tables below present, at December 31, 2012 and 2011, an analysis of the total outstanding principal amount of EFHCorp. debt that EFCH (parent entity) and EFIH have guaranteed (fully and unconditionally on a joint and several basis), as (i)amounts that EFIH held as an investment, (ii) amounts held by nonaffiliates subject to push down to our balance sheet and (iii)amounts held by nonaffiliates that are not Merger-related. As discussed in note (a) to the December 31, 2012 table below, as aresult of transactions in early 2013, debt guaranteed now totals only $60 million. The guarantee is not secured.December 31, 2012Securities Guaranteed (principal amounts)EFH Corp. 9.75% and 10% Senior Secured NotesEFH Corp. 10.875% Senior NotesEFH Corp. 11.25/12.00% Senior Toggle NotesSubtotalSubject to Push Not Merger- TotalHeld by EFIH Down Related Guaranteed$ -$ 776 $ 400 $ 1,1761,685 64 -1,7493,441 60 -3,501$ 5,126 $ 900 $ 400 6,426698$ 7,124TCEH Demand Notes (Note 15)Total(a) As a result of transactions completed in early 2013, the $5.126 billion principal amount of EFH Corp. Senior Notes werereturned by EFIH as a dividend to EFH Corp., which cancelled them, substantially all of the $1.176 billion principal amountof EFH Corp. Senior Secured Notes have been cancelled, $64 million of the $124 million principal amount of EFH Corp.Senior Notes subject to push down have been cancelled and the TCEH Demand Notes have been settled (see Note 15).December 31,2011Securities Guaranteed (principal amounts)EFH Corp. 9.75% and 10% Senior Secured NotesEFH Corp. 10.875% Senior NotesEFH Corp. 11.25/12.00% Senior Toggle NotesSubtotalSubject to Push Not Merger- TotalHeld by EFIH Down Related Guaranteed$ $ 776 $ 400 $ 1,1761,591 196 -1,7872,784 438 -3,222$ 4,375 $ 1,410 $ 400 6,1851,592$ 7,777TCEH Demand Notes (Note 15)TotalInformation Regarding Other Significant Outstanding DebtTCEH 11.5% Senior Secured Notes -At December 31, 2012, the principal amount of the TCEH 11.5% Senior SecuredNotes totaled $1.750 billion. The notes mature in October 2020, with interest payable in cash quarterly in arrears on January 1,April 1, July 1 and October 1, at a fixed rate of 11.5% per annum. The notes are fully and unconditionally guaranteed on a jointand several basis by EFCH and each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities (collectively, theGuarantors). The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and the guaranteesare secured on a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent suchassets and equity interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), subject to certainexceptions and permitted liens.The notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness of TCEH, (ii) seniorin right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of theTCEH Collateral and (iii) senior in right of payment to any future subordinated debt of TCEI-. These notes are effectivelysubordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of thevalue of the assets securing such obligations.The guarantees of the TCEH Senior Secured Notes by the Guarantors are effectively senior to any unsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. The guarantees are effectively subordinated toall debt of the Guarantors secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateralsecuring that debt.113 Table of ContentsThe indenture for the TCEH Senior Secured Notes contains a number of covenants that, among other things, restrict, subjectto certain exceptions, TCEH's and its restricted subsidiaries' ability to:* make restricted payments, including certain investments;" incur debt and issue preferred stock;" create liens;" enter into mergers or consolidations;* sell or otherwise dispose of certain assets, and* engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes when due. If certain events of default occur under the indenture, the trustee or the holders of at least 30% of aggregateprincipal amount of all outstanding TCEH Senior Secured Notes may declare the principal amount on all such notes to be due andpayable immediately.Until April 1, 2014, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of the TCEH Senior Secured Notes from time to time at a redemption price of 111.5% of the aggregate principalamount of the notes being redeemed, plus accrued interest. TCEH may redeem the notes at any time prior to April 1, 2016 at aprice equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. TCEHmay also redeem the notes, in whole or in part, at any time on or after April 1, 2016, at specified redemption prices, plus accruedinterest. Upon the occurrence of a change of control (as described in the indenture), TCEH must offer to repurchase the notes at101% of their principal amount, plus accrued interest.TCEH 15% Senior Secured Second Lien Notes (including Series B) -At December 31 2012, the principal amount of theTCEH 15% Senior Secured Second Lien Notes totaled $1.571 billion. These notes mature in April 2021, with interest payable incash quarterly in arrears on January 1, April 1, July 1 and October 1 at a fixed rate of 15% per annum. The notes are fully andunconditionally guaranteed on ajoint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH thatguarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by security interests in all ofthe assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of theassets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to theextent such assets and security interests secure obligations under the TCEH Senior Secured Facilities on a first-priority basis,subject to certain exceptions (including the elimination of the pledge of equity interests of any Subsidiary Guarantor to the extentthat separate financial statements would be required to be filed with the SEC for such Subsidiary Guarantor under Rule 3-16 ofRegulation S-X) and permitted liens. The guarantee from EFCH is not secured.The notes are senior obligations of the issuer and rank equally in right of payment with all senior indebtedness of TCEH,are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral(after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinateddebt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, theTCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEHCollateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEHCollateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of thevalue of the assets securing such obligations.The guarantees of the TCEH Senior Secured Second Lien Notes by the Subsidiary Guarantors are effectively senior to anyunsecured debt of the Subsidiary Guarantors to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral). These guarantees are effectively subordinated to all debt of the Subsidiary Guarantorssecured by the TCEH Collateral on a first-priority basis or that is secured by assets that are not part of the TCEH Collateral, tothe extent of the value of the collateral securing that debt. EFCH's guarantee ranks equally with its unsecured debt (includingdebt it guarantees on an unsecured basis) and is effectively subordinated to any of its secured debt to the extent of the value of thecollateral securing that debt.114 Table of ContentsThe indenture for the TCEH Senior Secured Second Lien Notes contains a number of covenants that, among other things,restrict, subject to certain exceptions, TCEH's and its restricted subsidiaries' ability to:* make restricted payments, including certain investments;* incur debt and issue preferred stock;" create liens;" enter into mergers or consolidations;* sell or otherwise dispose of certain assets, and* engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes when due. In general, all of the series of TCEH Senior Secured Second Lien Notes vote together as a single class. As aresult, if certain events of default occur under the indenture, the trustee or the holders of at least 30% of aggregate principal amountof all outstanding TCEH Senior Secured Second Lien Notes may declare the principal amount on all such notes to be due andpayable immediately.Until October 1,2013, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregateprincipal amount of each series of the TCEH Senior Secured Second Lien Notes from time to time at a redemption price of 115.00%of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEH may redeem each series of the notesat any time prior to October 1, 2015 at a price equal to 100% of their principal amount, plus accrued interest and the applicablepremium as defined in the indenture. TCEH may also redeem each series of the notes, in whole or in part, at any time on or afterOctober 1, 2015, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as describedin the indenture), TCEH must offer to repurchase each series of the notes at 101% of their principal amount, plus accrued interest.TCEH 10.25% Senior Notes (including Series B) and 10.50/11.25% Senior Toggle Notes (collectively, the TCEH SeniorNotes) -At December 31, 2012, the principal amount of the TCEH Senior Notes totaled $5.237 billion, including $363 millionaggregate principal amount held by EFH Corp. and EFIH, and the notes are fully and unconditionally guaranteed on a joint andseveral unsecured basis by TCEH's direct parent, EFCH (which owns 100% of TCEH), and by each subsidiary that guaranteesthe TCEH Senior Secured Facilities. The TCEH 10.25% Notes mature in November 2015, with interest payable in cash semi-annually in arrears on May I and November 1 at a fixed rate of 10.25% per annum. The TCEH Toggle Notes mature in November2016, with interest payable semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.50% per annum for cashinterest and at a fixed rate of 11.25% per annum for P1K Interest, which option expired with the November 1,2012 interest payment.TCEH may redeem the TCEH 10.25% Notes and TCEH Toggle Notes, in whole or in part, at any time, at specified redemptionprices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFCH or TCEH, TCEH must offerto repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.The indenture for the TCEH Senior Notes contains a number of covenants that, among other things, restrict, subject to certainexceptions, TCEH's and its restricted subsidiaries' ability to:* make restricted payments;* incur debt and issue preferred stock;* create liens;* enter into mergers or consolidations;* sell or otherwise dispose of certain assets, and* engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to pay principal or interest on thenotes when due. If certain events of default occur and are continuing under the indenture, the trustee or the holders of at least30% in principal amount of the notes may declare the principal amount on the notes to be due and payable immediately.Material Cross Default/Acceleration Provisions -Certain of our financing arrangements contain provisions that couldresult in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe othercovenants that could or does result in an acceleration of payments due. Such provisions are referred to as "cross default" or "crossacceleration" provisions.115 Table of ContentsIntercreditor Agreement -TCEH has entered into an intercreditor agreement with Citibank, N.A. and five securedcommodity hedge counterparties (the Secured Commodity Hedge Counterparties). The intercreditor agreement takes into account,among other things, the possibility that TCEH could issue notes and/or loans secured by collateral (other than the collateral thatsecures the TCEH Senior Secured Facilities) that ranks on parity with, or junior to, TCEH's existing first lien obligations underthe TCEH Senior Secured Facilities. The Intercreditor Agreement provides that the lien granted to the Secured Commodity HedgeCounterparties will rank pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH SeniorSecured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will be entitledto share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateralin an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the SecuredCommodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of theIntercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties' lien on such collateral relativeto the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to theSecured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the liengranted to the secured parties under the TCEH Senior Secured Facilities.Second Lien Intercreditor Agreement -TCEH has also entered into a second lien intercreditor agreement (the SecondLien Intercreditor Agreement) with Citibank, N.A., as senior collateral agent, and The Bank of New York Mellon Trust Company,N.A., as initial second priority representative. The Second Lien Intercreditor Agreement provides that liens on the collateral thatsecure the obligations under the TCEH Senior Secured Facilities, the obligations of the Secured Commodity Hedge Counterpartiesand any other obligations which are permitted to be secured on a pari passu basis therewith (collectively, the First Lien Obligations)will rank prior to the liens on such collateral securing the obligations under the TCEH Senior Secured Second Lien Notes, andany other obligations which are permitted to be secured on a pari passu basis (collectively, the Second Lien Obligations). TheSecond Lien Intercreditor Agreement provides that the holders of the First Lien Obligations will be entitled to the proceeds of anyliquidation of such collateral in connection with a foreclosure on such collateral until paid in full, and that the holders of the SecondLien Obligations will not be entitled to receive any such proceeds until the First Lien Obligations have been paid in full. TheSecond Lien Intercreditor Agreement also provides that the holders of the First Lien Obligations will control enforcement actionswith respect to such collateral, and the holders ofthe Second Lien Obligations will not be entitled to commence any such enforcementactions, with limited exceptions. The Second Lien Intercreditor Agreement also provides that releases of the liens on the collateralby the holders of the First Lien Obligations will automatically require that the liens on such collateral by the holders of the SecondLien Obligations be automatically released, and that amendments, waivers or consents with respect to any of the collateraldocuments in connection with the First Lien Obligations apply automatically to any comparable provision of the collateraldocuments in connection with the Second Lien Obligations.Fair Value of Long-Term DebtAt December 31, 2012 and 2011, the estimated fair value of our long-term debt (excluding capital leases) totaled $17.858billion and $18.740 billion, respectively, and the carrying amount totaled $30.342 billion and $30.434 billion, respectively. AtDecember 31, 2012, the estimated fair value of our short-term borrowings under the TCEH Revolving Credit Facilities totaled$1.500 billion and the carrying amount totaled $2.054 billion. We determine fair value in accordance with accounting standardsas discussed in Note 11, and at December 31, 2012, our debt fair value represents Level 2 valuations. We obtain security pricingfrom a vendor who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices arevalidated through subscription services such as Bloomberg.TCEH Interest Rate Swap TransactionsTCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at December31, 2012, TCEH has entered into the following series of interest rate swap transactions that effectively fix the interest rates atbetween 5.5% and 9.3%.Fixed Rates Expiration Dates Notional Amount5.5% -9.3% February 2013 through October 2014 $18.46 billion (a)6.8% -9.0% October 2015 through October 2017 $12.60 billion (b)(a) Swaps related to an aggregate $2.6 billion principal amount of debt expired in 2012. Per the terms of the transactions, thenotional amount of swaps entered into in 2011 grew by $2.405 billion, substantially offsetting the expired swaps.(b) These swaps are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes$3 billion that expires in October 2015 with the remainder expiring in October 2017.116 Table of ContentsTCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achievedthrough the interest rate swaps. Basis swaps in effect at December 31, 2012 totaled $11.967 billion notional amount, a decreaseof $5.783 billion from December 31, 2011 reflecting both new and expired swaps. The basis swaps relate to debt outstandingthrough 2014.The interest rate swap counterparties are secured on an equal and ratable basis by the same collateral package granted to thelenders under the TCEH Senior Secured Facilities.The interest rate swaps have resulted in net losses reported in interest expense and related charges as follows:Realized net lossUnrealized net gain (loss)TotalYear Ended December 31,2012 2011 2010S (670) $ (684) $ (673)166 (812) (207)$ (504) $ (1,496) $ (880)The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.065 billion and$2.231 billion at December 31, 2012 and 2011, respectively, of which $65 million and $76 million (both pretax), respectively,were reported in accumulated other comprehensive income.117 Table of Contents9. COMMITMENTS AND CONTINGENCIESContractual CommitmentsAt December 31, 2012, we had noncancellable commitments under energy-related contracts, leases and other agreementsas follows:Coal purchaseandtransportationagreements432308Pipeline Capacity paymentstransportation and under electricitystorage reservation purchase Nuclearfees agreements (a) Fuel Contracts Other Contracts$ 31 $ 99 $ 158 $ 13029 -116 4320132014$2015 292 12 -167 262016 123 --124 262017 43 --110 24Thereafter 44 --645 119Total $ 1,242 $ 72 $ 99 $ 1,320 $ 368(a) On the basis of current expectations of demand from electricity customers as compared with capacity and take-or-paypayments, management does not consider it likely that any material payments will become due for electricity not takenbeyond capacity payments.Expenditures under our coal purchase and coal transportation agreements totaled $245 million, $463 million and $445million for the years ended December 31, 2012, 2011 and 2010, respectively.At December 31, 2012, future minimum lease payments under both capital leases and operating leases are as follows:CapitalLeasesOperatingLeases (a)20132014201520162017ThereafterTotal future minimum lease paymentsLess amounts representing interestPresent value of future minimum lease paymentsLess current portionLong-term capital lease obligation$ 14 $1074243366 4635 36-16972 $ 37286412$ 52(a) Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.Rent reported as operating costs, fuel costs and SG&A expenses totaled $72 million, $66 million and $89 million for theyears ended December 31, 2012, 2011 and 2010, respectively.GuaranteesWe have entered into contracts that contain guarantees to unaffiliated parties that could require performance or paymentunder certain conditions.See Note 8 for discussion of guarantees and security for certain of our debt and EFCH guarantees of certain EFH Corp. debt.118 Table of ContentsLetters of CreditAt December 31, 2012, TCEH had outstanding letters of credit under its credit facilities totaling $764 million as follows:* $376 million to support risk management and trading margin requirements in the normal course of business, includingover-the-counter hedging transactions and collateral postings with ERCOT;* $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);* $71 million to support TCEH's REP financial requirements with the PUCT, and* $109 million for miscellaneous credit support requirements.Litigation Related to Generation FacilitiesIn November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak GroveManagement Company LLC's (Oak Grove) (a wholly-owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System(TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in theTravis County, Texas District Court. Plaintiffs sought a reversal of the TCEQ's order and a remand back to the TCEQ for furtherproceedings. Oral argument was held in this administrative appeal on October 23, 2012, and the court affirmed the TCEQ'sissuance of the TPDES permit to Oak Grove. In December 2012, plaintiffs appealed the district court's decision to the Third Courtof Appeals in Austin, Texas. While we cannot predict the timing or outcome of this proceeding, we believe the renewal andamendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (TexarkanaDivision) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violationsof the Clean Air Act (CAA) at Luminant's Martin Lake generation facility. In May 2012, the Sierra Club filed a lawsuit in the USDistrict Court for the Western District of Texas (Waco Division) against EFH Corp. and Luminant Generation Company LLC foralleged violations of the CAA at Luminant's Big Brown generation facility. The Big Brown and Martin Lake cases are currentlyscheduled for trial in November 2013. While we are unable to estimate any possible loss or predict the outcome, we believe thatthe Sierra Club's claims are without merit, and we intend to vigorously defend these lawsuits. In addition, in December 2010 andagain in October 2011, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating CAA provisions inconnection with Luminant's Monticello generation facility. In May 2012, the Sierra Club informed us that it may sue us forallegedly violating CAA provisions in connection with Luminant's Sandow 4 generation facility. While we cannot predict whetherthe Sierra Club will actually file suit regarding Monticello or Sandow 4 or the outcome of any resulting proceedings, we believewe have complied with the requirements of the CAA at all of our generation facilities.See below for discussion of litigation regarding the CSAPR and the Texas State Implementation Plan.Regulatory ReviewsIn June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of theCAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, includingNew Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generationfacilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received alarge and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently receiveda notice of violation from the EPA, which has in some cases progressed to litigation or settlement. In July 2012, the EPA sent usa notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our MartinLake and Big Brown generation facilities. While we cannot predict whether the EPA will initiate enforcement proceedings underthe notice of violation, we believe that we have complied with all requirements of the CAA at all of our generation facilities. Wecannot predict the outcome of any resulting enforcement proceedings or estimate the penalties that might be assessed in connectionwith any such proceedings. In September 2012, we filed a petition for review in the United States Court of Appeals for the FifthCircuit Court seeking judicial review of the EPA's notice of violation. Given recent legal precedent subjecting agency orders likethe notice of violation to judicial review, we filed the petition for review to preserve our ability to challenge the EPA's issuanceof the notice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December 2012, the Fifth CircuitCourt issued an order that will delay a ruling on the EPA's motion to dismiss until after the case has been fully briefed and oralargument, if any, is held. We cannot predict the outcome of these proceedings, including the financial effects, if any.119 Table of ContentsCross-State Air Pollution Rule (CSAPR)In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions ofsulfur dioxide (SO2) and nitrogen oxides (NO.) emissions from our fossil-fueled generation units. In September 2011, we fileda petition for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) challenging the CSAPRas it applies to Texas. If the CSAPR had taken effect, it would have caused us to, among other actions, idle two lignite/coal-fueledgeneration units and cease certain lignite mining operations by the end of 2011.In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR,including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule.In April 2012, we filed in the D.C. Circuit Court a petition for review of the Final Revisions on the ground, among others, thatthe rules do not include all of the budget corrections we requested from the EPA. The parties to the case have agreed that the caseshould be held in abeyance pending the conclusion of the CSAPR rehearing proceeding discussed below. In June 2012, the EPAfinalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPR issued by the EPA inOctober 2011, the Final Revisions and the Second Revised Rule finalize emissions budgets for our generation assets that areapproximately 6% lower for SO2, 3% higher for annual NO. and 2% higher for seasonal NOR.In August 2012, a three judge panel of the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for furtherproceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule do not impose any immediate requirementson us, the State of Texas, or other affected parties. The D.C. Circuit Court's order stated that the EPA was expected to continueadministering the CAIR (the predecessor rule to the CSAPR) pending the EPA's further consideration of the rule. In October2012, the EPA and certain other parties that supported the CSAPR filed petitions with the D.C. Circuit Court seeking review bythe full court of the panel's decision to vacate and remand the CSAPR. In January 2013, the D.C. Circuit Court denied theserequests for rehearing, concluding the CSAPR rehearing proceeding. The EPA and the other parties have approximately 90 daysto appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeals will be filed.State Implementation Plan (SIP)In September 20 10, the EPA disapproved a portion of the State Implementation Plan pursuant to which the TCEQ implementsits program to achieve the requirements of the Clean Air Act. The EPA disapproved the Texas standard permit for pollution controlprojects. We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. Wechallenged the EPA's disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) arguingthat the TCEQ's adoption of the standard permit conditions for pollution control projects was consistent with the Clean Air Act.In March 2012, the Fifth Circuit Court vacated the EPA's disapproval of the Texas standard permit for pollution control projectsand remanded the matter to the EPA for reconsideration. We cannot predict the timing or outcome of the EPA's reconsideration,including the financial effects, if any.In November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacingthat exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generationfacility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicabilityof the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and receivedthe generation facility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the Fifth CircuitCourt arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issuedis consistent with the Clean Air Act. In July 2012, the Fifth Circuit Court denied our challenge and ruled that the EPA's actionswere in accordance with the Clean Air Act. In October 2012, the Fifth Circuit Court panel withdrew its original opinion and issueda new expanded opinion that again upheld the EPA's disapproval. In November 2012, we filed a petition with the Fifth CircuitCourt asking for review by the full Fifth Circuit Court of the panel's new expanded opinion. Other parties to the proceedings alsofiled a petition with the Fifth Circuit Court asking the panel to reconsider its decision. We cannot predict the timing or outcomeof this matter, including the financial effects, if any.Other MattersWe are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutionsof which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity orfinancial condition.120 Table of ContentsEnvironmental ContingenciesSee discussion above regarding the CSAPR issued by the EPA in July 2011 and revised in February 2012 that includeprovisions which, among other things, place limits on SO2 and NO, emissions produced by electricity generation plants. TheCSAPR provisions and the Mercury and Air Toxics Standard (MATS) issued by the EPA in December 2011, would requiresubstantial additional capital investment in our lignite/coal-fueled generation facilities.We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Webelieve that we are in compliance with current environmental laws and regulations; however, the impact, if any, of changes toexisting regulations or the implementation ofnew regulations is not determinable and could materially affect our financial condition,results of operations and liquidity.The costs to comply with environmental regulations could be significantly affected by the following external events orconditions:" enactment of state or federal regulations regarding C02 and other greenhouse gas emissions;" other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances andhazardous and solid wastes, and other environmental matters, including revisions to CAIR currently being developedby the EPA as a result of court rulings discussed above and MATS, and" the identification of sites requiring clean-up or the filing of other complaints in which we may be asserted to be a potentialresponsible party under applicable environmental laws or regulations.Labor ContractsCertain personnel engaged in TCEH activities are represented by labor unions and covered by collective bargainingagreements with varying expiration dates. In November 2011, three-year labor agreements were reached covering bargaining unitpersonnel engaged in lignite-fueled generation operations (excluding Sandow) and lignite mining operations (excluding ThreeOaks). Also in November 2011, a four-year labor agreement was reached covering bargaining unit personnel engaged in naturalgas-fueled generation operations. In October 2010, two-year labor agreements were reached covering bargaining unit personnelengaged in the Sandow lignite-fueled generation operations and the Three Oaks lignite mining operations, and although the termof these agreements have now expired, we are currently negotiating new labor agreements for the Sandow operations and ThreeOaks Mine and are operating under the terms of the existing agreements for these two facilities. In August 2010, a three-yearlabor agreement was reached covering bargaining unit personnel engaged in nuclear-fueled generation operations. We do notexpect any changes in collective bargaining agreements to have a material effect on our results of operations, liquidity or financialcondition.Nuclear InsuranceNuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverageand accidental outage and/or extra expense coverage. The liability coverage is governed by the Price-Anderson Act (Act), whilethe property damage, decontamination and premature decommissioning coverage are promulgated by the rules and regulations ofthe NRC. We intend to maintain insurance against nuclear risks as long as such insurance is available. The company is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations,(iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses couldhave a material effect on our financial condition and results of operations and liquidity.With regard to liability coverage, the Act provides financial protection for the public in the event of a significant nucleargeneration plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $12.5 billion andrequires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $12.5 billion limit for a single incident mandated by the Act.As required, the company provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodilyinjury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As thefirst layer of financial protection, the company has $375 million of liability insurance from American Nuclear Insurers (ANI),which provides such insurance on behalf ofa major stock insurance company pool, Nuclear Energy Liability Insurance Association.The second layer of financial protection is provided under an industry-wide retrospective payment program called SecondaryFinancial Protection (SFP).121 Table of ContentsUnder the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in theUS is subject to an assessment of up to $117.5 million plus a 3% insurance premium tax, subject to increases for inflation everyfive years. Assessments are limited to $17.5 million per operating licensed reactor per year per incident. The company's maximumpotential assessment under the industry retrospective plan would be $235 million (excluding taxes) per incident but no more than$35 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375million per accident at any nuclear facility. The SFP and liability coverage are not subject to any deductibles.With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plantlicense-holders maintain at least $1.06 billion of such insurance and require the proceeds thereof to be used to place a plant in asafe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds canbe used for plant repair or restoration or to provide for premature decommissioning. The company maintains nucleardecontamination and property damage insurance for Comanche Peak in the amount of$2.25 billion (subject to $5 million deductibleper accident), above which the company is self-insured. This insurance coverage consists of a primary layer of coverage of $500million provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company and$1.25 billion of premature decommissioning coverage also provided by NEIL. The European Mutual Association for NuclearInsurance provides additional insurance limits of S500 million in excess of NEIL's $1.75 billion coverage.The company maintains Accidental Outage Insurance through NEIL to cover the additional costs of obtaining replacementelectricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as aresult of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeksand $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The totalmaximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both unitsare out of service at the same time as a result of the same accident.If NEIL's losses exceeded its reserves for the applicable coverage, potential assessments in the form of a retrospectivepremium call could be made up to ten times annual premiums. The company maintains insurance coverage against these potentialretrospective premium calls.Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL wouldmake available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits foreach claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.122 Table of Contents10. EQUITYCash Distributions to ParentWe paid no cash distributions to EFH Corp. in 2012, 2011 or 2010.Dividend RestrictionsWhile EFCH has no contractual dividend restrictions, the TCEH Senior Secured Facilities generally restrict TCEH frommaking any cash distribution to any of its parent companies for the ultimate purpose of making a cash distribution on their commonstock unless at the time, and after giving effect to such distribution, TCEH's consolidated total debt (as defined in the TCEH SeniorSecured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. At December 31, 2012, the ratio was 8.5 to 1.0.In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior SecuredNotes and TCEH Senior Secured Second Lien Notes generally restrict TCEH's ability to make distributions or loans to any of itsparent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior SecuredFacilities and the indentures governing such notes.Under applicable law, we are also prohibited from paying any dividend to the extent that immediately following paymentof such dividend, there would be no statutory surplus or we would be insolvent.Noncontrolling InterestsAs discussed in Note 2, we consolidate a joint venture formed in 2009 for the purpose of developing two new nucleargeneration units, which results in a noncontrolling interests component of equity. As discussed in Notes 2 and 7, prior to November2012, we also consolidated a VIE owned by EFH Corp. related to our accounts receivable securitization program, which resultedin a noncontrolling interests component of equity. Net loss attributable to the noncontrolling interests was immaterial for the yearsended December 31, 2012, 2011 and 2010.123 Table of Contents11. FAIR VALUE MEASUREMENTSAccounting standards related to the determination of fair value define fair value as the price that would be received to sellan asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a"mid-market" valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair valuefor the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the marketapproach for recurring fair value measurements and use valuation techniques to maximize the use ofobservable inputs and minimizethe use of unobservable inputs.We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:Level I valuations use quoted prices in active markets for identical assets or liabilities that are accessible at themeasurement date. An active market is a market in which transactions for the asset or liability occur with sufficientfrequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities includeexchange-traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures andswaps transacted through clearing brokers for which prices are actively quoted.Level 2 valuations use inputs that, in the absence of actively quoted market prices, are observable for the asset or liability,either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets,(b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quotedprices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quotedintervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation orother means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilitiesthat are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes areavailable.Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observableinputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset orliability at the measurement date. We use the most meaningful information available from the market combined withinternally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assetsand liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs tothe valuations, including inputs that are not observable or easily corroborated through other means. See further discussionbelow.Our valuation policies and procedures are developed, maintained and validated by an EFH Corp. centralized risk managementgroup that reports to the EFH Corp. Chief Financial Officer, who also functions as the Chief Risk Officer. Risk managementfunctions include valuation model validation, risk analytics, risk control, credit risk management and risk reporting.We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on themarket approach of using prices and other market information for identical and/or comparable assets and liabilities for those itemsthat are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationshipsbetween different price curves.In utilizing broker quotes, we attempt to obtain multiple quotes from brokers (generally non-binding) that are active in thecommodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input asobservable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputsvaries depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends andvarious other factors. In addition, for valuation of interest rate swaps, we use generally accepted interest swap valuation modelsutilizing month-end interest rate curves.Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multipleinputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficientamount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significantunobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locationsand credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forward pricecurves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fairvalue measurements resulting from such curves are classified as Level 3.124 Table of ContentsThe significant unobservable inputs and valuation models are developed by employees trained and experienced in marketoperations and fair value measurement and validated by the company's risk management group, which also further analyzes anysignificant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upwardor downward changes in the fair value measurement.With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset orliability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fairvalue measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for theeffects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input tothe fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.Assets and liabilities measured at fair value on a recurring basis consisted of the following:December 31, 2012Level I Level 2 Level 3 (a) Reclassification (b) TotalAssets:Commodity contractsInterest rate swapsNuclear decommissioning trust -equity securities (c)Nuclear decommissioning trust -debt securities (c)Total assetsLiabilities:Commodity contractsInterest rate swapsTotal liabilities$ 180 S2491,784 $283 $-- $ 2,0472144393-261 --261$ 429 $ _2.191 83 ~.- $ 2,703$ 208 $ 121 $ 54 3$ 383-2,067 -3a2,067$ 208 2 2188 S 54 $ -$ 2,450December 31, 2011Level I Level 2 Level 3 (a) Reclassification (b) TotalAssets:Commodity contractsNuclear decommissioning trust -equity securities (c)Nuclear decommissioning trust -debt securities (c)Total assetsLiabilities:Commodity contractsInterest rate swapsTotal liabilities$ 395 $2083,915 $124 $1 $4,435124332-242 --242$ 603 $ 4.,281 $ 124 $ 1 $ 5,009$ 446 $ 727 $ 71 $ 1 $ 1,245-2,231 --2,231$ 446 $ 2,958 $ 71 $ 1 $ 3,476(a) See table below for description of Level 3 assets and liabilities.(b) Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or viceversa, as presented in the balance sheet.(c) The nuclear decommissioning trust investment is included in the investments line in the balance sheet. See Note 16.In conjunction with ERCOT's transition to a nodal wholesale market structure effective December 2010, we have enteredinto certain derivative transactions (primarily congestion revenue rights transactions) that are valued at illiquid pricing locations(unobservable inputs), thus requiring classification as Level 3 assets or liabilities.Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal derivative instruments enteredinto for hedging purposes and include physical contracts that have not been designated "normal" purchases or sales. See Note 12for further discussion regarding the company's use of derivative instruments.125 Table of ContentsInterest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debtas well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 8 for discussion of interestrate swaps.Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement anddecommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securitiesconsistent with investment rules established by the NRC and the PUCT.There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December31, 2012, 2011 and 2010. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfersbetween Level 2 and Level 3 for the years ended December 31, 2012, 2011 and 2010.126 Table of ContentsThe following table presents the fair value of the Level 3 assets and liabilities by major contract type (all related to commoditycontracts) and the significant unobservable inputs used in the valuations at December 31, 2012:Fair ValueContract Type Valuation(a) Assets Liabilities Total TechniqueElectricitypurchases and Valuationsales $ 5 $ (9) $ (4) ModelSignificant Unobservable InputRange (b)Electricityspread optionsElectricitycongestionrevenue rightsOption Pricing24 Model34(10)Illiquid pricing locations (c)Hourly price curve shape(d)Gas to power correlation (e)Power volatility (f)Illiquid price differencesbetween settlement points(h)Illiquid price variancesbetween mines (i)Probability of default (j)Recovery rate (k)$20 to $40/MWh$20 to $501MWh20% to 90%20% to 40%$0.00 to $0.50$0.00 to $1.005% to 40%0% to 40%41Coalpurchases(2)(32)(1)Market39 Approach (g)Market(32) Approach (g)Other32Total $ 83 $ (54) $ 29(a) Electricity purchase and sales contracts include wind generation agreements and hedging positions in the ERCOT westregion, as well as power contracts, the valuations of which include unobservable inputs related to the hourly shaping of theprice curve. Electricity spread options consist of physical electricity call options. Electricity congestion revenue rightscontracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences betweensettlement points within ERCOT. Coal purchase contracts relate to western (Powder River Basin) coal.(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.(c) Based on the historical range of forward average monthly ERCOT West Hub prices.(d) Based on the historical range of forward average hourly ERCOT North Hub prices.(e) Estimate of the historical range based on forward natural gas and on-peak power prices for the ERCOT hubs most relevantto our spread options.(f) Based on historical forward price changes.(g) While we use the market approach, there is either insufficient market data to consider the valuation liquid or the significanceof credit reserves or non-performance risk adjustments results in a Level 3 designation.(h) Based on the historical price differences between settlement points in ERCOT North Hub.(i) Based on the historical range of price variances between mine locations.() Estimate of the range of probabilities of default based on past experience and the length of the contract as well as our andcounterparties' credit ratings.(k) Estimate of the default recovery rate based on historical corporate rates.127 Table of ContentsThe following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts)for the years ended December 31, 2012, 2011 and 2010:Year Ended December 3 1,2012 2011 2010$ 53 $ 342 $ 81Net asset balance at beginning of periodTotal unrealized valuation gains (losses)Purchases, issuances and settlements (a):PurchasesIssuancesSettlementsTransfers into Level 3 (b)Transfers out of Level 3 (b)Net change (c)Net asset balance at end of periodUnrealized valuation gains (losses) relating to instruments held at end ofperiod(17)(1)26673 117 68(23) (15) (31)(12) (41) (11)(42) -(12)(3) (349) (19)(24) (289) 261$ 29 $ 53 $ 342(24)17I]](a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases andissuances reflect option premiums paid or received.(b) Includes transfers due to changes in the observability of significant inputs. Transfers in and out occur at the end of eachquarter, which is when the assessments are performed. Transfers out during 2012 reflect increased observability of pricingrelated to certain congestion revenue rights. Transfers in during 2012 were driven by an increase in nonperformance riskadjustments related to certain coal purchase contracts as well as certain power contracts that include unobservable inputsrelated to the hourly shaping of the price curve. Transfers out during 2011 were driven by the effect of an increase in optionmarket trading activity on our natural gas collars for 2014 and increased liquidity in forward periods for coal purchasecontracts for 2014. All Level 3 transfers for the years presented are in and out of Level 2.(c) Substantially all changes in values of commodity contracts are reported in the income statement in net gain from commodityhedging and trading activities, except in 2010, a gain of $ 16 million on the termination of a long-term power sales contractis reported in other income in the income statement. Activity excludes changes in fair value in the month the position settledas well as amounts related to positions entered into and settled in the same month.128 Table of Contents12. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES -Strategic Use of DerivativesWe transact in derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodityprice risk and interest rate risk exposure. Our principal activities involving derivatives consist of a commodity hedging programand the hedging of interest costs on our long-term debt. See Note 11 for a discussion of the fair value of all derivatives.Natural Gas Price Hedging Program -TCEH has a natural gas price hedging program designed to reduce exposure tochanges in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricitysales and related cash flows. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas.Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has soldforward natural gas through 2014. These transactions are intended to hedge a portion of electricity price exposure related toexpected lignite/coal- and nuclear-fueled generation for this period. Unrealized gains and losses arising from changes in the fairvalue of the instruments under the program as well as realized gains and losses upon settlement of the instruments are reported inthe income statement in net gain (loss) from commodity hedging and trading activities.Interest Rate Swap Transactions -Interest rate swap agreements are used to reduce exposure to interest rate changes byconverting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swapsare used to effectively reduce the hedged borrowing costs. Unrealized gains and losses arising from changes in the fair value ofthe swaps as well as realized gains and losses upon settlement of the swaps are reported in the income statement in interest expenseand related charges. See Note 8 for additional information about interest rate swap agreements.Other Commodity Hedging and TradingActivity -In addition to the natural gas price hedging program, TCEH enters intoderivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for shorter-term hedgingpurposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in naturalgas and electricity markets.Financial Statement Effects of DerivativesSubstantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accountingstandards related to derivative instruments and hedging activities. The following tables provide detail of commodity and otherderivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported inthe balance sheets at December 31, 2012 and 2011:December 31, 2012Derivative assets Derivative liabilitiesCommodity Interest rate Commodity Interest ratecontracts swaps contracts swaps TotalCurrent assets $ 1,461 $ 2 $ $ -$ 1,463Noncurrent assets 586 ---586Current liabilities -(366) (528) (894)Noncurrent liabilities -- -(17) (1,539) (1,556)Net assets (liabilities) $ 2,047 $ 2 $ (383) $ (2,067) S (4011December 31, 2011Current assetsNoncurrent assetsCurrent liabilitiesNoncurrent liabilitiesNet assets (liabilities)Derivative assets Derivative liabilitiesCommodity Interest rate Commodity Interest ratecontracts swaps contracts swaps Total$ 2,883 $ -$ -$ -$ 2,8831,552 ---1,552(1) -(1,162) (621) (1,784)() -(1,610) (1,692)$ 4,434 $ (1,244)$ (2,231) $ 959129 Table of ContentsAt December 31, 2012 and 2011, there were no derivative positions accounted for as cash flow or fair value hedges.Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled$568 million and $1.006 billion in net liabilities at December 31, 2012 and 2011, respectively. Reported amounts as presented inthe above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements.This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positionswith the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantlyfrom period to period.The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealizedeffects:Year Ended December 31,2012 2011 2010Derivative (income statement presentation)Commodity contracts (Net gain from commodity hedging and tradingactivities) (a)Commodity contracts (Other income) (b)Interest rate swaps (Interest expense and related charges) (c)Net gain (loss)S 279 $1,139 $2,162116(504) (1,496) (880)(225) $ (357) $ 1,398(a) Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts relatedto positions settled are assumed to equal reversals of previously recorded unrealized amounts.(b) Represents a noncash gain on termination of a long-term power sales contract (see Note 6).(c) Includes unrealized mark-to-market net (gain) loss as well as the net realized effect on interest paid/accrued, both reportedin "Interest Expense and Related Charges" (see Note 16).The following table presents the pretax effect (all losses) on net income and other comprehensive income (OCI) of derivativeinstruments previously accounted for as cash flow hedges. There were no amounts recognized in OCI for the years ended December31, 2012, 2011 or 2010.Derivative type (income statement presentation of loss reclassifiedfrom accumulated OCI into income)Interest rate swaps (interest expense and related charges)Interest rate swaps (depreciation and amortization)Commodity contracts (operating revenues)TotalYear Ended December 31,2012 2011 2010$ (8) $ (27) $ (87)(2) (2) (2)S1 O1 $ (2 90)There were no transactions designated as cash flow hedges during the years ended December 31, 2012, 2011 or 2010.Accumulated other comprehensive income related to cash flow hedges at December 31, 2012 and 2011 totaled $42 millionand $49 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $6million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at December31, 2012 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.130 Table of ContentsDerivative Volumes-- The following table presents the gross notional amounts of derivative volumes at December 31,2012and 2011:December 31,2012 2011Derivative type Notional Volume Unit of MeasureInterest rate swaps:Floating/fixed (a) $ 31,060 $ 31,255 Million US dollarsBasis (b) $ 11,967 $ 19,167 Million US dollarsNatural gas:Natural gas price hedge forward sales and purchases (c) 875 1,602 Million MMBtuLocational basis swaps 495 728 Million MMBtuAll other 1,549 841 Million MMBtuElectricity 76,767 105,673 GWhCongestion Revenue Rights (d) 111,185 142,301 GWhCoal 13 23 Million tonsFuel oil 47 51 Million gallonsUranium 441 480 Thousand pounds(a) Includes notional amount of interest rate swaps maturing between February 2013 and October 2014 as well as notional amountof swaps effective from October 2014 with maturity dates through October 2017 (see Note 8).(b) The December 31, 2011 amount includes $1.417 billion notional amount of swaps entered into but not effective until February2012.(c) Represents gross notional forward sales, purchases and options transactions in the natural gas price hedging program. Thenet amount of these transactions was approximately 360 million MMBtu and 700 million MMBtu at December 31, 2012 and2011, respectively.(d) Represents gross forward purchases associated with instruments used to hedge price differences between settlement pointsin the nodal wholesale market design in ERCOT.Credit Risk-Related Contingent Features of DerivativesThe agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent featuresthat could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement.Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies;however, due to our credit ratings being below investment grade, substantially all of such collateral posting requirements arealready effective.At December 31, 2012 and 2011, the fair value of liabilities related to derivative instruments under agreements with creditrisk-related contingent features that were not fully cash collateralized totaled $58 million and $364 million, respectively. Theliquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling$12 million and $78 million at December 31, 2012 and 2011, respectively. If all the credit risk-related contingent features relatedto these derivatives had been triggered, including cross default provisions, at December 31,2012, there were no remaining liquidityrequirements, and at December 31,2011 the remaining related liquidity requirement would have totaled $7 million after reductionfor net accounts receivable and derivative assets under netting arrangements.In addition, certain derivative agreements that are collateralized primarily with liens on certain of our assets includeindebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under otherfinancing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of suchindebtedness. At December 31, 2012 and 2011, the fair value of derivative liabilities subject to such cross-default provisions,largely related to interest rate swaps, totaled $2.150 billion and $2.651 billion, respectively, before consideration of the amountof assets subject to the liens. No cash collateral or letters of credit were posted with these counterparties at December 31, 2012or 2011 to reduce the liquidity exposure. If all the credit risk-related contingent features related to these derivatives, includingamounts related to cross-default provisions, had been triggered at December 31, 2012 and 2011, the remaining related liquidityrequirement after reduction for derivative assets under netting arrangements but before consideration of the amount of assetssubject to the liens would have totaled $1.122 billion and $1.160 billion, respectively. See Note 8 for a description of otherobligations that are supported by liens on certain of our assets.131 Table of ContentsAs discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-relatedcontingent features, including cross-default provisions, totaled $2.208 billion and $3.015 billion at December 31, 2012 and 2011,respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable andderivative assets under netting arrangements and assets subject to related liens.Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amountsto be posted if the features are triggered. These provisions include material adverse change, performance assurance, and otherclauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosedabove exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.Concentrations of Credit Risk Related to DerivativesTCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. At December 31, 2012,total credit risk exposure to all counterparties related to derivative contracts totaled $2.139 billion (including associated accountsreceivable). The net exposure to those counterparties totaled $255 million at December 31, 2012 after taking into effect nettingarrangements, setoff provisions and collateral. At December 31, 2012, the credit risk exposure to the banking and financial sectorrepresented 92% of the total credit risk exposure and 52% of the net exposure, a significant amount of which is related to thenatural gas price hedging program, and the largest net exposure to a single counterparty totaled $50 million.Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerancebecause all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases therisk that a default by any of these counterparties would have a material effect on our financial condition, results of operations andliquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to postcollateral in the event of a material downgrade in their credit rating.We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorizespecific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positiveand negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit,surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financialcondition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty.The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event ofdefault by one or more counterparties could subsequently result in termination-related settlement payments that reduce availableliquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlementsif the counterparties owe amounts to us.132 Table of Contents13. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANSPension PlanOur subsidiaries are participating employers in the EFH Retirement Plan (the Plan), a defined benefit pension plan sponsoredby EFH Corp. The Plan is a qualified pension plan under Section 401 (a) of the Internal Revenue Code of 1986, as amended (Code)and is subject to the provisions of ERISA. All benefits are funded by the participating employers. The Plan provides benefits toparticipants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution creditsbased on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a TraditionalRetirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interestcomponent of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the CashBalance Formula, future increases in earnings will not apply to prior service costs. Since October 1, 2007, all new employees,with the exception of employees hired by Oncor, have not been eligible to participate in the Plan. It is EFH Corp.'s policy to fundthe Plan to the extent deductible under existing federal tax regulations.In August 2012, EFH Corp. approved certain amendments to the Plan. These actions were completed in the fourth quarter2012, and the amendments resulted in:* splitting off assets and liabilities under the Plan associated with employees of Oncor and all retirees and terminated vestedparticipants of EFH Corp. and its subsidiaries (including discontinued businesses) to a new plan sponsored andadministered by Oncor;* splitting off assets and liabilities under the Plan associated with active employees of EFH Corp.'s competitive businesses,other than collective bargaining unit (union) employees, to a Terminating Plan, freezing benefits and vesting all accruedplan benefits for these participants;* the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities under the TerminatingPlan, and* maintaining assets and liabilities associated with union employees of EFH Corp.'s competitive businesses under the Plan.Settlement of the Terminating Plan obligations and the full funding of the EFH Corp. competitive operations portion ofliabilities (including discontinued businesses) under the Oncor Plan resulted in an aggregate cash contribution by EFH Corp.'scompetitive operations of $259 million in the fourth quarter 2012.EFH Corp.'s competitive operations recorded charges totaling $285 million in the fourth quarter 2012, including $92 millionrelated to the settlement of the Terminating Plan and $193 million related to the competitive business obligations (includingdiscontinued businesses) that are being assumed under the Oncor Plan. These amounts represent the previously unrecognizedactuarial losses reported in EFH Corp.'s accumulated other comprehensive income (loss). TCEH's allocated share of these chargestotaled $141 million. TCEH settled $91 million of this allocation with EFH Corp. in 2012 and expects to settle the remaining $50million with EFH Corp. in the first quarter 2013.Our subsidiaries also participate in EFH Corp.'s supplemental unfunded retirement plans for certain employees whoseretirement benefits cannot fully be earned under the qualified Retirement Plan, the information for which is included below.Other Postretirement Employee Benefit (OPEB) PlanOur subsidiaries participate with EFH Corp. and certain other affiliated subsidiaries of EFH Corp. to offer OPEB in the formof health care and life insurance to eligible employees and their eligible dependents upon the retirement of such employees. Foremployees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formuladepending on the retiree's age and years of service. In 2011, we announced a change to the OPEB plan whereby, effective January1, 2013, Medicare-eligible retirees from the competitive business will be subject to a cap on increases in subsidies received underthe plan to offset medical costs.133 Table of ContentsPension and OPEB Costs Recognized as ExpenseThe following details net pension and OPEB costs recognized as expense. The pension and OPEB amounts provided representallocations to us of amounts related to EFH Corp.'s plans.Year Ended December 31,2012 2011 2010Pension costs (a) $ 178 $ 38 $ 28OPEB costs 1 14 11Total benefit costs recognized as expense $ 179 $ 52 $ 39(a) As a result of pension plan actions discussed above, 2012 includes $141 million recorded by TCEH as a settlement charge.For determining net periodic pension cost, EFH Corp. uses the calculated value method to determine the market-relatedvalue of the assets held in trust. EFH Corp. includes the realized and unrealized gains or losses in the market-related value ofassets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the precedingthree years is included in the market-related value. Each year, the market-related value of assets is increased for contributions tothe plan and investment income and is decreased for benefit payments and expenses for that year. For determining net periodicOPEB cost, EFH Corp. uses the fair value of assets held in trust.Regulatory Recovery of Pension and OPEB CostsPURA provides for the recovery by Oncor, in its regulated revenue rates, of pension and OPEB costs applicable to servicesof Oncor's active and retired employees, as well as services of active and retired personnel engaged in TCEH's activities, relatedto their service prior to the deregulation and disaggregation of EFH Corp.'s electric utility business effective January 1, 2002.Accordingly, Oncor and TCEH entered into an agreement whereby Oncor assumed responsibility for applicable pension and OPEBcosts related to those personnel.Additional Multiemployer Plan Participation DisclosuresWe have not been allocated any overfunded asset or underfunded liability related to our participation in EFH Corp.'s pensionand OPEB plans. However, we arejointly and severally liable for all EFH Corp. pension and OPEB plan liabilities and are subjectto certain risks including the following:" Funding/assets contributed by us may be used to provide benefits to employees from other participating entities;" We may be required to bear the unfunded obligations of another participating employer that stops making contributions,and" If we stop participating, we may be required to pay an amount to the plan based on the underfunded status of the plan.Our share of contributions to the Plan was 37% in 2012 and zero percent in each of the years ended December 31,2011 and2010. The Plan was at least 80% funded for those periods as determined under the provisions ofERISA. The Employer IdentificationNumber of the Retirement Plan is 75-26693 10 and the plan number is 002.Assumed Discount RateThe discount rate assumed for pension costs was 5.00% for January through July 2012, 4.15% for August through September2012, 4.20% for October through December 2012 and 5.50% and 5.90% for the years ended December 31, 2011 and 2010,respectively. The discount rate assumed for OPEB costs was 4.95%, 5.55% and 5.90% for the years ended December 31, 2012,2011 and 2010, respectively. The expected rate of return on plan assets reflected in the 2012 cost amounts is 7.4% and 6.8% forthe pension plan assets and OPEB assets, respectively.134 Table of ContentsThrift PlanOur employees may participate in a qualified savings plan, the EFH Thrift Plan (Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA.Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determinehighly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more thansuch threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also madein an amount equal to 100% of the first 6% of employee contributions for employees who are not covered by the Retirement Planor who are covered under the Cash Balance Formula of the Retirement Plan, and 75% of the first 6% of employee contributionsfor employees who are covered under the Traditional Retirement Plan Formula of the Retirement Plan. Employer matchingcontributions are made in cash and may be allocated by participants to any of the plan's investment options. Our contributions tothe Thrift Plan totaled $19 million, $18 million and $17 million for the years ended December 31,2012,2011 and 2010, respectively.135 Table of Contents14. STOCK-BASED COMPENSATIONIn December 2007, EFH Corp. established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates(2007 SIP). We bear the costs of EFH Corp.'s 2007 SIP for applicable management personnel engaged in our business activities.Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFH Corp.or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferredshares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in wholeor in part by reference to, or are otherwise based on the fair market value of EFH Corp.'s shares of common stock.Our stock-based compensation expense recorded for the years ended December 31, 2012, 2011 and 2010 was as follows:Year Ended December 31,Type of award 2012 2011 2010Restricted stock units granted to employees $ 3 $ 2 $ -Stock options granted to employees 2 4 9Other share and share-based awards (1) (1) (2)Total compensation expense $ 4 $ 5 $ 7=Restricted Stock Units -Restricted stock unit activity for our employees in 2012 consisted of grants of 1.4 million unitsand forfeitures of 0.2 million units. Restricted stock unit activity in 2011 consisted of the issuance of 11.2 million units in exchangefor stock options as discussed below, grants of 2.2 million units and forfeitures of 0.4 million units. Restricted stock units vest ascommon stock of EFH Corp, upon the earlier of September 2014 or a change of control, or on a prorated basis upon certain definedevents such as termination of employment. Compensation expense per unit is based on the estimated value of EFH Corp. stockat the grant date, less a marketability discount factor. To determine expense related to units issued in exchange for stock options,the unit value is further reduced by the fair value of the options exchanged. At December 31, 2012, there was approximately $7.5million of unrecognized compensation expense related to nonvested restricted stock units expected to be recognized by us throughSeptember 2014.Stock Options -No options were granted to employees in 2012 or 2011. Options to purchase 0.2 million shares of EFHCorp. common stock were granted to certain of our management employees in 2010. The exercise period for vested awards was10 years from grant date. The options initially provided the holder the right to purchase EFH Corp. common stock for $5.00 pershare. The terms of the options were fixed at grant date. One-half of the options initially granted were to vest solely based uponcontinued employment over a specific period of time, generally five years, with the options vesting ratably on an annual basisover the period (Time-Based Options). One-halfofthe options initially granted were to vest based upon both continued employmentand the achievement of targeted five-year EFH Corp. EBITDA levels (Performance-Based Options). Prior to vesting, expenseswere recorded if the achievement of the EBITDA levels was probable, and amounts recorded were adjusted or reversed if theprobability of achievement of such levels changed. Probability of vesting was evaluated at least each quarter. The stock optionexpense presented in the table above relates to Time-Based Options except for $1.6 million in 2010 related to Performance-BasedOptions.In October 2009, in consideration of the then recent economic dislocation and the desire to provide incentives for retention,grantees of Performance-Based Options (excluding named executive officers and a small group of other employees) were providedan offer, which substantially all accepted, to exchange their unvested Performance-Based Options granted under the 2007 SIPwith a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options (Cliff-VestingOptions) with a strike price of $3.50 per share (the then most recent market valuation of each share), with one-half of these optionsto vest in September 2012 and one-half of these options to vest in September 2014. Additionally, certain named executive officersand a small group of other employees were granted an aggregate 2.0 million Cliff-Vesting Options with a strike price of $3.50 pershare, to vest in September 2014, and substantially all of these employees also accepted an offer to exchange half of their unvestedPerformance-Based Options with a strike price of $5.00 per share and a vesting schedule through December 2012 for new time-based stock options with a strike price of $3.50 per share, to vest in September 2014.136 Table of ContentsIn December 2010, in consideration of the desire to enhance retention incentives, EFH Corp. offered employee grantees ofall stock options (excluding named executive officers and a limited number of other employees) the right to exchange their vestedand unvested options for restricted stock units payable in shares (at a ratio of two options for each stock unit). The exchange offerclosed in February 2011, and substantially all of our eligible employees accepted the offer, which resulted in the issuance of 6.5million restricted stock units in exchange for 11.1 million time-based options (including 3.5 million that were vested) and 1.9million performance-based options (including 1.4 million that were vested).In October 2011, in consideration of the desire to enhance retention incentives, EFH Corp. offered its named executiveofficers and a limited number of other officers (including certain of our officers) the right to exchange their vested and unvestedoptions for restricted stock units payable in shares on terms largely consistent with offers made in December2010 to other employeegrantees of stock options. The exchange offer closed in October 2011, and all eligible employees accepted the offer, which resultedin the issuance of 4.6 million restricted stock units in exchange for 7.3 million time-based options (including 3.2 million that werevested) and 1.9 million performance-based options (including 1.8 million that were vested).The fair value of all options granted was estimated using the Black-Scholes option pricing model and the assumptions notedin the table below. Since EFH Corp. is a private company, expected volatility was based on actual historical experience ofcomparable publicly-traded companies for a term corresponding to the expected life of the options. The expected life representsthe period of time that options granted were expected to be outstanding and was calculated using the simplified method prescribedby the SEC Staff Accounting Bulletin No. 107. The simplified method was used since EFH Corp. did not have stock option historyupon which to base the estimate of the expected life and data for similar companies was not reasonably available. The risk-freerate was based on the US Treasury security with terms equal to the expected life of the option at the grant date.The weighted average grant-date fair value of the Time-Based Options granted in 2010 was $1.36 per option.Assumptions supporting the fair values were as follows:Year EndedDecember 31, 2010Time-BasedAssumptions: OptionsExpected volatility 35%Expected annual dividendExpected life (in years) 6.8Risk-free rate 2.99%Compensation expense for Time-Based Options is based on the grant-date fair value and recognized over the original vestingperiod as employees perform services. At December 31, 2012, there was no unrecognized compensation expense related tononvested Time-Based Options granted to employees. The exchange oftime-based options for restricted stock units was considereda modification of the option award for accounting purposes.137 Table of ContentsA summary of Time-Based Options activity is presented below:Time-Based Options Activity in 2011:Total outstanding at beginning of periodGrantedExercisedForfeitedExchangedTotal outstanding at end of period (weighted average remaining term of 6 -10 years)Exercisable at end of period (weighted average remaining term of 6 -10 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 6 -10 years)WeightedAverageOptions Exercise(millions) Price18.7 $ 4.30(18.4) $0.3 $(0.3) $4.304.304.30WeightedAverageOptions Exercise(millions) Price20.0 $ 4.34Time-Based Options Activity in 2010:Total outstanding at beginning of periodGrantedExercisedForfeitedTotal outstanding at end of period (weighted average remaining term of 7 -10 years)Exercisable at end of period (weighted average remaining term of 7 -10 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 7 -10 years)0.2 $(1.5) $18.7 $(2.5) $(0.1) $16.1 $2.184.594.304.775.004.2220112010Nonvested Time-Based Options Activity:Total nonvested at beginning of periodGrantedVestedForfeitedExchangedTotal nonvested at end of periodOptions Grant-Date Options Grant-Date(millions) Fair Value (millions) Fair Value11.7 $ 1.55 15.5 $ 1.63-$ -0.2 $ 1.36-$ -- (2.5) $ 1.92-$ -(1.5) $ 1.72(11.7) $ 1.55 -$ --$ -11.7 $ 1.55Compensation expense for Performance-Based Options was based on the grant-date fair value and recognized over therequisite performance and service periods for each tranche of options depending upon the achievement of financial performance.At December 31,2012, there was no unrecognized compensation expense related to nonvested Performance-Based Optionsbecause the options are no longer expected to vest as a result of exchanges. A total of 2.4 million of the 2008 and 0.9 million ofthe 2009 Performance-Based Options had vested.138 Table of ContentsA summary of Performance-Based Options activity is presented below:OptionsPerformance-Based Options Activity in 2011: (millions)Outstanding at beginning of period 3.8GrantedExercisedForfeitedExchanged (3.8)Total outstanding at end of period (weighted average remaining term of 6 -8 years)WeightedAverageExercisePrice$ 5.005.00$Exercisable at end of period (weighted average remaining term of 6 -8 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 6 -8 years)-S$OptionsPerformance-Based Options Activity in 2010: (millions)Outstanding at beginning of period 4.9GrantedExercisedForfeited (1.1)ExchangedTotal outstanding at end of period (weighted average remaining term of 7 -10 years)WeightedAverageExercisePrice$ 5.00$$Exercisable at end of period (weighted average remaining term of 7 -10 years)Expected forfeituresExpected to vest at end of period (weighted average remaining term of 7 -10 years)3.8 $(0.9) $5.005.005.005.002.9 $Performance-Based Nonvested Options Activity:Total nonvested at beginning of periodGrantedVestedForfeitedExchangedTotal nonvested at end of period2011 2010Options Grant-Date Options Grant-Date(millions) Fair Value (millions) Fair Value0.5 $1.16 -$2.01 2.5 $1.16 -$2.01..... (0.9) $1.77 -$1.87....(1.1) $1.65 -$1.87(0.5) $1.16 -$2.01-$1.16 -$2.010.5 $1.16 -$2.01139 Table of ContentsOther Share and Share-BasedAwards -In 2008, EFH Corp. granted 1.75 million deferred share awards, each of whichrepresents the right to receive one share of EFH Corp. stock, to certain of our management employees who agreed to forego share-based awards that vested at the Merger date. The deferred share awards are fully vested and are payable in cash or stock upon theearlier of a change of control or separation of service. No expense was recorded in 2008 related to these awards. An additional150 thousand deferred share awards were granted to certain of our management employees in 2008, which are payable in cash orstock, all of which have since vested or have been surrendered upon termination of employment. No expense was recognized in2012 or 2011. Expenses recognized in 2010 related to these grants totaled $0.1 million. The deferred share awards are accountedfor as liability awards; therefore, the effects of changes in estimated value of EFH Corp. shares are recognized in earnings. As aresult of the decline in estimated value of EFH Corp. shares, share-based compensation expense in 2012, 2011 and 2010 wasreduced by $1.0 million, $1.0 million and $1.9 million, respectively.140 Table of Contents15. RELATED-PARTY TRANSACTIONSThe following represent our significant related-party transactions.TCEH's retail operations pay Oncor for services it provides, principally the delivery of electricity. Expenses recordedfor these services totaled $1.0 billion, $1.0 billion and $1.1 billion for the years ended December 31, 2012, 2011 and2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets atDecember 31, 2012 and 2011 reflect amounts due currently to Oncor totaling $53 million and $138 million, respectively,(included in trade accounts and other payables to affiliates) primarily related to these electricity delivery fees.In August 2012, TCEH and Oncor agreed to settle at a discount two agreements related to securitization (transition) bondsissued by Oncor's bankruptcy-remote financing subsidiary in 2003 and 2004 to recover generation-related regulatoryassets. Under the agreements, TCEH had been reimbursing Oncor as described immediately below. Under the settlement,TCEH paid, and Oncor received, $159 million in cash. The settlement was executed by EFIH acquiring the right toreimbursement under the agreements from Oncor and then selling these rights for the same amount to TCEH. Thetransaction resulted in a $2 million (after tax) increase in equity for the year ended December 31, 2012 in accordancewith accounting rules for related party transactions.Oncor collects transition surcharges from its customers to recover the transition bond payment obligations. Oncor'sincremental income taxes related to the transition surcharges it collects had been reimbursed by TCEH quarterly undera noninterest bearing note payable to Oncor that was to mature in 2016. The note balance at the August 2012 settlementdate totaled $159 million. TCEH's payments on the note totaled $20 million, $39 million and $37 million for the yearsended December 31, 2012, 2011 and 2010, respectively.Under an interest reimbursement agreement, TCEH had reimbursed Oncor on a monthly basis for interest expense onthe transition bonds. The remaining interest to be paid through 2016 under the agreement totaled $53 million at theAugust 2012 settlement date. Only the monthly accrual of interest under this agreement was reported as a liability. Thisinterest expense totaled $16 million, $32 million and $37 million for the years ended December 31, 2012, 2011 and 2010,respectively.Notes receivable from EFH Corp. are payable to TCEH on demand (TCEH Demand Notes) and arise from cash loanedfor debt principal and interest payments and other general corporate purposes of EFH Corp. At December 31, 2012 and2011, the notes consisted of:December 31,2012 2011Note related to debt principal and interest payments (P&I Note) $ 465 $ 1,359Note related to general corporate purposes (SG&A Note) 233 233Total $ 698 $ 1,592The TCEH Demand Notes were guaranteed by EFIH and EFCH on a senior unsecured basis. In connection with theamendment to the TCEH Senior Secured Facilities discussed in Note 8, $770 million of the SG&A Note was repaid inApril 2011. The TCEH Demand Notes were pledged as collateral under the TCEH Senior Secured Facilities. In February2012, $950 million of the P&I Note was repaid by EFH Corp. The repayment was funded by a debt issuance at EFIH inFebruary 2012. At December 31, 2012, EFIH had in escrow $680 million of the proceeds from its August 2012 debtissuance to pay a dividend to EFH Corp., which EFH Corp. had agreed to use to repay the balance of the TCEH DemandNotes. The average daily balance of the TCEH Demand Notes totaled $789 million, $1.542 billion and $1.588 billionfor the years ended December 31, 2012, 2011 and 2010, respectively. The TCEH Demand Notes carried interest at a ratebased on the one-month LIBOR rate plus 5.00%, and interest income related to the TCEH Demand Notes totaled $42million, $82 million and $85 million for the years ended December 31, 2012, 2011 and 2010, respectively. In January2013, EFH Corp. repaid the balance of the TCEH Demand Notes.141 Table of Contents" TCEH had a demand note payable to EFH Corp. totaling $770 million for the period January to April 2011 and for theperiod February to December 2010. The proceeds from the note were used to repay borrowings under the TCEH RevolvingCredit Facility. The average daily balance of the note was $184 million and $644 million for the years ended December2011 and 2010, respectively. The note carried interest at a rate based on the one-month LIBOR rate plus 3.50%, andinterest expense related to this note totaled $7 million and $25 million for the years ended December 31, 2011 and 2010,respectively. In addition, EFCH has a demand note payable to EFH Corp., the proceeds from which were used to repayoutstanding debt. The note totaled $81 million and $57 million at December 31, 2012 and 2011, respectively, and carriedinterest at a rate based on the one-month LIBOR rate plus 5.00%. Interest expense related to this note totaled $3 million,$2 million and $1 million for the years ended December 31, 2012, 2011 and 2010, respectively." Receivables from affiliates are measured at historical cost and primarily consist of notes receivable for cash loaned toEFH Corp. for debt principal and interest payments and other general corporate purposes of EFH Corp. as discussedabove. TCEH reviews economic conditions, counterparty credit scores and historical payment activity to assess theoverall collectability of its affiliated receivables. There were no credit loss allowances at December 31, 2012 and 2011,respectively." A subsidiary of EFH Corp. bills our subsidiaries for information technology, financial, accounting and other administrativeservices at cost. These charges, which are settled in cash and primarily reported in SG&A expenses, totaled $265 million,$213 million and $193 million for the years ended December 31, 2012, 2011 and 2010, respectively. Effective in 2012,TCEH reimburses a subsidiary of EFH Corp. for an allocated share of computer equipment purchased by the subsidiary.Amounts paid by TCEH in 2012 included existing computer equipment and totaled $38 million, which was accountedfor as an intangible asset to be amortized over the life of the equipment. Previously, the depreciation of such equipmentwas included in the administrative cost billings." Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facilityis funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to TCEH forcontribution in the trust fund with the intent that the trust fund assets, reported in investments in our balance sheet, willultimately be sufficient to fund the actual future decommissioning liability, reported in noncurrent liabilities in our balancesheet. The delivery fee surcharges remitted to TCEH totaled $16 million, $17 million and $16 million for the years endedDecember 31, 2012, 2011 and 2010, respectively. Income and expenses associated with the trust fund and thedecommissioning liability incurred by TCEH are offset by a net change in a receivable/payable that ultimately will besettled through changes in Oncor's delivery fee rates. At December 31, 2012 and 2011, the excess of the trust fund balanceover the decommissioning liability resulted in a payable totaling $284 million and $225 million, respectively, includedin other noncurrent liabilities in our balance sheet.EFH Corp. files consolidated federal income tax and Texas state margin tax returns that include our results; however,under a tax sharing agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts,including income taxes payable to or receivable from EFH Corp., are recorded as if we file our own corporate incometax return. As a result, we had income taxes payable to EFH Corp. of $31 million and $74 million at December 31, 2012and 2011, respectively. We made income tax net payments to EFH Corp. of $84 million, $123 million and $49 millionfor the years ended December 31, 2012, 2011 and 2010, respectively." Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of anyREP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility.Under these tariffs, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateralsupport in an amount equal to estimated transition charges over specified time periods. Accordingly, at December 31,2012 and 2011, TCEH had posted letters of credit in the amount of $11 million and $12 million, respectively, for thebenefit of Oncor." Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstandingissues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter ofcredit in an amount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred,two or more rating agencies downgrade Oncor's credit rating below investment grade.In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders.These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of eachmember of the Sponsor Group have from time to time engaged in commercial banking transactions with us and/or providedfinancial advisory services to us, in each case in the normal course of business.142 Table of Contents* For the year ended December 31,2011, fees paid to Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners,related to debt issuances, exchanges, amendments and extensions totaled $26 million, described as follows: (i) Goldmanacted as a joint lead arranger and joint book-runner in the April 2011 amendment and extension of the TCEH SeniorSecured Facilities (see Note 8) and received fees totaling $17 million and (ii) Goldman acted as a joint book-runningmanager and initial purchaser in the issuance of $1.750 billion principal amount of TCEH Senior Secured Notes as partof the April 2011 amendment and extension and received fees totaling $9 million. Affiliates of KKR and TPG served asadvisers to these transactions, and each received $5 million as compensation for their services." Affiliates of GS Capital Partners are parties to certain commodity and interest rate hedging transactions with us in thenormal course of business." Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issuedby us in open market transactions or through loan syndications." As a result of debt repurchase and exchange transactions in 2009 through 2011, EFH Corp. and EFIH held TCEH debtsecurities as follows (principal amounts):December 31,2012 2011TCEH Senior Notes:Held by EFH Corp. $ 284 $ 284Held by EFIH 79 79TCEH Term Loan Facilities:Held by EFH Corp. 19 19Total $ 382 $ 382Interest expense on the notes totaled $38 million, $34 million and $30 million for the years ended December 31, 2012,2011 and 2010, respectively.See Notes 8 and 9 for guarantees and push-down of certain EFH Corp. debt and Note 13 for allocation of EFH Corp. pensionand OPEB costs to us and amendments to the EFH Corp. pension plan in 2012.143 Table of Contents16. SUPPLEMENTARY FINANCIAL INFORMATIONInterest Expense and Related ChargesYear Ended December 31,2012 2011 2010Interest paid/accrued (including net amounts settled/accrued under interestrate swaps)Interest related to pushed down debtAccrued interest to be paid with additional toggle notes (Note 8)Unrealized mark-to-market net (gain) loss on interest rate swapsAmortization of interest rate swap losses at dedesignation of hedgeaccountingAmortization of fair value debt discounts resulting from purchaseaccountingAmortization of debt issuance, amendment and extension costs anddiscountsCapitalized interestTotal interest expense and related charges2,616 $75152(166)8112,540 $781668122,26621121720727178717182 183 122(36) (31) (60)S 2,842 $ 3,792 $ 3,067Restricted CashDecember 31, 2012 December 31, 2011Noncurrent NoncurrentCurrent Assets Assets Current Assets AssetsAmounts related to TCEH's Letter of Credit Facility (Note 8) $Amounts related to margin deposits heldTotal restricted cash $-$ 947 $ -$ 947--129 -$- 947 S 129 $ 947Inventories by Major CategoryDecember 31,2012 2011$ 201 $ 177Materials and suppliesFuel stockNatural gas in storageTotal inventories16820324 38$ 393 $ 418InvestmentsDecember 31,2012 2011$ 654 $ 574Nuclear plant decommissioning trustAssets related to employee benefit plans, including employee savings programs, net ofdistributionsLandMiscellaneous otherTotal other investments841710414$ 710 $ 629144 Table of ContentsNuclear Decommissioning Trust- Investments in a trust that will be used to fund the costs to decommission the ComanchePeak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as adelivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trustfund are offset by a corresponding change in a receivable/payable that will ultimately be settled through changes in Oncor's deliveryfees rates (see Note 15). A summary of investments in the fund follows:December 31, 2012Debt securities (b)Equity securities (c)TotalDebt securities (b)Equity securities (c)TotalFair marketCost (a) Unrealized gain Unrealized loss value$ 246 $ 16 $ (1) $ 261245 161 (13) 393$ 491 $ 177 $ (14) $ 654December 31, 2011Fair marketCost (a) Unrealized gain Unrealized loss value$ 231 $ 13 $ (2) $ 242230 121 (19) 332$ 461 $ 134 $ (21) $ 574(a) Includes realized gains and losses on securities sold.(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio ratingof AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with municipal bonds. Thedebt securities had an average coupon rate of 4.38% at both December 31,2012 and 2011 and an average maturity of 6 yearsat both December 31, 2012 and 2011.(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.Debt securities held at December 31, 2012 mature as follows: $94 million in one to five years, $55 million in five to tenyears and $112 million after ten years.The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and lossesfrom such sales.Realized gainsRealized lossesProceeds from sales of securitiesInvestments in securitiesYear Ended December 31,2012 2011 2010$ 1$ 1 $ 1$ (2) $ (3) $ (2)$ 106 $ 2,419 $ 974$ (122) $ (2,436) $ (990)Property, Plant and EquipmentDecember 31,Generation and miningOther assetsTotalLess accumulated depreciationNet of accumulated depreciationConstruction work in progressNuclear fuel (net of accumulated amortization of $941 and $776)Held for saleProperty, plant and equipment -net2012 201123,144 $ 22,607452 42723,596 23,0345,845 4,72317,751 18,311444361575320-- 1218,556 $ 19,218145 Table of ContentsDepreciation expense totaled $1.228 billion, $1.330 billion and $ 1.245 billion for the years ended December 31, 2012,2011 and 2010, respectively.Assets related to capital leases included above totaled $70 million and $67 million at December 31, 2012 and 2011,respectively, net of accumulated depreciation.Asset Retirement and Mining Reclamation ObligationsThese liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining,removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is noearnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through theregulatory process as part of Oncor's delivery fees.The following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrentliabilities and deferred credits in the balance sheet, for the years ended December 31, 2012 and 2011:Mining LandNuclear Plant Reclamation andDecommissioning Other Total$ 329 $ 164 $ 493Liability at January 1, 2011Additions:AccretionIncremental reclamation costs (a)Reductions:PaymentsLiability at December 31, 2011Additions:AccretionIncremental reclamation costs (a)Reductions:PaymentsLiability at December 31, 2012Less amounts due currentlyNoncurrent liability at December 31, 20121929674867-(72) (72)$ 348 $ 188 $ 5362037365736-(93) (93)368 168 536-(84) (84)$ 368 $ 84 $ 452(a) Reflecting additional land to be reclaimed.Other Noncurrent Liabilities and Deferred CreditsThe balance of other noncurrent liabilities and deferred credits consists of the following:December 31,Uncertain tax positions (including accrued interest)Asset retirement and mining reclamation obligationsUnfavorable purchase and sales contractsNuclear decommissioning cost over-recovery (Note 15) (a)Retirement plan and other employee benefitsOtherTotal other noncurrent liabilities and deferred credits2012 2011$ 1,250 $ 1,220452 50562028428647225449 8$ 2,643 $ 2,649(a) Balance at December 31,2011 was previously classified as a liability due to affiliates. Because Oncor only acts as collectionagent to balance the amounts ultimately collected from its customers with the actual future cost to decommission the nuclearplant, the classification as a liability due Oncor was corrected.146 Table of ContentsUnfavorable Purchase and Sales Contracts -Unfavorable purchase and sales contracts primarily represent the extent towhich contracts on a net basis were unfavorable to market prices at the date of the Merger. These are contracts for which: (i)TCEH has made the "normal" purchase or sale election allowed or (ii) the contract did not meet the definition of a derivative underaccounting standards related to derivative instruments and hedging transactions. Under purchase accounting, TCEH recorded thevalue at October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is primarilyon a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of purchasedpower costs as appropriate. The amortization amount totaled $27 million, $26 million and $27 million for the years ended December31, 2012, 2011 and 2010, respectively. See Note 3 for intangible assets related to favorable purchase and sales contracts.The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:Year20132014201520162017Amount$ 26$$$$25252525Supplemental Cash Flow InformationYear Ended December 31,201120122010Cash payments (receipts) related to:Interest paid (a)Capitalized interestInterest paid (net of capitalized interest) (a)Income taxesNoncash investing and financing activities:Effect of Parent's payment of interest and issuance of toggle notes asconsideration for cash interest, net of tax, on pushed down debtPrincipal amount of TCEH Toggle Notes issued in lieu of cash interestConstruction expenditures (b)Contribution related to EFH Corp. stock-based compensationEffect of push down of debt from parentDebt exchange transactionsGain on termination of long-term power sales contract (Note 6)$ 2,569 $(36)$ 2,533 $$ 84 $2,469 $(31)2,438 $123 $$$$$$$$22 $181 $46 $5 $(282) $-S33 $162 $62 $5$(167) $2,269(60)2,20949(99)211837(1,618)527116(a) Net of interest received on interest rate swaps.(b) Represents end-of-period accruals.147 Table of Contents17. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATIONAt December 31, 2012 TCEH and TCEH Finance, as Co-Issuers, had outstanding $5.237 billion aggregate principal amountof 10.25% Senior Notes Due 2015, 10.25% Senior Notes due 2015 Series B and Toggle Notes (collectively, the TCEH SeniorNotes) and $1.571 billion aggregate principal amount of 15% Senior Secured Second Lien Notes due 2021 and 15% Senior SecuredSecond Lien Notes due 2021 (Series B) (collectively, the TCEH Senior Secured Second Lien Notes). The TCEH Senior Notesand the TCEH Senior Secured Second Lien Notes are unconditionally guaranteed by EFCH and by each subsidiary (all 100%owned by TCEH) that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The guarantees issued bythe Guarantors are full and unconditional, joint and several guarantees of the TCEH Senior Notes and the TCEH Senior SecuredSecond Lien Notes. The guarantees of the TCEH Senior Notes rank equally with any senior unsecured indebtedness of theGuarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing thatindebtedness. The guarantees of the TCEH Senior Secured Second Lien Notes rank equally in right of payment with all seniorindebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the valueof the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of paymentto any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH SeniorSecured Facilities, the TCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extentof the value of the TCEH Collateral (see Note 8). All other subsidiaries of EFCH, either direct or indirect, do not guarantee theTCEH Senior Notes or TCEH Senior Secured Second Lien Notes (collectively the Non-Guarantors). The indentures governingthe TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes contain certain restrictions, subject to certain exceptions,on EFCH's ability to pay dividends or make investments. See Note 10.The following tables have been prepared in accordance with Regulation S-X Rule 3-10, "Financial Statements of Guarantorsand Issuers of Guaranteed Securities Registered or Being Registered" in order to present the condensed consolidating statementsof income and of cash flows of EFCH (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors for the years endedDecember 31, 2012, 2011 and 2010 and the condensed consolidating balance sheets at December 31, 2012 and December 31,2011 of the Parent, Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted forunder the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5J, "Push Down BasisofAccounting Required in Certain Limited Circumstances," including the effects of the push down of $62 million and $319 millionof the EFH Corp. Senior Notes to the Parent at December 31,2012 and December 31,2011, respectively, $388 million of the EFHCorp. Senior Secured Notes to the Parent at both December 31, 2012 and December 31, 2011, and the TCEH Senior Notes, TCEHSenior Secured Notes, TCEH Senior Secured Second Lien Notes and TCEH Senior Secured Facilities to the Other Guarantors atDecember 31, 2012 and December 31, 2011 (see Note 8). TCEH Finance's sole function is to be the co-issuer of the certain TCEHdebt securities; therefore, it has no other independent assets, liabilities or operations.EFCH (parent entity) received no dividends/distributions from its consolidated subsidiaries for the years ended December31, 2012, 2011 and 2010.148 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Statements of Income (Loss)Year Ended December 31, 2012(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ -$ -$ 5,636 $ 31 $ (31) $ 5,636Operating revenuesFuel, purchased power costsand delivery feesNet gain from commodityhedging and trading activitiesOperating costsDepreciation and amortizationSelling, general andadministrative expensesFranchise and revenue-basedtaxesImpairment of goodwillOther incomeOther deductionsInterest incomeInterest expense and relatedchargesIncome (loss) before incometaxesIncome tax benefit (expense)Equity earnings (losses) ofsubsidiariesNet income (loss)Other comprehensive incomeComprehensive income (loss)-- (2,816)269120-(2,816)-- 389-(888)-(1,343)(888)-- (1,343)(!1)-- (1,200)6(662)(80)7(185)739(17)31(80)-- (1,200)(659)(3)(994)13(188)46301(90) (3,491) (2,374) (9) 3,122 (2,842)(90)30(4,126)1,005(1,846)6152(1)2,128(725)(3,932)924(2,948) 173 (2) -2,777 --(3,008) (2,948) (1,233) 1 4,180 (3,008)7 7 --(7) 7$ (3,001) $ (2,941) $ (1,233) $ 1 $ 4,173 $ (3,001)149 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Statements of Income (Loss)Year Ended December 31, 2011(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ -$ -$ 7,040 $ 11 $ (11) $ 7,040Operating revenuesFuel, purchased power costsand delivery feesNet gain (loss) fromcommodity hedging andtrading activitiesOperating costsDepreciation and amortizationSelling, general andadministrative expensesFranchise and revenue-basedtaxesOther incomeOther deductionsInterest incomeInterest expense and relatedchargesLoss before income taxesIncome tax benefitEquity earnings (losses) ofsubsidiariesNet lossOther comprehensive incomeComprehensive loss-- (3,396)1,018(7)-(3,396)-- 1,011-(924)-(1,470)-- (924)-- (1,470)(735)(96)58(437)694(4)11(728)(96)48(524)866(16)(87)381(989)(94) (4,370) (2,301) (7) 2,980 (3,792)(88) (3,074) (1,574) -1,991 (2,745)26 1,067 520 -(670) 943(1,740) 267 --1,473 --(1,802) (1,740) (1,054) -2,794 (1,802)19 19 --(19) 19$ (1,783) S (1,721) (1,054) $ -$ 2,775 $ (,783)150 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Statements of Income (Loss)Year Ended December 31, 2010(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ -$ -$ 8,223 S 12 $ -$ 8,235Operating revenuesFuel, purchased power costsand delivery feesNet gain from commodityhedging and trading activitiesOperating costsDepreciation and amortizationSelling, general andadministrative expensesFranchise and revenue-basedtaxesImpairment of goodwillOther incomeOther deductionsInterest incomeInterest expense and relatedchargesIncome (loss) before incometaxesIncome tax (expense) benefitEquity earnings (losses) ofsubsidiariesNet income (loss)Other comprehensive incomeComprehensive income (loss)(4,371)1,373788(837)(1,380)-(4,371)-2,161-(837)-(1,380)-- (4,100)727(718)(106)176(17)454(4)(722)(106)(4,100)903(18)90m1388(1)(753)(231) (3,409) (1,867) (6) 2,446 (3,067)(230)83(5,021)281345(91)I1,693(591)(3,212)(318)(3,383) 1,357 --2,026 _ _(3,530) (3,383) 254 1 3,128 (3,530)59 59 --(59) 59$ (3,471) $ (3,324) $ 254 $ 1 $ 3,069 $ (3,471)151 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Statements of Cash FlowsYear Ended December 31, 2012(millions of dollars)Parent/ Other Non-Guarantor Issuer Guarantors guarantors Eliminations ConsolidatedCash provided by (used in)operating activities (3) $ (964) S 963 $ (236) $ -$ (240)Cash flows -financingactivities:Notes due to affiliates 14 908 --(922) -Repayments/repurchases oflong-term debt (29) --(40)Net short-term borrowingsunder accounts receivablesecuritization program --(22) -(22)Increase in other short-termborrowings -1,384 ---1,384Decrease in income tax-related note payable to Oncor --(20) --(20)Settlement of reimbursementagreements with Oncor --(159) --(159)Contributions from parent ---300 (300) -Contributions fromnoncontrolling interests -- 7 -7Debt amendment, exchangeand issuance costs ---(5) -(5)Sale/leaseback of equipment --15 -15Other, net --1 --Cash provided by (usedin) financing activities 3 2,292 (192) 280 (1,222) 1,161Cash flows -investingactivities:Capital expenditures --(622) (9) -(631)Nuclear fuel purchases -(213) --(213)Notes/loans due fromaffiliates --4 -922 926Investment in subsidiary -(300) --300 -Purchase of right to usecertain computer-relatedassets from parent --(38) --(38)Proceeds from sales of assets --2 --2Changes in restricted cash --129 --129Purchases of environmentalallowances and credits -(25) --(25)Proceeds from sales ofnuclear decommissioningtrust fund securities -106 --106Investments in nucleardecommissioning trust fundsecurities --(122) --(122)Cash provided by (usedin) investing activities -(300) (779) (9) 1,222 134Net change in cash and cashequivalents -1,028 (8) 35 -1,055Cash and cash equivalents -87 23 10 1beginning balance -- 87 23 10__-- 120Cash and cash equivalents -ending balance $ S 1,115 $ 15 $ 45 $ -$ 1,175152 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Statements of Cash FlowsYear Ended December 31, 2011(millions of dollars)Cash provided by (used in)operating activitiesCash flows -financingactivities:Notes due to affiliatesIssuances of long-term debtRepayments/repurchases oflong-term debtNet short-term borrowingsunder accounts receivablesecuritization programDecrease in other short-termborrowingsDecrease in income tax-related note payable to OncorContributions fromnoncontrolling interestsDebt amendment, exchangeand issuance costsOther, netParent/ Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ (4) $ (1,572) S 2,827 $ (15) $ -$ 1,23612 2,370-- 1,750(8) (1,372)7 (2,389)1,750(28)-- (1,408)88(455)(455)(39)(39)1616(843)(843)-- (2) ---(2)Cash provided by (usedin) financing activities 4 1,448 (67) 31 (2,389) (973)Cash flows -investingactivities:Capital expenditures --(515) (15) -(530)Nuclear fuel purchases -(132) --(132)Notes/loans due fromaffiliates -(2,043) -2,389 346Proceeds from sales of assetsReduction of restricted cashrelated to TCEH letter ofcredit facilityOther changes in restrictedcashProceeds from sales ofenvironmental allowancesand creditsPurchases of environmentalallowances and creditsProceeds from sales ofnuclear decommissioningtrust fund securitiesInvestments in nucleardecommissioning trust fundsecuritiesOther, netCash provided by (usedin) investing activitiesNet change in cash and cashequivalentsCash and cash equivalents -beginning balanceCash and cash equivalents -ending balance4918849188(96)(96)1010(17)2,419(17)2,419-- (2,436)-- (2,436)-9 --9188 (2,752) (15) 2,389 (190)648I7323 15 9 -47$ -- $ 87 $ 23 $ 10 $ -$ 120153 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Statements of Cash FlowsYear Ended December 31, 2010(millions of dollars)Cash provided by (used in)operating activitiesCash flows -financingactivities:Issuances of long-term debtRepayments/repurchases oflong-term debtNet short-term borrowingsunder accounts receivablesecuritization programIncrease in other short-termborrowingsNotes/loans from affiliatesAdvances from affiliatesDecrease in income tax-related note payable to OncorContributions fromnoncontrolling interestsDebt discount, financing andreacquisition expensesOther, netCash provided by (usedin) financing activitiesCash flows -investingactivities:Net notes/loans to affiliatesCapital expendituresNuclear fuel purchasesProceeds from sales of assetsProceeds from sales ofenvironmental allowancesand creditsPurchases of environmentalallowances and creditsChanges in restricted cashProceeds from sales ofnuclear decommissioningtrust fund securitiesInvestments in nucleardecommissioning trust fundsecuritiesOther, netCash used in investingactivitiesNet change in cash and cashequivalentsEffect of consolidation of VIECash and cash equivalents -beginning balanceCash and cash equivalents -ending balanceParent/ Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ (22) S (829) $ 2,208 $ (100) $ -$ 1,257-350 3 --353(8) (550) (89) --(647)969634(4)172814(810)17234(37)(37)(13)3232(13)--37 --3722 786 (99) 128 (810) 27--(1,313) -810 (503)--(764) (32) -(796)--(106) --(106)--141 -1411212(30)(33)974(990)(30)(33)974(990)-- (l) 4 -- -(7)1- (1) (2,105) (32) 810 (1,338)(54)4(4)7(54)777 11 6 -94$ -$ 23 $ 15 $ 9 $ -$ 47154 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Balance SheetsDecember 31, 2012(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations ConsolidatedASSETSCurrent assets:Cash and cash equivalentsRestricted cashAdvances to affiliatesTrade accounts receivable -netNotes receivable from parentIncome taxes receivableAccounts receivable from affiliatesInventoriesCommodity and other derivativecontractual assetsAccumulated deferred income taxesMargin deposits related to commoditypositionsOther current assetsTotal current assetsRestricted cashInvestmentsProperty, plant and equipment -netNotes receivable from parentAdvances to affiliatesGoodwillIdentifiable intangible assets -netCommodity and other derivativecontractual assetsAccumulated deferred income taxesOther noncurrent assets, principallyunamortized amendment/issuance costsTotal assetsLIABILITIES AND EQUITYCurrent liabilities:Short-term borrowingsNotes/advances from affiliatesLong-term debt due currentlyTrade accounts payableTrade accounts and other payables toaffiliatesNotes payable to parentCommodity and other derivativecontractual liabilities$$- 1,115 $-- 2-- 698-- 9515 $45 $-$ 1,17536360410393336445(36)(97)(410)(95)7106983931,46331,1273(6)--71 --71--112 8 -1203 3,037 1,733 501 (644) 4,630-947 ---947(9,794) 23,382 747 9 (13,634) 710--18,422 134 -18,556--8,794-4,952 ---1,781(8,794) -4-- 4,952-- --1,781575828113 (831)5864 781 806 3 (783) 811$ (9,787) $ 34,502 $ 32,294 $ 650 $ (24,686) $ 32,973$-$ 2,054 $-- 8,83011 642,054 $82 $ (2,054) $-(8,830)212 387-231-- 1973(97)(95)2,136963891398180610284894155 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Balance SheetsDecember 31, 2012(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations ConsolidatedMargin deposits related to commoditypositionsAccumulated deferred income taxesAccrued income taxes payable toparentAccrued taxes other than incomeAccrued interestOther current liabilitiesTotal current liabilitiesAccumulated deferred income taxesCommodity and other derivativecontractual liabilitiesNotes or other liabilities due affiliatesLong-term debt held by affiliateLong-term debt, less amounts duecurrentlyOther noncurrent liabilities and deferredcreditsTotal liabilitiesEFCH shareholder's equityNoncontrolling interestsTotal equityTotal liabilities and equity5963452(6)60049312 4336 (410)--17 --1718 389 281 -(281) 4071 4 253 -(3) 255112 12,985 3,585 188 (11,776) 5,09479 -3,569 -111 3,759-- 1,5391751,5565382382515 29,355 28,486-(28,428) 29,92813 36 2,594 -- 2,643719 44,297 38,256 188 (40,093) 43,367(10,506) (9,795) (5,962) 350 15,407 (10,506)---112 -112(10,506) (9,795) (5,962) 462 15,407 (10,394)$ (9,787) $ 34,502 $ 32,294 $ 650 $ (24,686) $ 32,973=_156 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Balance SheetsDecember 31, 2011(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations ConsolidatedASSETSCurrent assets:Cash and cash equivalentsRestricted cashAdvances to affiliatesTrade accounts receivable -netNotes receivable from parentIncome taxes receivableAccounts receivable from affiliatesInventories -Commodity and other derivativecontractual assetsAccumulated deferred income taxesMargin deposits related to commoditypositionsOther current assetsTotal current assetsRestricted cashInvestmentsProperty, plant and equipment -netNotes receivable from parentAdvances to affiliatesGoodwillIdentifiable intangible assets -netCommodity and other derivativecontractual assetsAccumulated deferred income taxesOther noncurrent assets, principallyunamortized amendment/issuance costsTotal assetsLIABILITIES AND EQUITYCurrent liabilities:Short-term borrowingsNotes/advances from affiliatesLong-term debt due currentlyTrade accounts payableTrade accounts and other payables toaffiliatesNotes payable to parent/affiliateCommodity and other derivativecontractual liabilities$ -S87 $23 $12910 $525-414 651670 -859-418-- $ 120-- 129(41)(420) 760-67011(96)(9)418-1,63031,253-2,883(3)--56 -- -56--57 1 1 5914 2,485 2,628 536 (568) 5,095-947 ---947(6,860) 22,903 663 -- (16,077) 629--19,086 132 -19,218-922 -... 922--8,785 -(8,785) --- 6,152 ---6,152-1,826 --1,826-- 1,511-- 294411 (295)1,5526 974 902 6 (889) 999$ (6,840) $ 36,188 $ 33,931 $ 675 $ (26,614) $ 37,340$ -1011670 $ 670 $8,816 --28-- 552104 $ (670) $7 (8,826)7747395534213(420)57215804(9) 209-57-- 1,784980157 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCondensed Consolidating Balance SheetsDecember 31, 2011(millions of dollars)Margin deposits related to commoditypositionsAccumulated deferred income taxesAccrued income taxes payable toparentAccrued taxes other than incomeAccrued interestOther current liabilitiesTotal current liabilitiesAccumulated deferred income taxesCommodity and other derivativecontractual liabilitiesNotes or other liabilities due affiliatesLong-term debt held by affiliateLong-term debt, less amounts duecurrentlyOther noncurrent liabilities and deferredcreditsTotal liabilitiesEFCH shareholder's equityNoncontrolling interests in subsidiariesTotal equityTotal liabilities and equityParent Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated865 196 1,061452(3)53--170 -(96) 74--136 --13624 369 258 -(257) 394-11 257 1 (3) 266102 11,715 3,338 536 (10,284) 5,40782 -4,124 -506 4,7121,67038222138-- 1,692-- 138-- 382-(28,608) 30,076782 29,230 28,67213 52 2,583 -- 1 2,649979 43,049 38,877 536 (38,385) 45,056(7,819) (6,861) (4,946) 36 11,771 (7,819)---103 -103(7,819) (6,861) (4,946) 139 11,771 (7,716)$ (6,840) $ 36,188 $ 33,931 $ 675 $ (26,614) $ 37,340158 Table of ContentsItem 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURENone.Item 4. CONTROLS AND PROCEDURESAn evaluation was performed under the supervision and with the participation of our management, including the principalexecutive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls andprocedures in effect at December 31,2012. Based on the evaluation performed, our management, including the principal executiveofficer and principal financial officer, concluded that the disclosure controls and procedures were effective.There has been no change in our internal control over financial reporting during the most recently completed fiscal quarterthat has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.159 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANYMANAGEMENT'S ANNUAL REPORT ONINTERNAL CONTROL OVER FINANCIAL REPORTINGThe management of Energy Future Competitive Holdings Company is responsible for establishing and maintaining adequateinternal control over financial reporting (as defined in Rules 13a- 15(f) and 15d-I 5(f) under the Securities Exchange Act of 1934)for the company. Energy Future Competitive Holdings Company's internal control over financial reporting is designed to providereasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposesin accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financialreporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subjectto the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with proceduresor policies.The management of Energy Future Competitive Holdings Company performed an evaluation as of December 31, 2012 of theeffectiveness of the company's internal control over financial reporting based on the Committee of Sponsoring Organizations ofthe Treadway Commission's (COSO's) Internal Control -Integrated Framework. Based on the review performed, managementbelieves that as of December 31, 2012 Energy Future Competitive Holdings Company's internal control over financial reportingwas effective.The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statementsof Energy Future Competitive Holdings Company has issued an attestation report on Energy Future Competitive HoldingsCompany's internal control over financial reporting./s/ JOHN F. YOUNG /s/ PAUL M. KEGLEVICJohn F. Young, Chair, President and Paul M. Keglevic, Executive Vice PresidentChief Executive and Chief Financial OfficerFebruary 19, 2013160 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and Shareholders of Energy Future Competitive Holdings CompanyDallas, TexasWe have audited the internal control over financial reporting of Energy Future Competitive Holdings Company (a subsidiary ofEnergy Future Holdings Corp.) and subsidiaries ("EFCH") as of December 31, 2012 based on criteria established in InternalControl -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. EFCH'smanagement is responsible for maintaining effective internal control over financial reporting and for its assessment of theeffectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on InternalControl Over Financial Reporting. Our responsibility is to express an opinion on EFCH's internal control over financial reportingbased on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal controlover financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal controlover financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operatingeffectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary inthe circumstances. We believe that our audit provides a reasonable basis for our opinion.A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principalexecutive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors,management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles. A company's internalcontrol over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonableassurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timelydetection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financialstatements.Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or impropermanagement override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subjectto the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.In our opinion, EFCH maintained, in all material respects, effective internal control over financial reporting as of December 31,2012, based on the criteria established in Internal Control -Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission.We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), theconsolidated financial statements as of and for the year ended December 31, 2012 of EFCH and our report dated February 19,2013 expressed an unqualified opinion on those financial statements and included an emphasis of matter paragraph related to (1)EFCH's continued net losses, substantial indebtedness and significant cash interest requirements and EFCH's ability to satisfy itsobligations in October 2014, which include the maturities of $3.8 billion of Texas Competitive Electric Holdings Company LLC("TCEH") Term Loan Facilities, being dependent upon completion of one or more actions described in Note I to the consolidatedfinancial statements and (2) TCEH's loans, which are payable on demand, to its indirect parent, Energy Future Holdings Corp./s/ DELOITrE & ToucHE LLPDallas, TexasFebruary 19, 2013161 Table of ContentsItem 9b. OTHER INFORMATIONNonePART IIIItem 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEItem 10 is not presented as EFCH meets the conditions set forth in General Instruction (I)(1)(a) and (b).Item 11. EXECUTIVE COMPENSATIONItem II is not presented as EFCH meets the conditions set forth in General Instruction (1)(1)(a) and (b).Item 12,SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERSItem 12 is not presented as EFCH meets the conditions set forth in General Instruction (I)(])(a) and (b).Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCEItem 13 is not presented as EFCH meets the conditions set forth in General Instruction (I)(1)(a) and (b).162 Table of ContentsItem 14. PRINCIPAL ACCOUNTING FEES AND SERVICESDeloitte & Touche LLP has been the independent auditor for EFH Corp. and for its Predecessor (TXU Corp.) since itsorganization in 1996.The Audit Committee of the EFH Corp. Board of Directors has adopted a policy relating to the engagement of EFH Corp.'sindependent auditor that applies to EFH Corp. and its consolidated subsidiaries, including EFCH. The policy provides that inaddition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessaryto complete SEC filings, EFH Corp.'s independent auditor may be engaged to provide non-audit services as described herein.Prior to engagement, all services to be rendered by the independent auditor must be authorized by the Audit Committee in accordancewith preapproval procedures which are defined in the policy. The preapproval procedures require:1. The annual review and preapproval by the Audit Committee of all anticipated audit and non-audit services; and2. The quarterly preapproval by the Audit Committee of services, if any, not previously approved and the review of thestatus of previously approved services.The Audit Committee may also approve certain on-going non-audit services not previously approved in the limitedcircumstances provided for in the SEC rules. All services performed by Deloitte & Touche LLP, the member firms of DeloitteTouche Tohmatsu and their respective affiliates ("Deloitte & Touche") for EFH Corp. in 2012 were preapproved by the AuditCommittee.The policy defines those non-audit services which EFH Corp.'s independent auditor may also be engaged to provide asfollows:1. Audit related services, including:a. due diligence accounting consultations and audits related to mergers, acquisitions and divestitures;b. employee benefit plan audits;c. accounting and financial reporting standards consultation;d. internal control reviews, ande. attest services, including agreed-upon procedures reports that are not required by statute or regulation.2. Tax related services, including:a. tax compliance;b. general tax consultation and planning;c. tax advice related to mergers, acquisitions, and divestitures, andd. communications with and request for rulings from tax authorities.3. Other services, including:a. process improvement, review and assurance;b. litigation and rate case assistance;c. forensic and investigative services, andd. training services.The policy prohibits EFCH from engaging its independent auditor to provide:1. Bookkeeping or other services related to EFCH's accounting records or financial statements;2. Financial information systems design and implementation services;3. Appraisal or valuation services, fairness opinions, or contribution-in-kind reports;4. Actuarial services;5. Internal audit outsourcing services;6. Management or human resource functions;7. Broker-dealer, investment advisor, or investment banking services;8. Legal and expert services unrelated to the audit, and9. Any other service that the Public Company Accounting Oversight Board determines, by regulation, to be impermissible.In addition, the policy prohibits EFCH's independent auditor from providing tax or financial planning advice to any officerof EFCH.Compliance with the Audit Committee's policy relating to the engagement of Deloitte & Touche is monitored on behalf ofthe Audit Committee by EFH Corp.'s chief accounting officer. Reports describing the services provided by Deloitte & Touche andfees for such services are provided to the Audit Committee no less often than quarterly.163 Table of ContentsFor the years ended December 31,2012 and 2011, fees billed (in US dollars) to EFCH by Deloitte & Touche were as follows:2012 2011Audit Fees. Fees for services necessary to perform the annual audit, review SEC filings,fulfill statutory and other service requirements, provide comfort letters and consentsAudit-Related Fees. Fees for services including employee benefit plan audits, due diligencerelated to mergers, acquisitions and divestitures, accounting consultations and audits inconnection with acquisitions, internal control reviews, attest services that are not required bystatute or regulation, and consultation concerning financial accounting and reportingstandardsTax Fees. Fees for tax compliance, tax planning, and tax advice related to mergers andacquisitions, divestitures, and communications with and requests for rulings from taxingauthorities$ 5,642,000 $506,0006,035,500326,000All Other Fees. Fees for services including process improvement reviews, forensicaccounting reviews, litigation assistance, and training servicesTotal256,0006,404,000 $ 6,361,500PART IVItem 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES(b) Exhibits:EFCH's Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012PreviouslyFiled* With FileNumberExhibits(3)AsExhibitArticles of Incorporation and By-laws3(a) 333-153529Form S-4 (filedSeptember 17, 2008)3(b) 333-153529Form S-4 (filedSeptember 17, 2008)3(b)3(e)-Second Amended and Restated Articles of Incorporationof Energy Future Competitive Holdings Company(formerly known as TXU US Holdings Company)-Restated Bylaws of Energy Future Competitive HoldingsCompany (formerly known as TXU US HoldingsCompany)(4) Instruments Defining the Rights of Security Holders, Including Indentures**Energy Future Holdings Corp. (Merger-related push down debt)4(a) 1-12833Form 8-K (filedOctober 31, 2007)4(b) 1-12833Form 10-K (2009) (filedFebruary 19, 2010)4(c) 1-12833Form I0-Q(Quarter endedJune 30, 2009)(filed August 4, 2009)4(d) 1-12833Form 8-K (filedJuly 30, 2010)4.14(f)4(a)-Indenture, dated October 31,2007, among Energy FutureHoldings Corp., the guarantors named therein and TheBank of New York Mellon, as trustee, relating to SeniorNotes due 2017 and Senior Toggle Notes due 2017.-Supplemental Indenture, dated July 8, 2008, to theIndenture, dated October 31, 2007.-Second Supplemental Indenture, dated August 3, 2009,to the Indenture, dated October 31, 2007.-Third Supplemental Indenture, dated July 29,2010, to theIndenture, dated October 31, 2007.99.1164 Table of ContentsEFCH's Exhibits to Form 10-K for the Fiscal Year Ended December 31, 20124(e) 1-12833 Form 10-Q (Quarter endedSeptember 30, 2011) (filed October 28,2011)4(f) 1-12833Form 8-K (filedNovember 20, 2009)4(b)4.14.14(g)1-12833 Form 8-K (filed January 30,2013)4(h) 333-171253Form S-4 (filedJanuary24, 2011)4(i) 333-165860Form S-3 (filedApril 1,2010)4(k)40)4(j) 1-12833Form 10-Q(Quarter endedJune 30, 2010)(filed August 2, 2010)4(k) 1-12833Form 10-Q(Quarter endedJune 30, 2010)(filed August 2, 2010)4(a)Fourth Supplemental Indenture, dated October 18, 2011,to the Indenture dated October 31, 2007.Indenture, dated November 16, 2009, among EnergyFuture Holdings Corp., the guarantors named therein andThe Bank of New York Mellon Trust Company, N.A., astrustee, relating to 9.75% Senior Secured Notes due 2019.Supplemental Indenture, dated January 25, 2013, to theIndenture, dated November 16, 2009, among EnergyFuture Holdings Corp., the guarantors named therein andThe Bank of New York Mellon Trust Company, N.A., astrustee, relating to 9.75% Senior Secured Notes due 2019.Indenture, dated January 12, 2010, among Energy FutureHoldings Corp., the guarantors named therein and TheBank of New York Mellon Trust Company, N.A., astrustee, relating to 10.000% Senior Secured Notes due2020.First Supplemental Indenture, dated March 16, 2010, tothe Indenture, dated January 12, 2010, among EnergyFuture Holdings Corp., the guarantors named therein andThe Bank of New York Mellon Trust Company, N.A., astrustee, relating to 10.000% Senior Secured Notes due2020.-Second Supplemental Indenture, dated April 13, 2010, tothe Indenture, dated January 12, 2010, among EnergyFuture Holdings Corp., the guarantors named therein andThe Bank of New York Mellon Trust Company, N.A., astrustee, relating to 10.000% Senior Secured Notes due2020.-Third Supplemental Indenture, dated April 14, 2010, tothe Indenture, dated January 12, 2010, among EnergyFuture Holdings Corp., the guarantors named therein andThe Bank of New York Mellon Trust Company, N.A., astrustee, relating to 10.000% Senior Secured Notes due2020.-Fourth Supplemental Indenture, dated May 21, 2010, tothe Indenture, dated January 12, 2010, among EnergyFuture Holdings Corp., the guarantors named therein andThe Bank of New York Mellon Trust Company, N.A., astrustee, relating to 10.000% Senior Secured Notes due2020.-Fifth Supplemental Indenture, dated July 2, 2010, to theIndenture, January 12, 2010, among Energy FutureHoldings Corp., the guarantors named therein and TheBank of New York Mellon Trust Company, N.A., astrustee, relating to 10.000% Senior Secured Notes due2020.-Sixth Supplemental Indenture, dated July 6, 2010, to theIndenture, dated January 12, 2010, among Energy FutureHoldings Corp., the guarantors named therein and TheBank of New York Mellon Trust Company, N.A., astrustee, relating to 10.000% Senior Secured Notes due2020.4(b)4(1)1-12833Form l0-Q(Quarter endedJune 30, 2010)(filed August 2, 2010)4(c)4(m) 1-12833Form I0-Q(Quarter endedJune 30, 2010)(filed August 2, 2010)4(n) 1-12833Form I0-Q(Quarter endedJune 30, 2010)(filed August 2, 2010)4(d)4(e)165 Table of ContentsEFCH's Exhibits to Form 10-K for the Fiscal Year Ended December 31, 20124(o) 333-171253Form S-4 (filedJanuary 24, 2011)4(p) 1-12833 Form 8-K (filed January 30,2013)4(r)4.2Texas Competitive Electric Holdings Company LLC4(q) 333-108876Form 8-K (filedOctober 31, 2007)4.24(r)4(s)4(t)1-12833Form 8-K (filedDecember 12, 2007)1-12833Form 10-Q(Quarter endedJune 30, 2009)(filed August 4, 2009)1-12833Form 8-K (filedOctober 8, 2010)4.14(b)4.14.14.14(a)4.3Seventh Supplemental Indenture, dated July 7, 2010, tothe Indenture, dated January 12, 2010, among EnergyFuture Holdings Corp., the guarantors named therein andthe Bank of New York Mellon Trust Company, N.A., astrustee, relating to 10,000% Senior Secured Notes due2020.-Eighth Supplemental Indenture, dated January 25, 2013,to the Indenture, dated January 12, 2010, among EnergyFuture Holdings Corp., the guarantors named therein andThe Bank of New York Mellon Trust Company, N.A., astrustee, relating to 10.000% Senior Secured Notes due2020.-Indenture, dated October 31, 2007, among TexasCompetitive Electric Holdings Company LLC and TCEHFinance, Inc., the guarantors and The Bank of New YorkMellon Trust Company, N.A., as trustee, relating to10.25% Senior Notes due 2015.-First Supplemental Indenture, dated December 6, 2007,to the Indenture, dated October 31,2007, relating to TexasCompetitive Electric Holdings Company LLC's andTCEH Finance, Inc.'s 10.25% Senior Notes due 2015,Series B, and 10.50%/11.25% Senior Toggle Notes due2016.Second Supplemental Indenture, dated August 3, 2009,to the Indenture, dated October 31,2007, relating to TexasCompetitive Electric Holdings Company LLC's andTCEH Finance, Inc.'s 10.25% Senior Notes due 2015,10.25% Senior Notes due 2015, Series B, and10.50%/11.25% Senior Toggle Notes due 2016.-Indenture, dated October 6, 2010, among TexasCompetitive Electric Holdings Company LLC and TCEHFinance, Inc., the guarantors and The Bank of New YorkMellon Trust Company, N.A., as trustee, relating to 15%Senior Secured Second Lien Notes due 2021.-First Supplemental Indenture, dated October 20, 2010, tothe Indenture, dated October 6, 2010.-Second Supplemental Indenture, dated November 15,2010, to the Indenture, dated October 6, 2010.-Third Supplemental Indenture, dated as of September 26,2011, to the Indenture, dated October 6, 2010.Second Lien Pledge Agreement, dated October 6, 2010,among Texas Competitive Electric Holdings CompanyLLC, TCEH Finance, Inc., the subsidiary guarantorsnamed therein and The Bank of New York Mellon TrustCompany, N.A., as collateral agent for the benefit of thesecond lien secured parties.4(u) 1-12833Form 8-K (filedOctober 26, 2010)4(v) 1-12833Form 8-K (filedNovember 17, 2010)4(w) 1-12833 Form I0-Q (Quarter endedSeptember 30, 2011) (filed October 28,2011)4(x) 1-12833Form 8-K (filedOctober 8, 2010)166 Table of ContentsEFCH's Exhibits to Form 10-K for the Fiscal Year Ended December 31, 20124(y)1-12833Form 8-K (filedOctober 8, 2010)4(z) 1-12833Form 8-K (filedOctober 8, 2010)4(aa) 1-12833Form 10-K (filedFebruary 18, 2011)4(bb) 1-12833Form 8-K (filedApril 20, 2011)4(cc) 1-12833 Form 8-K (filed April 20, 2011)4(dd) 1-12833 Form 8-K (filed April 20, 2011)4(ee) 1-12833Form 8-K (filedApril 20, 2011)4.4 Second Lien Security Agreement, dated October 6,2010,among Texas Competitive Electric Holdings CompanyLLC, TCEH Finance, Inc., the subsidiary guarantorsnamed therein and The Bank Of New York Mellon TrustCompany, N.A., as collateral agent and as the initialsecond priority representative for the benefit ofthe secondlien secured parties.4.5 Second Lien Intercreditor Agreement, dated October 6,2010, among Texas Competitive Electric HoldingsCompany LLC, TCEH Finance, Inc., the subsidiaryguarantors named therein, Citibank, N.A., as collateralagent for the senior collateral agent and the administrativeagent, The Bank of New York Mellon Trust Company,N.A., as the initial second priority representative.4(aaa) Form of Second Deed of Trust, Assignment of Leases andRents, Security Agreement and Fixture Filing to FidelityNational Title Insurance Company, as trustee, for thebenefit of The Bank of New York Mellon Trust Company,N.A., as Collateral Agent and Initial Second PriorityRepresentative for the benefit of the Second Lien SecuredParties, as Beneficiary.4.1 -Indenture, dated as of April 19, 2011, among TexasCompetitive Electric Holdings Company LLC, TCEHFinance Inc., the Guarantors party thereto and The Bankof New York Mellon Trust Company, N.A., as trustee,relating to 11.5% Senior Secured Notes due 2020.4.2 -Form of Deed of Trust, Assignment of Leases and Rents,Security Agreement and Fixture Filing to FidelityNational Title Insurance Company, as trustee, for thebenefit of Citibank, N.A., as Collateral Agent for thebenefit of the Holders of the 11.5% Senior Secured Notesdue 2020, as Beneficiary.4.3 -Form of Deed ofTrust and Security Agreementto FidelityNational Title Insurance Company, as trustee, for thebenefit of Citibank, N.A., as Collateral Agent for thebenefit of the Holders of the 11.5% Senior Secured Notesdue 2020, as Beneficiary.4.4 -Form of Subordination and Priority Agreement, amongCitibank, N.A., as beneficiary under the First Lien CreditDeed of Trust, The Bank of New York Mellon TrustCompany, N.A., as beneficiary under the Second LienIndenture Deed of Trust, Citibank, N.A., as beneficiaryunder the First Lien Indenture Deed of Trust, TexasCompetitive Electric Holdings Company LLC and thesubsidiary guarantors party thereto.(10) Material ContractsCredit Agreements and Related Agreements167 Table of ContentsEFCH's Exhibits to Form 10-K for the Fiscal Year Ended December 31, 201210(a) 333-171253Post-EffectiveAmendment #1 toForm S-4(filed February 7, 2011)10(b) 1-12833Form 8-K (filedAugust 10, 2009)10(c) 1-12833 Form 8-K (filed April 20, 2011)10(d) 1-12833 Form 8-K (filed January 7,2013)10(e) 1-12833 Form 8-K (filed January 7,2013)10(f) 1-12833Form 10-K (2007) (filedMarch 31, 2008)10(g) 1-12833Form 10-K (2007) (filedMarch 31, 2008)10(h) 1-12833 Form 10-Q (Quarter endedMarch 31, 2011) (filed April 29, 2011)10(i) 1-12833Form 8-K (filedAugust 10, 2009)l0(rr)10.110.110.110.210(ss)l0(vv)l0(b)10.2-$24,500,000,000 Credit Agreement, dated October 10,2007, among Energy Future Competitive HoldingsCompany; Texas Competitive Electric HoldingsCompany LLC, as the borrower; the several lenders fromtime to time parties thereto; Citibank, N.A., asadministrative agent, collateral agent, swingline lender,revolving letter of credit issuer and deposit letter of creditissuer; Goldman Sachs Credit Partners L.P., as postingagent, posting syndication agent and postingdocumentation agent; JPMorgan Chase Bank, N.A., assyndication agent and revolving letter of credit issuer;Citigroup Global Markets Inc., J.P. Morgan SecuritiesInc., Goldman Sachs Credit Partners L.P., LehmanBrothers Inc., Morgan Stanley Senior Funding, Inc. andCredit Suisse Securities (USA) LLC, as joint leadarrangers and bookrunners; Goldman Sachs CreditPartners L.P., as posting lead arranger and booknmner;Credit Suisse, Goldman Sachs Credit Partners L.P.,Lehman Commercial Paper Inc., Morgan Stanley SeniorFunding, Inc., as co-documentation agents; and J. Aron& Company, as posting calculation agent.-Amendment No. 1, dated August 7, 2009, to the$24,500,000,000 Credit Agreement.-Amendment No. 2, dated April 7, 2011, to the$24,500,000,000 Credit Agreement-December 2012 Extension Amendment, dated January 4,2013, to the $24,500,000,000 Credit Agreement.-Incremental Amendment No. 1, dated January 4, 2013, tothe $24,500,000,000 Credit Agreement.-Guarantee, dated October 10, 2007, by the guarantorsparty thereto in favorofCitibank, N.A., as collateral agentfor the benefit of the secured parties under the$24,500,000,000 Credit Agreement, dated October 10,2007.-Form of Deed of Trust, Assignment of Leases and Rents,Security Agreement and Fixture Filing to FidelityNational Title Insurance Company, as trustee, for thebenefit of Citibank, N.A., as beneficiary.Form of First Amendment to Deed of Trust, Assignmentof Leases and Rents, Security Agreement and FixtureFiling to Fidelity National Title Insurance Company, astrustee, for the benefit of Citibank, N.A., as Beneficiary.Amended and Restated Collateral Agency andIntercreditor Agreement, dated October 10, 2007, asamended and restated as of August 7, 2009, amongEnergy Future Competitive Holdings Company; TexasCompetitive Electric Holdings Company LLC; thesubsidiary guarantors party thereto; Citibank, N.A., asadministrative agent and collateral agent; Credit SuisseEnergy LLC, J. Aron & Company, Morgan StanleyCapital Group Inc., Citigroup Energy Inc., each as asecured hedge counterparty; and any other person thatbecomes a secured party pursuant thereto.168 Table of ContentsEFCH's Exhibits to Form 10-K for the Fiscal Year Ended December 31, 201210(j) 1-12833Form 8-K (filedAugust 10, 2009)10.310(k) 1-12833Form 8-K (filedAugust 10, 2009)10.4-Amended and Restated Security Agreement, datedOctober 10, 2007, as amended and restated as of August7, 2009, among Texas Competitive Electric HoldingsCompany LLC, the subsidiary grantors party thereto, andCitibank, N.A., as collateral agent for the benefit of thefirst lien secured parties, including the secured partiesunder the $24,500,000,000 Credit Agreement, datedOctober 10, 2007.-Amended and Restated Pledge Agreement, dated October10, 2007, as amended and restated as of August 7, 2009,among Energy Future Competitive Holdings Company,Texas Competitive Electric Holdings Company LLC, thesubsidiary pledgors party thereto, and Citibank, N.A., ascollateral agent for the benefit first lien secured parties,including the secured parties under the $24,500,000,000Credit Agreement, dated October 10, 2007.-Pledge Agreement, dated November 16, 2009, made byEnergy Future Intermediate Holding Company LLC andthe additional pledgers to The Bank of New York MellonTrust Company, N.A., as collateral trustee for the holdersof parity lien obligations.-Collateral Trust Agreement, dated November 16, 2009,among Energy Future Intermediate Holding CompanyLLC, The Bank of New York Mellon Trust Company,N.A., as first lien trustee and as collateral trustee, and theother secured debt representatives party thereto.10(l) 1-12833Form 8-K (filedNovember 20, 2009)10(m) 1-12833Form 8-K (filedNovember 20, 2009)Other Material Contracts10(n) 1-12833Form 10-K (2003)(filed March 15, 2004)10(o) 1-12833Form IO-Q(Quarter endedJune 30, 2007)(filed August 9, 2007)10(p) 1-12833Form 10-K (2006)(filed March 2, 2007)4.34.410(qq) -Lease Agreement, dated February 14, 2002, betweenState Street Bank and Trust Company of Connecticut,National Association, an owner trustee of ZSF/DallasTower Trust, a Delaware grantor trust, as lessor and EFHProperties Company, as Lessee (Energy Plaza Property).10.110(iii)lO(q) 1-12833Form 1O-K (2007)(filed March 31, 2008)10(r) 1-12833Form 1O-K (2007)(filed March 31, 2008)10(s) 1-12833Form 1O-K (2007) (filedMarch 31, 2008)10(t) 1-12833Form 1O-K (2007) (filedMarch 31, 2008)10(sss)10(ttt)-First Amendment, dated June 1, 2007, to LeaseAgreement, dated February 14, 2002.-Amended and Restated Transaction Confirmation byGeneration Development Company LLC, dated February2007 (subsequently assigned to Texas CompetitiveElectric Holdings Company LLC on October 10, 2007)(confidential treatment has been requested for portions ofthis exhibit).-ISDA Master Agreement, dated October 25, 2007,between Texas Competitive Electric Holdings CompanyLLC and Goldman Sachs Capital Markets, L.P.-Schedule to the ISDA Master Agreement, dated October25, 2007, between Texas Competitive Electric HoldingsCompany LLC and Goldman Sachs Capital Markets, L.P.-Form of Confirmation between Texas CompetitiveElectric Holdings Company LLC and Goldman SachsCapital Markets, L.P.-ISDA Master Agreement, dated October 29, 2007,between Texas Competitive Electric Holdings CompanyLLC and Credit Suisse International.10(uuu)10(vvv)169 Table of ContentsEFCH's Exhibits to Form 10-K for the Fiscal Year Ended December 31, 201210(u) 1-12833Form 10-K (2007) (filedMarch 31, 2008)10(v) 1-12833Form 10-K (2007) (filedMarch 31, 2008)10(w) 1-12833 Form 8-K (filed December 6,2012)10(x) 1-12833 Form 8-K (filed December 6,2012)10(y) 1-12833 Form 10-Q (Quarter endedSeptember 30, 2012) (filed October 30,2012)10(www)10(xxx)10.110.210(b)-Schedule to the ISDA Master Agreement, dated October29, 2007, between Texas Competitive Electric HoldingsCompany LLC and Credit Suisse International.-Form of Confirmation between Texas CompetitiveElectric Holdings Company LLC and Credit SuisseInternational.-First Lien Trade Receivables Financing Agreement, datedas of November 30, 2012, among TXU EnergyReceivables Company LLC, as Borrower, TXU EnergyRetail Company LLC, as Collection Agent, certainInvestors, CitiBank, N.A., as the Initial Bank, andCitiBank, N.A., as Administrative Agent and as a GroupManaging Agent.-Trade Receivables Sale Agreement, dated as ofNovember 30, 2012, among TXU Energy RetailCompany LLC, as Originator, as Collection Agent and asOriginator Agent and TXU Energy ReceivablesCompany LLC, as Buyer, and Energy Future HoldingsCorp.Federal and State Income Tax Allocation Agreement,effective January 1, 2010, by and among members of theEnergy Future Holdings Corp. consolidated group.-Computation of Ratio of Earnings to Fixed ChargesCertification of John Young, principal executive officerof Energy Future Competitive Holdings Corp., pursuantto Section 302 of the Sarbanes-Oxley Act of 2002.Certification of Paul M. Keglevic, principal financialofficer of Energy Future Competitive Holdings Corp.,pursuant to Section 302 of the Sarbanes-Oxley Act of2002.Certification of John Young, principal executive officerof Energy Future Competitive Holdings Corp., pursuantto 18 U.S.C. Section 1350, as adopted pursuant to Section906 of the Sarbanes-Oxley Act of 2002.Certification of Paul M. Keglevic, principal financialofficer of Energy Future Competitive Holdings Corp.,pursuant to 18 U.S.C. Section 1350, as adopted pursuantto Section 906 of the Sarbanes-Oxley Act of 2002.(12) Statement Regarding Computation of Ratios12(a)(31) Rule 13a -14(a)/15d -14(a) Certifications31(a)31(b)32 Section 1350 Certifications32(a)32(b)(95) Mine Safety Disclosures95(a)(99) Additional Exhibits99(a) 33-55408Post-EffectiveAmendment No. 1 toForm S-3(filed July, 1993)-Mine Safety Disclosures99(b)Amended Agreement dated January 30, 1990, betweenEnergy Future Competitive Holdings Company and Tex-La Electric Cooperative of Texas, Inc.170 Table of ContentsEFCH's Exhibits to Form 10-K for the Fiscal Year Ended December 31, 201299(b) -Texas Competitive Electric Holdings Company LLCConsolidated Adjusted EBITDA reconciliation for theyears ended December 31, 2012 and 2011.99(c) -Energy Future Holdings Corp. Consolidated AdjustedEBITDA reconciliation for the years ended December 31,2012 and 2011.XBRL Data Files101.INS XBRL Instance Document101.SCH XBRL Taxonomy Extension Schema Document101.CAL XBRL Taxonomy Extension Calculation Document101.DEF XBRL Taxonomy Extension Definition Document101 LAB XBRL Taxonomy Extension Labels Document101.PRE XBRL Taxonomy Extension Presentation Document* Incorporated herein by reference** Certain instruments defining the rights of holders of long-term debt of the Company's subsidiaries included in the financialstatements filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed10 percent of the total assets of the Company and its subsidiaries on a consolidated basis. The Company hereby agrees, uponrequest of the SEC, to furnish a copy of any such omitted instrument.SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Energy Future CompetitiveHoldings Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.ENERGY FUTURE COMPETITIVE HOLDINGS COMPANYDate: February 19, 2013 By /s/ JOHN F. YOUNG(John F. Young, President and Chief Executive)Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the followingpersons on behalf of Energy Future Competitive Holdings Company and in the capacities and on the date indicated.171 Table of ContentsSienature/s/ JOHN F. YOUNG Principal(John F. Young, Chair, President and Chief Executive)/S/ PAUL M. KEGLEVIC Principal(Paul M. Keglevic, Executive Vice President andChief Financial Officer)/S/ STANLEY J. SZLAUDERBACH Principal(Stanley J. Szlauderbach,Senior Vice President and Controller)/S/ ARCILIA C. ACOSTA Director(Arcilia C. Acosta)/s/ SCOTT LEBOVITZ Director(Scott Lebovitz)TitleExecutive Officer and DirectorFinancial Officer and DirectorDateFebruary 19, 2013February 19, 2013February 19, 2013Accounting OfficerFebruary 19, 2013February 19, 2013February 19, 2013February 19, 2013/S/ MICHAEL MACDOUGALL(Michael MacDougall)/S/ JONATHAN D. SMIDT(Jonathan D. Smidt)DirectorDirector172 Exhibit 31(a)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCertificate Pursuant to Section 302of Sarbanes -Oxley Act of 2002I, John F. Young, certify that:1. I have reviewed this annual report on Form 10-K of Energy Future Competitive Holdings Company;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which such statements were made, not misleading with respect tothe period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a- 15(0 and 15d- 15(0) for the registrant and have:a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed underour supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period in which this report is being prepared;b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles;c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusionsabout the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based onsuch evaluation; andd. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during theregistrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materiallyaffected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalentfunctions):a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reportingwhich are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financialinformation; andb. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: February 19, 2013 /s/ JOHN F. YOUNGName: John F. YoungTitle: Chair, President and Chief Executive Exhibit 31(b)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCertificate Pursuant to Section 302of Sarbanes -Oxley Act of 20021, Paul M. Keglevic, certify that:1. I have reviewed this annual report on Form 10-K of Energy Future Competitive Holdings Company;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which such statements were made, not misleading with respect tothe period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a-15(f) and 15d-15(f)) for the registrant and have:a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed underour supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period in which this report is being prepared;b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles;c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusionsabout the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based onsuch evaluation; andd. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during theregistrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materiallyaffected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalentfunctions):a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reportingwhich are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financialinformation; andb. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: February 19, 2013 /s/ PAUL M. KEGLEVICName: Paul M. KeglevicExecutive Vice President and Chief FinancialTitle: Officer Exhibit 32(a)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCertificate Pursuant to Section 906of Sarbanes -Oxley Act of 2002CERTIFICATION OF CEOThe undersigned, John F. Young, Chair, President and Chief Executive of Energy Future CompetitiveHoldings Company (the "Company"), DOES HEREBY CERTIFY that, to his knowledge:1. The Company's Annual Report on Form 10-K for the period ended December 31,2012 (the "Report")fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of1934, as amended; and2. Information contained in the Report fairly presents, in all material respects, the financial conditionand results of operations of the Company.IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 19th dayof February, 2013.Name:Title:/s/ JOHN F. YOUNGJohn F. YoungChair, President and Chief ExecutiveA signed original of this written statement required by Section 906 has been provided to Energy Future Competitive HoldingsCompany and will be retained by Energy Future Competitive Holdings Company and furnished to the Securities and ExchangeCommission or its staff upon request. Exhibit 32(b)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANYCertificate Pursuant to Section 906of Sarbanes -Oxley Act of 2002CERTIFICATION OF CFOThe undersigned, Paul M. Keglevic, Executive Vice President and Chief Financial Officer of EnergyFuture Competitive Holdings Company (the "Company"), DOES HEREBY CERTIFY that, to hisknowledge:I. The Company's Annual Report on Form 10-K for the period ended December 31,2012 (the "Report")frilly complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of1934, as amended; and2. Information contained in the Report fairly presents, in all material respects, the financial conditionand results of operations of the Company.IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 19th dayof February, 2013./s/ PAUL M. KEGLEVICName: Paul M. KeglevicExecutive Vice President and Chief FinancialTitle: OfficerA signed original of this written statement required by Section 906 has been provided to Energy Future Competitive HoldingsCompany and will be retained by Energy Future Competitive Holdings Company and furnished to the Securities and ExchangeCommission or its staff upon request. Exhibit 95(a)Mine Safety DisclosuresSafety is a top priority in all our businesses, and accordingly, it is a key component of our focus on operational excellence,our employee performance reviews and employee compensation. Our health and safety program objectives are to prevent workplaceaccidents and ensure that all employees return home safely and comply with all regulations.We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities.These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safetyand Health Act of 1977, as amended (the Mine Act), as well as other regulatory agencies such as the RRC. The MSHA inspectsUS mines, including ours, on a regular basis and if it believes a violation of the Mine Act or any health or safety standard or otherregulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citationsand orders can be contested and appealed to the Federal Mine Safety and Health Review Commission (FMSHRC), which oftenresults in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. The number ofcitations, orders and proposed assessments vary depending on the size of the mine as well as other factors.Disclosures related to specific mines pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer ProtectionAct and Item 104 of Regulation S-K sourced from data documented at January 3, 2013 in the MSHA Data Retrieval System forthe twelve months ended December 31, 2012 (except pending legal actions, which are at December 31, 2012), are as follows:ReceivedReceived Notice of LegalTotal Dollar Total Notice of Potential ActionsSection Section Value of Number Pattern of to Have Pending Legal Legal104 104(d) MSHA of Violations Pattern at Last Actions ActionsS and S Section Citations Section Section Assessments Mining Under Under Day of Initiated ResolvedCitations 104(b) and 110(b)(2) 107(a) Proposed Related Section Section Period During DuringMine (a) (b) Orders Orders Violations Orders (c) Fatalities 104(e) 104(e) (d) Period PeriodBeckville 2 --25 --6 2 2Big Brown 7 --6 ---3 3 2Kosse 10 --144 --5 2 -Oak Hill ---1 ---2 --Sulphur Springs 4 --. 6 --1 1 4Tatum 3 --5 ---2 --Three Oaks 8 -I --76 --3 2 1Turlington ------I I -Winfield South I --I --I I I(a) Excludes mines for which there were no applicable events.(b) Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injuryif left unabated.(c) Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in thetwelve months ended December 31, 2012, including but not limited to Sections 104, 107 and 110 citations and orders thatare not required to be reported.(d) Pending actions before the FMSHRC involving a coal or other mine. All 24 are contests of proposed penalties. Exhibit 99(b)Texas Competitive Electric Holdings Company LLC ConsolidatedAdjusted EBITDA Reconciliation(millions of dollars)Net lossIncome tax benefitInterest expense and related chargesDepreciation and amortizationEBITDAInterest incomeAmortization of nuclear fuelPurchase accounting adjustments (a)Impairment of goodwillImpairment and write-down of other assets (b)Unrealized net (gain) loss resulting from commodity hedging and trading transactionsEBITDA amount attributable to consolidated unrestricted subsidiariesCorporate depreciation, interest and income tax expenses included in SG&A expenseNoncash compensation expense (c)Transition and business optimization costs (d)Transaction and merger expenses (e)Restructuring and other (f)Charges related to pension plan actions (g)Expenses incurred to upgrade or expand a generation station (h)Adjusted EBITDA per Incurrence CovenantExpenses related to unplanned generation station outagesPro forma adjustment for Oak Grove 2 reaching 70% capacity in Q2 2011 (i)Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (j)Adjusted EBITDA per Maintenance CovenantYear Ended December 31,2012 2011$ (2,948) $ (1,740)(894) (917)2,752 3,6991,343 1,470$ 253 $ 2,512(46) (87)156 14255 1571,2006 4301,526 (58)(4) (7)17 167 123338423714 72141100 100$ 3,496 $ 3,3687818127-8$ 3,574 $ 3,584(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements,environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclearfuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Adjustments in 2011include $46 million related to an asset sale.(b) Impairment of assets in 2011 includes impairment of emission allowances and certain mining assets due to EPA rule issued in July 2011.(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and excludecapitalized amounts.(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costsrelated to generation plant reliability and supply chain efficiency initiatives.(e) Transaction and mnerger expenses primarily represent Sponsor Group management fees.(f) Restructuring and other in 2011 includes gains on termination of a long-term power sales contract and settlement of amounts due fromhedging/trading counterparty, fees related to the amendment and extension of the TCEH Senior Secured Facilities, and reversal of certainliabilities accrued in purchase accounting.(g) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employeesof EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pensionobligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensiveincome.(h) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs.(i) Pro forma adjustment for the year ended 2011 represents the annualization of the actual nine months ended December 31,2011 EBITDAresults for Oak Grove 2, which achieved the requisite 70% average capacity factor in the second quarter 2011.(j) Primarily pre-operating expenses relating to Oak Grove and Sandow 5. Exhibit 99(c)Energy Future Holdings Corp. ConsolidatedAdjusted EBITDA Reconciliation(millions of dollars)Net lossIncome tax benefitInterest expense and related chargesDepreciation and amortizationEBITDAOncor Holdings distributions of earningsInterest incomeAmortization of nuclear fuelPurchase accounting adjustments (a)Impairment of goodwillImpairment and write-down of other assets (b)Debt extinguishment gainsEquity in earnings of unconsolidated subsidiaryUnrealized net (gain) loss resulting from commodity hedging and trading transactionsEBITDA amount attributable to consolidated unrestricted subsidiariesNoncash compensation expense (c)Transition and business optimization costs (d)Transaction and merger expenses (e)Restructuring and other (f)Charges related to pension plan actions (g)Expenses incurred to upgrade or expand a generation station (h)Adjusted EBITDA per Incurrence CovenantAdd Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)Adjusted EBITDA per Restricted Payments CovenantYear Ended December 31,2012 2011$ (3,360) $ (1,913)(1,232) (1,134)3,508 4,2941,373 1,499$ 289 $ 2,746147 116(2) (2)156 14274 2041,20048 433(51)(270) (286)1,526 (58)411 1335 3939 3715 80285100 100$ 3,657 $ 3,5131,600 1,523$ 5,257 $ 5,036(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements,environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclearfuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Adjustments in 2011include $46 million related to an asset sale.(b) Impairment of assets in 2011 includes impairment of emission allowances and certain mining assets due to EPA rule issued in July 2011.(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and excludecapitalized amounts.(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costsrelated to generation plant reliability and supply chain efficiency initiatives.(e) Transaction and merger expenses primarily represent Sponsor Group management fees.(f) Restructuring and other in 2011 includes gains on termination of a long-term power sales contract and settlement of amounts due fromhedging/trading counterparty, fees related to the amendment and extension of the TCEH Senior Secured Facilities, and reversal of certainliabilities accrued in purchase accounting.(g) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employeesof EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pensionobligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensiveincome.(h) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs. Table of ContentsUNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 1O-QE] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013-OR-0 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Commission File Number 00 1-34543Energy Future Competitive Holdings Company LLC(formerly Energy Future Competitive Holdings Company)(Exact name of registrant as specified in its charter)Delaware 75-1837355(State of incorporation or organization) (I.R.S. Employer Identification No.)1601 Bryan Street, Dallas, TX 75201-3411 (214) 812-4600(Address of principal executive offices) (Zip Code) (Registrant's telephone number, including area code)Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file suchreports) and (2) has been subject to such filing requirements for the past 90 days. Yes IM No 03Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, everyInteractive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) duringthe preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [E No 0Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smallerreporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2of the Exchange Act.Large accelerated filer 0 Accelerated filer 0 Non-Accelerated filer [M (Do not check if a smaller reporting company)Smaller reporting company 0Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes 0 No IEAt May 1, 2013, the outstanding membership interest in Energy Future Competitive Holdings Company LLC was directly heldby Energy Future Holdings Corp.Energy Future Competitive Holdings Company LLC meets the conditions set forth in General Instructions (H)(l)(a) and (b) ofForm 10-Q and is therefore filing this report with the reduced disclosure format. Table of ContentsTABLE OF CONTENTSPAGEGLOSSARYPART I. FINANCIAL INFORMATIONItem 1. Financial Statements (Unaudited)Condensed Statements of Consolidated Income (Loss) -Three Months Ended March 31. 2013 and 2012Condensed Statements of Consolidated Comprehensive Income (Loss) -Three Months Ended March 31. 2013 and 2012Condensed Statements of Consolidated Cash Flows -Three Months Ended March 31, 2013 and 2012 2Condensed Consolidated Balance Sheets -March 31, 2013 and December 31, 2012 3Notes to Condensed Consolidated Financial Statements 4Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 50Item 3. Ouantitative and Qualitative Disclosures About Market Risk 69Item 4. Controls and Procedures 75PART II. OTHER INFORMATIONItem 1. Legal Proceedings 75Item 1A. Risk Factors 75Item 4. Mine Safety Disclosures 75Item 6. Exhibits 76SIGNATURE 78Energy Future Competitive Holdings Company LLC's (EFCH) (formerly known as Energy Future Holdings Company) annualreports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports aremade available to the public, free of charge, on the Energy Future Holdings Corp. (EFH Corp.) website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securitiesand Exchange Commission. EFCH also from time to time makes available to the public, free of charge, on the EFH Corp. websitecertain financial statements of its wholly-owned subsidiary, Texas Competitive Electric Holdings Company LLC. The informationon EFH Corp.'s website shall not be deemed a part of, or incorporated by reference into, this quarterly report on Form IO-Q. Therepresentations and warranties contained in any agreement that EFCH has filed as an exhibit to this quarterly report on Form 10-Q or that EFCH has or may publicly file in the future may contain representations and warranties made by and to the parties theretoat specific dates. Such representations and warranties may be subject to exceptions and qualifications contained in separatedisclosure schedules, may represent the parties' risk allocation in the particular transaction, or may be qualified by materialitystandards that differ from what may be viewed as material for securities law purposes.This quarterly report on Form I0-Q and other Securities and Exchange Commission filings ofEFCH and its subsidiaries occasionallymake references to EFH Corp., EFCH (or "we," "lour," "us" or "the company"), TCEH, TXU Energy or Luminant when describingactions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidatedwith, or otherwise reflected in, their respective parent company's financial statements for financial reporting purposes. However,these references should not be interpreted to imply that the relevant parent company is actually undertaking the action or has therights or obligations of the relevant subsidiary company or vice versa.i Table of ContentsGLOSSARYWhen the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.2012 Form 10-KAdjusted EBITDACAIRCFTCCSAPREBITDAEFCH's Annual Report on Form 10-K for the year ended December 31, 2012Adjusted EBITDA means EBITDA adjusted to exclude noncash items, unusualitems and other adjustments allowable under certain debt arrangements of TCEHand EFH Corp. See the definition of EBITDA below. Adjusted EBITDA andEBITDA are not recognized terms under US GAAP and, thus, are non-GAAPfinancial measures. We are providing TCEH's and EFH Corp.'s Adjusted EBITDAin this Form I0-Q (see reconciliations in Exhibits 99(b) and 99(c)) solely becauseof the important role that Adjusted EBITDA plays in respect of certain covenantscontained in the debt arrangements. We do not intend for Adjusted EBITDA (orEBITDA) to be an alternative to net income as a measure of operating performanceor an alternative to cash flows from operating activities as a measure of liquidityor an alternative to any other measure of financial performance presented inaccordance with US GAAP. Additionally, we do not intend for Adjusted EBITDA(or EBITDA) to be used as a measure of free cash flow available for management'sdiscretionary use, as the measure excludes certain cash requirements such as interestpayments, tax payments and other debt service requirements. Because not allcompanies use identical calculations, our presentation of Adjusted EBITDA (andEBITDA) may not be comparable to similarly titled measures of other companies.Clean Air Interstate RuleUS Commodity Futures Trading Commissionthe final Cross-State Air Pollution Rule issued by the EPA in July 2011 and vacatedby the US Court of Appeals for the District of Columbia Circuit in August 2012(see Note 6 to Financial Statements)earnings (net income) before interest expense, income taxes, depreciation andamortizationEnergy Future Competitive Holdings Company LLC, a direct, wholly-ownedsubsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries,depending on context (formerly known as Energy Future Competitive HoldingsCompany, which was a Texas corporation)Energy Future Holdings Corp., a holding company, and/or its subsidiariesdepending on context, whose major subsidiaries include TCEH and OncorEnergy Future Intermediate Holding Company LLC, a direct, wholly-ownedsubsidiary of EFH Corp. and the direct parent of Oncor HoldingsEFIH Finance Inc., a direct, wholly-owned subsidiary of EFIH, formed for the solepurpose of serving as co-issuer with EFIH of certain debt securitiesUS Environmental Protection AgencyElectric Reliability Council of Texas, Inc., the independent system operator andthe regional coordinator of various electricity systems within Texasgenerally accepted accounting principlesgigawatt-hoursEFCHEFH Corp.EFIHEFIH FinanceEPAERCOTGAAPGWhIRSUS Internal Revenue ServiceLIBORLuminantLondon Interbank Offered Rate, an interest rate at which banks can borrow funds,in marketable size, from other banks in the London interbank marketsubsidiaries of TCEH engaged in competitive market activities consisting ofelectricity generation and wholesale energy sales and purchases as well ascommodity risk management and trading activities, all largely in Texasii Table of Contentsmarket heat rateMATSMergerMMBtuMoody'sMWMWhNERCNOxNRCNYMEXOncorHeat rate is a measure of the efficiency of converting a fuel source to electricity.Market heat rate is the implied relationship between wholesale electricity pricesand natural gas prices and is calculated by dividing the wholesale market price ofelectricity, which is based on the price offer of the marginal supplier in ERCOT(generally natural gas plants), by the market price of natural gas. Forward wholesaleelectricity market price quotes in ERCOT are generally limited to two or threeyears; accordingly, forward market heat rates are generally limited to the same timeperiod. Forecasted market heat rates for time periods for which market price quotesare not available are based on fundamental economic factors and forecasts,including electricity supply, demand growth, capital costs associated with newconstruction of generation supply, transmission development and other factors.the Mercury and Air Toxics Standard established by the EPAThe transaction referred to in the Agreement and Plan of Merger, dated February25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which wascompleted on October 10, 2007.million British thermal unitsMoody's Investors Services, Inc. (a credit rating agency)megawattsmegawatt-hoursNorth American Electric Reliability Corporationnitrogen oxidesUS Nuclear Regulatory Commissionthe New York Mercantile Exchange, a physical commodity futures exchangeOncor Electric Delivery Company LLC, a direct, majority-owned subsidiary ofOncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidatedbankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition BondCompany LLC, depending on context, that is engaged in regulated electricitytransmission and distribution activitiesOncor Electric Delivery Holdings Company LLC, a direct, wholly-ownedsubsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries,depending on contextother postretirement employee benefitsPublic Utility Commission of TexasThe purchase method of accounting for a business combination as prescribed byUS GAAP, whereby the cost or "purchase price" of a business combination,including the amount paid for the equity and direct transaction costs are allocatedto identifiable assets and liabilities (including intangible assets) based upon theirfair values. The excess of the purchase price over the fair values of assets andliabilities is recorded as goodwill.retail electric providerRailroad Commission of Texas, which among other things, has oversight of lignitemining activity in TexasStandard & Poor's Ratings Services, a division of the McGraw-Hill CompaniesInc. (a credit rating agency)US Securities and Exchange Commissionselling, general and administrativesulfur dioxideOncor HoldingsOPEBPUCTpurchase accountingREPRRCS&PSECSG&AS02iii Table of ContentsSponsor GroupTCEHTCEH Demand NotesTCEH FinanceTCEH Senior NotesTCEH Senior Secured FacilitiesTCEH Senior Secured NotesTCEH Senior Secured Second LienNotesTCEQTexas HoldingsRefers, collectively, to certain investment funds affiliated with Kohlberg KravisRoberts & Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GSCapital Partners, an affiliate of Goldman, Sachs & Co., that have an ownershipinterest in Texas Holdings.Texas Competitive Electric Holdings Company LLC, a direct, wholly-ownedsubsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries,depending on context, that are engaged in electricity generation and wholesale andretail energy markets activities, and whose major subsidiaries include Luminantand TXU EnergyRefers to certain loans from TCEH to EFH Corp. in the form of demand notes tofinance EFH Corp. debt principal and interest payments and, until April 2011, othergeneral corporate purposes of EFH Corp., that were guaranteed on a seniorunsecured basis by EFCH and EFIH and were repaid by EFH Corp. in January2013.TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for thesole purpose of serving as co-issuer with TCEH of certain debt securitiesRefers, collectively, to TCEH's and TCEH Finance's 10.25% Senior Notes dueNovember 1, 2015 and 10.25% Senior Notes due November 1, 2015, Series B(collectively, TCEH 10.25% Notes) and TCEH's and TCEH Finance's10.50%/ 11.25% Senior ToggleNotes dueNovember 1,2016 (TCEH ToggleNotes).Refers, collectively, to the TCEH Term Loan Facilities, TCEH Revolving CreditFacility and TCEH Letter of Credit Facility. See Note 5 to Financial Statementsfor details of these facilities.TCEH's and TCEH Finance's 11.5% Senior Secured Notes due October 1, 2020Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured SecondLien Notes due April 1,2021 and TCEH's and TCEH Finance's 15% Senior SecuredSecond Lien Notes due April 1, 2021, Series B.Texas Commission on Environmental QualityTexas Energy Future Holdings Limited Partnership, a limited partnership controlledby the Sponsor Group, that owns substantially all of the common stock of EFHCorp.Texas Reliability Entity, Inc., an independent organization that develops reliabilitystandards for the ERCOT region and monitors and enforces compliance with NERCstandards and ERCOT protocolsTXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEHthat is a REP in competitive areas of ERCOT and is engaged in the retail sale ofelectricity to residential and business customersUnited States of AmericaTRETXU EnergyUSVIEvariable interest entityiv Table of ContentsPART I. FINANCIAL INFORMATIONItem 1. FINANCIAL STATEMENTSENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)(Unaudited)Operating revenuesFuel, purchased power costs and delivery feesNet gain (loss) from commodity hedging and trading activitiesOperating costsDepreciation and amortizationSelling, general and administrative expensesFranchise and revenue-based taxesOther income (Note 12)Other deductionsInterest incomeInterest expense and related charges (Note 12)Loss before income taxesIncome tax benefitNet lossThree Months Ended March 31,2013 2012(millions of dollars)1,260 $ 1,222(636) (628)(197) 368(229) (207)(344) (330)(158) (155)(17) (19)4(3)3(2)4 16(593) (643)(909) (375)383 122$ (526) $ (253)See Notes to Financial Statements.CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)(Unaudited)Three Months Ended March 31,2013 2012(millions of dollars)Net lossOther comprehensive income, net of tax effects -cash flow hedges derivative value net lossrelated to hedged transactions recognized during the period and reported in interest expenseand related charges (net of tax benefit of $1 in both periods)Comprehensive loss$ (526) $(253)2 3$ (524) ( (250)See Notes to Financial Statements.I Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS(Unaudited)Three Months Ended March 31,2013 2012(millions of dollars)Cash flows -operating activities:Net lossAdjustments to reconcile net loss to cash provided by (used in) operating activities:Depreciation and amortizationDeferred income tax benefit, netUnrealized net loss from mark-to-market valuations of commodity positionsUnrealized net gain from mark-to-market valuations of interest rate swaps (Note 5)Interest expense on toggle notes payable in additional principal (Notes 5 and 12)Amortization of debt related costs, discounts, fair value discounts and losses ondedesignated cash flow hedges (Note 12)Interest expense related to pushed-down debt of parent (Notes 5 and 12)Bad debt expense (Note 4)Accretion expense related primarily to mining reclamation obligations (Note 12)Stock-based incentive compensation expenseChanges in operating assets and liabilities:Margin deposits, netOther operating assets and liabilitiesCash provided by (used in) operating activitiesCash flows -financing activities:Repayments/repurchases of long-term debt (Note 5)Net short-term borrowings under accounts receivable securitization program (Note 4)Decrease in other short-term borrowings (Note 5)Notes/advances due to affiliatesDecrease in income tax-related note payable to Oncor (Note 11)Contributions from noncontrolling interests (Note 7)Sale/leaseback of equipmentOther, netCash used in financing activitiesCash flows -investing activities:Capital expendituresNuclear fuel purchasesSettlements of notes due from affiliatesPurchase of right to use certain computer-related assets from parent (Note 11)Proceeds from sales of assetsChanges in restricted cashPurchases of environmental allowances and creditsProceeds from sales of nuclear decommissioning trust fund securitiesInvestments in nuclear decommissioning trust fund securitiesOther, netCash provided by investing activities(526) $387(276)487(148)(253)376(131)152(110)4470368521959m 1(199) 12174 (12)(14) 164(16)72(18)(11)(670)(10)2I-14(2) 1(8) (692)(131)(20)698(6)(5)41(45)(177)(64)92515(6)10(14)Net change in cash and cash equivalentsCash and cash equivalents -beginning balanceCash and cash equivalents -ending balance--_ 2533 691511 1631,175 120$ 1,686 $ 283See Notes to Financial Statements.2 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)March 31, December 31,2013 2012(millions of dollars)ASSETSCurrent assets:Cash and cash equivalentsTrade accounts receivable -net (includes $373 and $445 in pledged amounts related to aVIE (Notes 2 and 4))Notes receivable from parent (Note 11)Inventories (Note 12)Commodity and other derivative contractual assets (Note 9)Margin deposits related to commodity positionsOther current assetsTotal current assetsRestricted cash (Note 12)Investments (Note 12)Property, plant and equipment -net (Note 12)Goodwill (Note 3)Identifiable intangible assets -net (Note 3)Commodity and other derivative contractual assets (Note 9)Other noncurrent assets, primarily unamortized debt amendment and issuance costsTotal assetsLIABILITIES AND EQUITYCurrent liabilities:Short-term borrowings (includes $89 and $82 related to a VIE (Notes 2 and 5))Long-term debt due currently (Note 5)Trade accounts payableTrade accounts and other payables to affiliatesNotes payable to parent (Note 11)Commodity and other derivative contractual liabilities (Note 9)Margin deposits related to commodity positionsAccumulated deferred income taxesAccrued income taxes payable to parent (Note 11)Accrued taxes other than incomeAccrued interestOther current liabilitiesTotal current liabilitiesAccumulated deferred income taxesCommodity and other derivative contractual liabilities (Note 9)Notes or other liabilities due to affiliates (Note 11)Long-term debt held by affiliates (Note 11)Long-term debt, less amounts due currently (Note 5)Affiliate tax sharing liability (Note 12)Other noncurrent liabilities and deferred credits (Note 12)Total liabilities$ 1,686 $1,175557 710-- 698408 3931,208 1,463127 7184 1204,070 4,630947 947750 71018,346 18,5564,952 4,9521,765 1,781424 586971 811S 32,225 $ 32,973$ 2,143 $ 2,13683 96389 389144 13983 81971 894457 60045 4944 3144 17521 407218 2555,142 5,0943,056 3,7591,407 1,5566 5382 38229,738 29,9281,1151-862 2,64342,708 43,367Commitments and Contingencies (Note 6)Equity (Note 7):EFCH shareholder's equityNoncontrolling interests in subsidiariesTotal equityTotal liabilities and equity(10,596) (10,506)113 112(10,483) (10,394)$ 32225 $ 32,973See Notes to Financial Statements3 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Unaudited)1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIESDescription of BusinessReferences in this report to "we," "our," "us" and "the company" are to EFCH and/or its subsidiaries, as apparent in thecontext. See "Glossary" for defined terms.EFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. In April 2013, EFCH wasconverted from a Texas corporation to a Delaware limited liability company; the directors and officers and consolidated assets,businesses and operations are unchanged. We conduct our operations almost entirely through our wholly-owned subsidiary, TCEH.TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, includingelectricity generation, wholesale energy sales and purchases, commodity risk management and trading activities and retail electricitysales. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesalecustomers, are performed on an integrated basis; consequently, there are no reportable business segments.TCEH operates largely in the ERCOT market, and wholesale electricity prices in that market have generally moved with theprice of natural gas. Wholesale electricity prices have significant implications to its profitability and cash flows and, accordingly,the value of its business.Liquidity ConsiderationsEFCH has been and is expected to continue to be adversely affected by the sustained decline in natural gas prices and itseffect on wholesale and retail electricity prices in ERCOT. Further, the remaining natural gas hedges that TCEH entered intowhen forward market prices of natural gas were significantly higher than current prices will mature in 2013 and 2014. Thesemarket conditions challenge the long-term profitability and operating cash flows of EFCH's and its subsidiaries' business and theability to support their significant interest payments and debt maturities, and could adversely impact their ability to obtain additionalliquidity and service, refinance and/or extend the maturities of their outstanding debt.Note 5 provides the details of EFCH's and its consolidated subsidiaries' short-term borrowings and long-term debt, includingprincipal amounts and maturity dates, as well as details of recent debt activity, including the three-year extension of the portionof the TCEH Revolving Credit Facility that would have expired in 2013. At March 31, 2013, TCEH had $1.7 billion of cash andcash equivalents and $212 million of available capacity under its letter of credit facility. Based on the current forecast of cashfrom operating activities, which reflects current forward market electricity prices, projected capital expenditures and other cashflows, we expect that TCEH will have sufficient liquidity to meets its obligations until October 2014, at which time a total of $3.8billion of the TCEH Term Loan Facilities matures. TCEH's ability to satisfy this obligation is dependent upon the implementationof one or more of the actions described immediately below.EFH Corp. and its subsidiaries (excluding Oncor Holdings and its subsidiaries) continue to consider and evaluate possibletransactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and willlikely from time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives.These transactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to andextensions of debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debt of EFHCorp., EFIH, EFCH and TCEH into equity of EFH Corp., EFIH, EFCH, TCEH and/or any of their subsidiaries. These actionscould result in holders ofEFH Corp., EFIH and TCEH debt instruments not recovering the full principal amount ofthose obligations.4 Table of ContentsDiscussions with CreditorsWe and EFH Corp. recently engaged in discussions with certain unaffiliated holders of first lien senior secured claims againstEFCH, TCEH and certain of TCEH's subsidiaries (the Creditors) with respect to our capital structure, including the possibility ofa restructuring transaction. During the discussions, proposed changes to EFH Corp.'s capital structure were presented to theCreditors. The proposed changes included a consensual restructuring of TCEH's debt under which EFCH, TCEH, and certain ofTCEH's subsidiaries would implement a prepackaged plan of reorganization by commencing voluntary cases under Chapter I Iof the United States Bankruptcy Code. Under this proposed plan, the TCEH first lien creditors would exchange their claims fora combination of EFH Corp. equity and cash or new long-term debt of TCEH, and the Sponsors would continue to hold an equityinvestment in EFH Corp. The Sponsors communicated a willingness to contribute new equity capital to EFH Corp. to facilitateimplementation of the proposed plan in an amount that would provide substantial additional liquidity to EFH Corp. and EFIH,provided that in such circumstances the Sponsors would receive additional equity of EFH Corp. Following implementation ofthe proposed plan, EFH Corp. would continue to hold all of the equity interests in EFCH and EFIH, EFCH would continue to holdall of the equity interests in TCEH, and EFIH would continue to hold all of the equity interests in Oncor Holdings. We, EFH Corp.and the Creditors have not reached agreement on the terms of any change in our capital structure and are currently not engagedin ongoing negotiations. We and EFH Corp. will continue to consider and evaluate a range of future changes to our capital structure,in addition to the proposed changes described above. In addition, we and EFH Corp. and the Sponsors may engage from time totime in additional discussions, which may include proposed changes to our capital structure, with the Creditors, other creditorsand their professional advisors.Basis of PresentationThe condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basisas the audited financial statements included in our 2012 Form 10-K. Adjustments (consisting of normal recurring accruals)necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompanyitems and transactions have been eliminated in consolidation. Any acquisitions of outstanding debt for cash, including notes thathad been issued in lieu of cash interest, are presented in the financing activities section of the statement of cash flows. Certaininformation and footnote disclosures normally included in annual consolidated financial statements prepared in accordance withUS GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interimfinancial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunctionwith the audited financial statements and related notes included in our 2012 Form 10-K. The results of operations for an interimperiod may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in thenotes are stated in millions of US dollars unless otherwise indicated.Use of EstimatesPreparation of financial statements requires estimates and assumptions about future events that affect the reporting of assetsand liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. Inthe event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods toreflect more current information.5 Table of Contents2. VARIABLE INTEREST ENTITIESA variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level ofcontrol over the entity or results in economic risks to us. Accounting standards require consolidation of a VIE if we have (a) thepower to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (primarybeneficiary). In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decisionmaking processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationshipsamong the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE. There are nomaterial investments accounted for under the equity or cost method.Consolidated VIEsSee discussion in Note 4 regarding the VIE related to our accounts receivable securitization program that is consolidatedunder the accounting standards because TCEH owns and controls TXU Energy (the primary beneficiary ofTXU Energy ReceivablesCompany). We consolidated the previous program, which was terminated in November 2012, under the accounting standardsbecause TCEH (as the owner of TXU Energy) was the primary beneficiary of TXU Receivables Company, which is owned andcontrolled by our parent, EFH Corp.We also consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEHand Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existingComanche Peak nuclear-fueled generation facility using MHI's US-Advanced Pressurized Water Reactor technology and to obtaina combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries ofTCEH and MHI that hold 88% and 12% of CPNPC's equity interests, respectively (see Note 7).The carrying amounts and classifications of the assets and liabilities related to our consolidated VIEs are as follows:March 31, December 31, March 31, December 31,Assets: 2013 2012 Liabilities: 2013 2012Cash and cash equivalents $ 80 $ 43 Short-term borrowings $ 89 $ 82Accounts receivable 373 445 Trade accounts payable 1 IProperty, plant and equipment 136 134 Other current liabilities 9 7Other assets, including $3million and $12 million ofcurrent assets 11 16Total assets $ 600 $ 638 Total liabilities $ 99 $ 90The assets of our consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of our consolidatedVIEs do not have recourse to our assets to settle the obligations of the VIE.6 Table of Contents3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETSGoodwillThe following table provides information regarding our goodwill balance. There were no changes to the goodwill balancefor the three months ended March 31, 2013. None of the goodwill is being deducted for tax purposes.Goodwill before impairment chargesAccumulated impairment chargesBalance at March 31, 2013 and December 31, 2012$ 18,322(13,370)$ 4,952In the first quarter 2013, we finalized the fair value calculations supporting the $1.2 billion noncash goodwill impairmentcharge that was recorded in the fourth quarter 2012. No additional impairment was recorded.Identifiable Intangible AssetsIdentifiable intangible assets reported in the balance sheet are comprised of the following:March 31, 2013December 31, 2012Identifiable Intangible AssetRetail customer relationshipFavorable purchase and sales contractsGross GrossCarrying Accumulated Carrying AccumulatedAmount Amortization Net Amount Amortization Net$ 463 $ 384 $ 79 $ 463 $ 378 85552 320 232 552 314 238Software and other computer-relatedassetsEnvironmental allowances and creditsMining development costsTotal intangible assets subject toamortizationRetail trade name (not subject toamortization)Mineral interests (not currently subject toamortization)Total intangible assets325 122 203 320 112 208596 396 200 594 393 201173 90 83 163 82 81$ 2,109 $ 1,312797 $ 2,092 $ 1,27995581395513$ 1,76513$ 1,781Amortization expense related to intangible assets (including income statement line item) consisted of:Three Months Ended March 31,2013 20126 9Identifiable Intangible AssetRetail customer relationshipFavorable purchase and sales contractsSoftware and other computer-related assetsEnvironmental allowances and creditsMining development costsTotal amortization expenseIncome Statement LineDepreciation and amortizationOperating revenues/fuel, purchasedpower costs and delivery feesDepreciation and amortizationFuel, purchased power costs anddelivery feesDepreciation and amortization61086358 6$ 33 $ 347 Table of ContentsEstimatedAmortization ofIntangible Assets -The estimated aggregate amortization expense of intangible assets for eachof the next five fiscal years is as follows:Estimated AmortizationYear Expense2013 $ 1332014 $ 1152015 $ 1052016 $ 862017 $ 678 Table of Contents4. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAMIn November 2012, TCEH entered into a new accounts receivable securitization program, and EFH Corp. terminated theprevious program. Upon termination of the program, TXU Energy repurchased receivables previously sold and then sold themto TXU Energy Receivables Company, a new entity that is described below. Except as noted below, the new program is substantiallythe same as the terminated program.Under the program, TXU Energy (originator) sells all of its trade accounts receivable to TXU Energy Receivables Company,which is an entity created for the special purpose of purchasing receivables from the originator and is a consolidated, wholly-owned, bankruptcy-remote subsidiary of TCEH. TXU Energy Receivables Company borrows funds from a financial institutionusing the accounts receivable as collateral.The trade accounts receivable amounts under the program are reported in the financial statements as pledged balances, andthe related funding amounts are reported as short-term borrowings.The maximum funding amount currently available under the program is $200 million, which approximates the expectedusage and applies only to receivables related to non-executory retail sales contracts. Program funding increased to $89 millionat March 31, 2013 from $82 million at December 31, 2012. Because TCEH's credit ratings were lower than Ba3/BB-, under theterms of the program available funding is reduced by the amount of customer deposits held by the originator, which totaled $35million at March 31, 2013.TXU Energy Receivables Company issues a subordinated note payable to the originator in an amount equal to the differencebetween the face amount of the accounts receivable purchased, less a discount, and cash paid to the originator. Because thesubordinated note is limited to 25% of the uncollected accounts receivable purchased, and the amount of borrowings is limitedby terms of the financing agreement, any additional funding to purchase the receivables is sourced from cash on hand and/orcapital contributions from TCEH. Under the program, the subordinated note issued by TXU Energy Receivables Company issubordinated to the security interests of the financial institution. The balance of the subordinated note payable, which is eliminatedin consolidation, totaled $44 million and $97 million at March 31, 2013 and December 31, 2012, respectively.All new trade receivables under the program generated by the originator are continuously purchased by TXU EnergyReceivables Company with the proceeds from collections of receivables previously purchased and, as necessary, increasedborrowings or funding sources as described immediately above. Changes in the amount ofborrowings by TXU Energy ReceivablesCompany reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such aschanges in sales prices and volumes.The discount from face amount on the purchase of receivables from the originator principally funds program fees paid tothe financial institution. The program fees consist primarily of interest costs on the underlying financing and are reported asinterest expense and related charges. The discount also funds a servicing fee, which is reported as SG&A expense, paid by TXUEnergy Receivables Company to TXU Energy, which provides recordkeeping services and is the collection agent under the program.Program fee amounts were as follows:Three Months Ended March 31,2013 2012Program fees $ 2 $ 2Program fees as a percentage of average funding (annualized) 6.0% 7.1%9 Table of ContentsActivities of TXU Energy Receivables Company and TXU Receivables Company were as follows:Cash collections on accounts receivableFace amount of new receivables purchasedDiscount from face amount of purchased receivablesProgram fees paid to financial institutionServicing fees paid for recordkeeping and collection servicesIncrease (decrease) in subordinated notes payable(Increase) decrease in cash heldCash flows (provided to) used by originator under the programThree Months Ended March 31,2013 2012$ 980 $ 1,100(909) (956)9 3(2) (2)(1)(52) (133)(33) _$ (7) $ 11The program expires in November 2015, provided that the expiration date will change to June 2014 if at that time more than$500 million aggregate principal amount of the term loans and deposit letter of credit loans under the TCEH Senior SecuredFacilities maturing prior to October 2017 remain outstanding. The program is subject to the same financial maintenance covenantas the TCEH Senior Credit Facilities as discussed in Note 5. The program may be terminated upon the occurrence of a numberof specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquentfor 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the daysoutstanding ratio exceed stated thresholds, unless the financial institution waives such events of termination. The thresholds applyto the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Energy Receivables Companydefaults in any payment with respect to debt in excess of $50,000 in the aggregate, or if EFH Corp., TCEH, any affiliate of TCEHacting as collection agent, any parent guarantor of the originator or the originator defaults in any payment with respect to debt(other than hedging obligations) in excess of $200 million in the aggregate for such entities. At March 31, 2013, there were nosuch events of termination.If the program was terminated, TCEH's liquidity would be reduced because collections of sold receivables would be usedby TXU Energy Receivables Company to repay borrowings from the financial institution instead of purchasing new receivables.We expect that the level of cash flows would normalize in approximately 10 to 24 days following termination.Trade Accounts ReceivableMarch 31, 2013 December 31, 2012Wholesale and retail trade accounts receivable, including $383 and $454 in pledgedretail receivablesAllowance for uncollectible accountsTrade accounts receivable -reported in balance sheet$567 $719(10) (9)$ 557 $ 710Gross trade accounts receivable at March 31, 2013 and December 31, 2012 included unbilled revenues of $200 million and$260 million, respectively.Allowance for Uncollectible Accounts ReceivableThree Months Ended March 31,2013 2012$ 9 $ 27Allowance for uncollectible accounts receivable at beginning of periodIncrease for bad debt expenseDecrease for account write-offsAllowance for uncollectible accounts receivable at end of period65(5) (12)$ 10 $ 2010 Table of Contents5. SHORT-TERM BORROWINGS AND LONG-TERM DEBTShort-Term BorrowingsAt March 31, 2013, outstanding short-term borrowings totaled $2.143 billion, which included $2.054 billion under the TCEHRevolving Credit Facility at a weighted average interest rate of 4.70%, excluding customary fees, and $89 million under theaccounts receivable securitization program discussed in Note 4.At December 31, 2012, outstanding short-term borrowings totaled $2.136 billion, which included $2.054 billion under theTCEH Revolving Credit Facility at a weighted average interest rate of 4.40%, excluding customary fees, and $82 million underthe accounts receivable securitization program.Credit FacilitiesCredit facilities and related cash borrowings at March 31, 2013 are presented below. Available letter of credit capacitytotaled $212 million at March 31, 2013 as discussed below. The facilities are all senior secured facilities of TCEH.March 31, 2013Letters of CashFacility Maturity Date Facility Limit Credit Borrowings AvailabilityTCEH Revolving Credit Facility (a) October 2016 $ 2,054 $ -- $ 2,054 $ -TCEH Letter of Credit Facility (b) October 2017 (b) 1,062 -1,062 --Total TCEH $ 3,116 $ -- $ 3,116 $ -(a) Facility used for borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. At March31, 2013, borrowings under the facility bear interest at LIBOR plus 4.50%, and a commitment fee is payable quarterly inarrears at a rate per annum equal to 1.00% of the average daily unused portion of the facility. In January 2013, commitmentspreviously maturing in 2013 were extended to 2016 as discussed below.(b) Facility, $42 million of which matures in October 2014, used for issuing letters of credit for general corporate purposes,including, but not limited to, providing collateral support under hedging arrangements and other commodity transactionsthat are not secured by a first-lien interest in the assets of TCEH. The borrowings under this facility have been recordedby TCEH as restricted cash that supports issuances of letters of credit and are classified as long-term debt. At March 31,2013, the restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009 related to anoffice building financing. At March 31, 2013, the restricted cash supports $735 million in letters of credit outstanding,leaving $212 million in available letter of credit capacity.Amendment and Extension of TCEH Revolving Credit Facility -In January 2013, the Credit Agreement governing theTCEH Senior Secured Facilities was amended to extend the maturity date of the $645 million of commitments maturing in October2013 to October 2016, bringing the maturity date of all commitments under the TCEH Revolving Credit Facility totaling $2.054billion to October 2016. The extended commitments have the same terms and conditions as the existing commitments expiringin October 2016 under the Credit Agreement. Fees in consideration for the extension were settled through the incurrence of $340million principal amount of incremental term loans under the TCEH Term Loan Facilities maturing in October 2017. In connectionwith the extension request, TCEH eliminated its ability to draw letters of credit under the TCEH Revolving Credit Facility. Atthe date of the extension, there were no outstanding letters of credit under the TCEH Revolving Credit Facility.11 Table of ContentsLong-Term DebtAt March 31, 2013 and December 31, 2012, long-term debt consisted of the following:TCEHSenior Secured Facilities:3.733% TCEH Term Loan Facilities maturing October 10, 2014 (a)(b)3.704% TCEH Letter of Credit Facility maturing October 10, 2014 (b)4.732% TCEH Term Loan Facilities maturing October 10, 2017 (a)(b)(c)4.704% TCEH Letter of Credit Facility maturing October 10, 2017 (b)11.5% Fixed Senior Secured Notes due October 1, 202015% Fixed Senior Secured Second Lien Notes due April 1, 202115% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B10.25% Fixed Senior Notes due November 1, 2015 (c)10.25% Fixed Senior Notes due November 1, 2015, Series B (c)10.50 / 11.25% Senior Toggle Notes due November 1, 2016Pollution Control Revenue Bonds:Brazos River Authority:5.40% Fixed Series 1994A due May 1, 20297.70% Fixed Series 1999A due April 1, 20336.75% Fixed Series 1999B due September 1, 2034, remarketing date April 1,2013 (d)7.70% Fixed Series 1999C due March 1, 20328.25% Fixed Series 2001A due October 1, 20308.25% Fixed Series 2001D-1 due May 1, 20330.134% Floating Series 2001D-2 due May 1, 2033 (e)0.320% Floating Taxable Series 20011 due December 1, 2036 (f)0.134% Floating Series 2002A due May 1, 2037 (e)6.75% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (d)6.30% Fixed Series 2003B due July 1, 20326.75% Fixed Series 2003C due October 1, 20385.40% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (d)5.00% Fixed Series 2006 due March 1, 2041Sabine River Authority of Texas:6.45% Fixed Series 2000A due June 1, 20215.20% Fixed Series 2001C due May 1, 20285.80% Fixed Series 2003A due July 1, 20226.15% Fixed Series 2003B due August 1, 2022Trinity River Authority of Texas:6.25% Fixed Series 2000A due May 1, 2028Unamortized fair value discount related to pollution control revenue bonds (g)Other:7.46% Fixed Secured Facility Bonds with amortizing payments through January 20157% Fixed Senior Notes due March 15, 2013Capital leasesOtherUnamortized discountUnamortized fair value discount (g)Total TCEHDecember 31,March 31, 2013 2012$ 3,8094215,7101,0201,7503361,2352,0461,4421,749$3,8094215,3701,0201,7503361,2352,0461,4421,74939111165071171976245443952311003911116507117197624544395231100517012455170124514(110)14(112)4 12562 643 3(119) (10)(1) (1)30,098 29,88012 Table of ContentsDecember 31,March 31, 2013 2012EFCH (parent entity)9.58% Fixed Notes due in annual installments through December 4, 2019 (h)8.254% Fixed Notes due in quarterly installments through December 31, 2021 (h)1.099% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (b)8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037Unamortized fair value discount (g)SubtotalEFH Corp. debt pushed down (i)10% Fixed Senior Notes due January 15, 20209.75% Fixed Senior Notes due October 15, 201910.875% Fixed Senior Notes due November 1, 201711.25 / 12.00% Senior Toggle Notes due November 1, 2017Subtotal -EFH Corp. debt pushed downTotal EFCH (parent entity)Total EFCH consolidatedLess amount due currentlyLess amount held by affiliates (Note 11)Total long-term debt35381353918 8(7) (7)75 76-- 330-- 5816 3214 3030 450105 52630,203 30,406(83) (96)(382) (382)$ 29,738 $ 29,928(a) Interest rate swapped to fixed on $18.265 billion principal amount of maturities through October 2014 and up to an aggregate$12.6 billion principal amount from October 2014 through October 2017.(b) Interest rates in effect at March 31, 2013.(c) As discussed below and in Note 11, principal amounts of notes/term loans totaling $382 million at both March 31, 2013 andDecember 31, 2012 were held by EFH Corp. and EFIH.(d) These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatoryremarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.(e) Interest rates in effect at March 31, 2013. These series are in a daily interest rate mode and are classified as long-term asthey are supported by long-term irrevocable letters of credit.(f) Interest rate in effect at March 31, 2013. This series is in a weekly interest rate mode and is classified as long-term as it issupported by long-term irrevocable letters of credit.(g) Amount represents unamortized fair value adjustments recorded under purchase accounting.(h) EFCH's obligations with respect to these financings are guaranteed by EFH Corp. and secured on a first-priority basis by,among other things, an undivided interest in the Comanche Peak nuclear generation facility.(i) Represents 50% of the amount of these EFH Corp. securities guaranteed by, and pushed down to (pushed-down debt), EFCH(parent entity) per the discussion below under "Guarantees and Push Down of EFH Corp. Debt."Debt Amounts Due CurrentlyAmounts due currently (within twelve months) at March 31,2013 totaled $83 million and consisted of $60 million principalamount of TCEH pollution control revenue bonds (PCRBs) subject to mandatory tender and remarketing in April 2013, which werepurchased in April 2013, and $23 million of scheduled installment payments on capital leases and debt securities.Debt Related Activity in 2013Principal amounts of long-term debt issued in the three months ended March 31, 2013 consisted of $340 million principalamount of incremental term loans under the TCEH Term Loan Facilities discussed in "Amendment and Extension of TCEHRevolving Credit Facility" above.Repayments of long-term debt in the three months ended March 31, 2013 totaled $16 million and consisted of $14 millionof payments of principal at scheduled maturity dates and $2 million of contractual payments under capital leases.13 Table of ContentsIn April 2013, TCEH acquired for $40 million in cash the owner participant interest in a trust established to lease naturalgas-fueled combustion turbines to TCEH. The interest in the trust was held by an unaffiliated party. The trust is a VIE, and inaccordance with accounting standards, the trust will be consolidated in the second quarter 2013, with the trust's combustion turbineassets and related debt being recorded at estimated fair values. At March 31, 2013, the principal amount of the trust's debt totaled$45 million.Issuance of EFIH 10% Senior Secured Notes and EFIH 11.25%/12.25% Toggle Notes in Exchange for EFH Corp. DebtGuaranteed by EFCH- In exchanges in January 2013, EFIH and EFIH Finance issued $1.302 billion principal amount of EFIH10% Senior Secured Notes due 2020 (EFIH 10% Notes) in exchange for $1.310 billion total principal amount of EFH Corp. andEFIH senior secured notes consisting of: (i) $113 million principal amount of EFH Corp. 9.75% Senior Secured Notes due 2019(EFH Corp. 9.75% Notes), (ii) S1.058 billion principal amount of EFH Corp. 10% Senior Secured Notes due 2020 (EFH Corp.10% Notes), and (iii) $139 million principal amount of EFIH senior secured notes.In connection with these debt exchange transactions, EFH Corp. received the requisite consents from holders of the EFHCorp. 9.75% Notes and EFH Corp. 10% Notes to certain amendments to the respective indentures governing these notes. Theseamendments, among other things, made EFCH and EFIH unrestricted subsidiaries under the EFH Corp. 9.75% Notes and EFHCorp. 10% Notes, thereby eliminating EFCH's and EFIH's guarantees of the notes.In additional exchanges in January 2013, EFIH and EFIH Finance issued $89 million principal amount of 11.25%/12.25%Toggle Notes due 2018 (EFIH Toggle Notes) in exchange for $95 million total principal amount of EFH Corp. senior notesconsisting of: (i) $31 million principal amount of EFH Corp. 10.875% Senior Notes due 2017 (EFH Corp. 10.875% Notes), (ii)$33 million principal amount of EFH Corp. 11.25%/12.00% Senior Toggle Notes due 2017 (EFH Corp. Toggle Notes) and (iii)$31 million principal amount of other EFH Corp. unsecured debt.In the first quarter 2013, EFIH distributed $6.360 billion principal amount of EFH Corp. debt guaranteed by EFCH thatEFIH previously received in debt exchanges as a dividend to EFH Corp., which cancelled the notes. The dividend included $1.715billion principal amount of EFH Corp. 10.875% Notes, $3.474 billion principal amount of EFH Corp. Toggle Notes, $1.058 billionprincipal amount of EFH Corp. 10% Notes and $113 million principal amount of EFH Corp. 9.75% Notes.After these early 2013 transactions, EFCH guarantees only $60 million principal amount of EFH Corp. debt as discussedbelow in "Guarantees and Push Down of EFH Corp. Debt."Guarantees and Push Down of EFH Corp. DebtMerger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing at the time of the Merger. Debtissued in exchange for Merger-related debt is considered Merger-related. Debt issuances are considered Merger-related debt tothe extent the proceeds are used to repurchase Merger-related debt. Merger-related debt of EFH Corp. (parent) that is fully andunconditionally guaranteed on ajoint and several basis by EFIH and EFCH (parent entity) is subject to push down in accordancewith SEC Staff Accounting Bulletin Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected inour financial statements. Merger-related debt of EFH Corp. held by its subsidiaries is not subject to push down.The amount reflected in our balance sheet as pushed down debt ($30 million and $450 million at March 31, 2013 andDecember 31,2012, respectively, as shown in the long-term debt table above) represents 50% of the principal amount of the EFHCorp. Merger-related debt guaranteed by EFCH (parent entity). This percentage reflects the fact that at the time of the Merger,the equity investments of EFCH (parent entity) and EFIH in their respective operating subsidiaries were essentially equal amounts.Because payment of principal and interest on the debt is the responsibility of EFH Corp., we record the settlement of such amountsas noncash capital contributions from EFH Corp.14 Table of ContentsThe table below presents, an analysis of the total outstanding principal amount of EFH Corp. debt that EFCH (parent entity)and EFIH had guaranteed (fully and unconditionally on a joint and several basis) at December 31, 2012, as (i) amounts that EFIHheld as an investment, (ii) amounts held by nonaffiliates subject to push down to our balance sheet and (iii) amounts held bynonaffiliates that are not Merger-related. As discussed in note (a) to the table below, as a result of transactions in early 2013, debtguaranteed and subject to push down at March 31, 2013 totals $60 million and consists of $33 million principal amount of EFHCorp. 10.875% Senior Notes and $27 million principal amount of EFH Corp. 11.25%/I 2.00% Senior Toggle Notes. The guaranteeis not secured.December 31, 2012 (a)Subject to Push Not Merger- TotalSecurities Guaranteed (principal amounts) Held by EFIH Down Related GuaranteedEFH Corp. 9.75% and 10% Senior Notes $ -$ 776 $ 400 $ 1,176EFH Corp. 10.875% Senior Notes 1,685 64 -1,749EFH Corp. 11.25%/12.00% Senior Toggle Notes 3,441 60 -3,501Subtotal $ 5,126 $ 900 $ 400 6,426TCEH Demand Notes (Note 11) 698Total $ 7,124(a) As a result of transactions completed in early 2013, the $5.126 billion principal amount of EFH Corp. 10.875% Senior Notesand 11.25%/12.00% Senior Toggle Notes were distributed by EFIH as a dividend to EFH Corp., which cancelled them,substantially all of the $1.176 billion principal amount of EFH Corp. 9.75% and 10% Senior Notes have been cancelled,$64 million of the $124 million principal amount of EFH Corp. 10.875% Senior Notes and 11.25%/12.00% Senior ToggleNotes subject to push down have been cancelled and the TCEH Demand Notes have been settled (see Note 11).Information Regarding Other Significant Outstanding DebtTCEH Senior Secured Facilities -Borrowings under the TCEH Senior Secured Facilities totaled $22.635 billion atMarch 31, 2013 and consisted of:* $3.809 billion of TCEH Term Loan Facilities maturing in October 2014 with interest payable at LIBOR plus 3.50%;* $15.7 10 billion of TCEH Term Loan Facilities maturing in October 2017 with interest payable at LIBOR plus 4.50%;* $42 million of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2014 with interest payableat LIBOR plus 3.50% (see discussion under "Credit Facilities" above);* $1.020 billion of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2017 with interest payableat LIBOR plus 4.50% (see discussion under "Credit Facilities" above), and* Amounts borrowed under the TCEH Revolving Credit Facility, which may be reborrowed from time to time until October2016 and represent the entire amount of commitments under the facility totaling $2.054 billion at March 31, 2013. See"Credit Facilities" above for discussion regarding the maturity date extension of $645 million in commitments from 2013to 2016.Each of the loans described above that matures in 2016 or 2017 includes a "springing maturity" provision pursuant to which(i) in the event that more than $500 million aggregate principal amount of the TCEH 10.25% Notes due in 2015 (other than notesheld by EFH Corp. or its controlled affiliates at March 31,2011 to the extent held at the determination date as defined in the CreditAgreement) or more than $150 million aggregate principal amount of the TCEH Toggle Notes due in 2016 (other than notes heldby EFH Corp. or its controlled affiliates at March 31, 2011 to the extent held at the determination date as defined in the CreditAgreement), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (ii) TCEH'stotal debt to Adjusted EBITDA ratio (as defined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at the applicabledetermination date, then the maturity date of the extended loans will automatically change to 90 days prior to the maturity dateof the applicable notes.Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are severaland not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH's available liquidity could be reduced by an amountup to the aggregate amount of such lender's commitments under the TCEH Senior Secured Facilities.15 Table of ContentsThe TCEH Senior Secured Facilities are fully and unconditionally guaranteed jointly and severally on a senior secured basisby EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US subsidiary of TCEH.The TCEH Senior Secured Facilities, along with the TCEH Senior Secured Notes and certain commodity hedging transactionsand the interest rate swaps described under "TCEH Interest Rate Swap Transactions" below, are secured on a first priority basisby (i) substantially all of the current and future assets of TCEH and TCEH's subsidiaries who are guarantors of such facilities and(ii) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.TCEH 11.5% Senior Secured Notes -At March 31, 2013, the principal amount of the TCEH 11.5% Senior Secured Notestotaled $1.750 billion. The notes mature in October 2020, with interest payable in cash quarterly in arrears on January 1, April 1,July 1 and October 1, at a fixed rate of 11.5% per annum. The notes are fully and unconditionally guaranteed on ajoint and severalbasis by EFCH and each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors).The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and the guarantees are securedon a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent such assets andequity interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), subject to certain exceptionsand permitted liens.The notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness of TCEH, (ii) seniorin right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of theTCEH Collateral and (iii) senior in right of payment to any future subordinated debt of TCEH. These notes are effectivelysubordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of thevalue of the assets securing such obligations.TCEH 15% Senior Secured Second Lien Notes (including Series B) -At March 31, 2013, the principal amount of theTCEH 15% Senior Secured Second Lien Notes totaled $1.571 billion. These notes mature in April 2021, with interest payable incash quarterly in arrears on January 1, April 1, July 1 and October 1 at a fixed rate of 15% per annum. The notes are fully andunconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH thatguarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by security interests in all ofthe assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of theassets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to theextent such assets and security interests secure obligations under the TCEH Senior Secured Facilities on a first-priority basis,subject to certain exceptions (including the elimination of the pledge of equity interests of any Subsidiary Guarantor to the extentthat separate financial statements would be required to be filed with the SEC for such Subsidiary Guarantor under Rule 3-16 ofRegulation S-X) and permitted liens. The guarantee from EFCH is not secured.The notes are senior obligations of the issuer and rank equally in right of payment with all senior indebtedness of TCEH,are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral(after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinateddebt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, theTCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEHCollateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEHCollateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of thevalue of the assets securing such obligations.TCEH 10.25% Senior Notes (including Series B) and 10.50/11.25% Senior Toggle Notes (collectively, the TCEH SeniorNotes) -At March 31, 2013, the principal amount of the TCEH Senior Notes totaled $5.237 billion, including $363 millionaggregate principal amount held by EFH Corp. and EFIH, and the notes are fully and unconditionally guaranteed on a joint andseveral unsecured basis by TCEH's direct parent, EFCH (which owns 100% of TCEH), and by each subsidiary that guaranteesthe TCEH Senior Secured Facilities. The TCEH 10.25% Notes mature in November 2015, with interest payable in cash semi-annually in arrears on May I and November 1 at a fixed rate of 10.25% per annum. The TCEH Toggle Notes mature in November2016, with interest payable semi-annually in arrears on May I and November 1 at a fixed rate of 10.50% per annum for cashinterest and at a fixed rate of 11.25% per annum for PIK Interest, which option expired with the November 1,2012 interest payment.16 Table of ContentsFair Value of Long-Term DebtAt March 31, 2013 and December 31, 2012, the estimated fair value of our long-term debt (excluding capital leases) totaled$17.297 billion and $ 17.858 billion, respectively, and the carrying amount totaled $30.141 billion and $30.342 billion, respectively.At March 31, 2013 and December 31, 2012, the estimated fair value of our short-term borrowings under the TCEH RevolvingCredit Facilities totaled $1.412 billion and $1.500 billion, respectively, and the carrying amount totaled $2.054 billion. Wedetermine fair value in accordance with accounting standards as discussed in Note 8, and at March 31, 2013, our debt fair valuerepresents Level 2 valuations. We obtain security pricing from a vendor who uses broker quotes and third-party pricing servicesto determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.TCEH Interest Rate Swap TransactionsTCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at March 31,2013, TCEH has entered into the following series of interest rate swap transactions that effectively fix the interest rates at between5.5% and 9.3%.Fixed Rates Expiration Dates Notional Amount5.5% -9.3% September 2013 through October 2014 $18.265 billion (a)6.8% -9.0% October 2015 through October 2017 $12.600 billion (b)(a) Swaps related to an aggregate $600 million principal amount of debt expired in 2013. Per the terms of the transactions, thenotional amount of swaps entered into in 2011 grew by $405 million in 2013, substantially offsetting the expired swaps.(b) These swaps are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes$3 billion that expires in October 2015 with the remainder expiring in October 2017.TCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achievedthrough the interest rate swaps. Basis swaps in effect at March 31, 2013 totaled $11.967 billion notional amount. The basis swapsrelate to debt outstanding through 2014.The interest rate swap counterparties are secured on an equal and ratable basis by the same collateral pledged to the lendersunder the TCEH Senior Secured Facilities.The interest rate swaps have resulted in net losses reported in interest expense and related charges as follows:Three Months Ended March 31,2013 2012Realized net loss $ (151) $ (168)Unrealized net gain 148 110Total $ (3) $ (58)The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.917 billion and$2.065 billion at March 31, 2013 and December 31, 2012, respectively, of which $62 million and $65 million (both pretax),respectively, were reported in accumulated other comprehensive income.17 Table of Contents6. COMMITMENTS AND CONTINGENCIESGuaranteesWe have entered into contracts that contain guarantees to unaffiliated parties that could require performance or paymentunder certain conditions. Material guarantees are discussed below.See Note 5 for discussion of guarantees and security for certain of our debt and EFCH guarantees of certain EFH Corp. debt.Letters of CreditAt March 31, 2013, TCEH had outstanding letters of credit under its credit facilities totaling $735 million as follows:* $330 million to support risk management and trading margin requirements in the normal course of business, includingover-the-counter hedging transactions and collateral postings with ERCOT;* $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);* $65 million to support TCEH's REP financial requirements with the PUCT, and* $132 million for miscellaneous credit support requirements.LitigationIn March 2013, Aurelius Capital Master, Ltd. and ACP Master, Ltd. filed a lawsuit in the United States District Court forthe Northern District of Texas (Dallas Division) against EFCH as a nominal defendant and each of the current directors and aformer director of EFCH. In the lawsuit, Aurelius, as a creditor under the TCEH Senior Secured Facilities and certain TCEHsecured bonds both of which are guaranteed by EFCH, filed a derivative claim against EFCH and its directors. Aurelius allegesthat the directors of EFCH breached their fiduciary duties to EFCH and its creditors, including Aurelius, by permitting TCEH tomake certain loans "without collecting fair and reasonably equivalent value." The lawsuit seeks recovery for the benefit of EFCH.We cannot predict the outcome of this proceeding, including the financial effects, if any.Litigation Related to Generation Facilities -In November 2010, an administrative appeal challenging the decision of theTCEQ to renew and amend Oak Grove Management Company LLC's (Oak Grove) (a wholly-owned subsidiary of TCEH) TexasPollutant Discharge Elimination System (TPDES) permit related to water discharges was filed by Robertson County: Our Land,Our Lives and Roy Henrichson in the Travis County, Texas District Court. Plaintiffs sought a reversal of the TCEQ's order anda remand back to the TCEQ for further proceedings. The district court affirmed the TCEQ's issuance of the TPDES permit to OakGrove. In December 2012, plaintiffs appealed the district court's decision to the Third Court of Appeals in Austin, Texas. Whilewe cannot predict the timing or outcome of this proceeding, we believe the renewal and amendment of the Oak Grove TPDESpermit are protective of the environment and were in accordance with applicable law.In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (TexarkanaDivision) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violationsof the Clean Air Act (CAA) at Luminant's Martin Lake generation facility. In May 2012, the Sierra Club filed a lawsuit in the USDistrict Court for the Western District of Texas (Waco Division) against EFH Corp. and Luminant Generation Company LLC foralleged violations of the CAA at Luminant's Big Brown generation facility. The Big Brown case is currently scheduled for trialin November 2013, and the Martin Lake case does not yet have a trial date. While we are unable to estimate any possible loss orpredict the outcome, we believe that the Sierra Club's claims are without merit, and we intend to vigorously defend these lawsuits.In addition, in December 2010 and again in October 2011, the Sierra Club informed Luminant that it may sue Luminant forallegedly violating CAA provisions in connection with Luminant's Monticello generation facility. In May 2012, the Sierra Clubinformed us that it may sue us for allegedly violating CAA provisions in connection with Luminant's Sandow 4 generation facility.While we cannot predict whether the Sierra Club will actually file suit regarding Monticello or Sandow 4 or the outcome of anyresulting proceedings, we believe we have complied with the requirements of the CAA at all of our generation facilities.See below for discussion of litigation regarding the CSAPR and the Texas State Implementation Plan.18 Table of ContentsRegulatory ReviewsIn June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of theCAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, includingNew Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generationfacilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received alarge and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently receiveda notice of violation from the EPA, which has in some cases progressed to litigation or settlement. In July 2012, the EPA sent usa notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our MartinLake and Big Brown generation facilities. While we cannot predict whether the EPA will initiate enforcement proceedings underthe notice of violation, we believe that we have complied with all requirements of the CAA at all of our generation facilities. Wecannot predict the outcome of any resulting enforcement proceedings or estimate the penalties that might be assessed in connectionwith any such proceedings. In September 2012, we filed a petition for review in the United States Court of Appeals for the FifthCircuit Court (Fifth Circuit Court) seekingjudicial review of the EPA's notice of violation. Given recent legal precedent subjectingagency orders like the notice of violation to judicial review, we filed the petition for review to preserve our ability to challengethe EPA's issuance of the notice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December2012, the Fifth Circuit Court issued an order that will delay a ruling on the EPA's motion to dismiss until after the case has beenfully briefed and oral argument, if any, is held. In April 2013, we received an additional information request from the EPA underSection 114 related to the Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to theSandow 4 generation facility. We cannot predict the outcome of these proceedings, including the financial effects, if any.Cross-State Air Pollution Rule (CSAPR)In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions ofsulfur dioxide (SO2) and nitrogen oxides (NO.) emissions from our fossil-fueled generation units. In September 2011, we fileda petition for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) challenging the CSAPRas it applies to Texas. If the CSAPR had taken effect, it would have caused us to, among other actions, idle two lignite/coal-fueledgeneration units and cease certain lignite mining operations by the end of 2011.In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR,including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule.In April 2012, we filed in the D.C. Circuit Court a petition for review of the Final Revisions on the ground, among others, thatthe rules do not include all of the budget corrections we requested from the EPA. The parties to the case agreed that the caseshould be held in abeyance pending the conclusion of the CSAPR rehearing proceeding discussed below. In June 2012, the EPAfinalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPR issued by the EPA inOctober 2011, the Final Revisions and the Second Revised Rule finalize emissions budgets for our generation assets that areapproximately 6% lower for SO2, 3% higher for annual NO, and 2% higher for seasonal NO,,.In August 2012, a three judge panel of the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for furtherproceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule do not impose any immediate requirementson us, the State of Texas, or other affected parties. The D.C. Circuit Court's order stated that the EPA was expected to continueadministering the CAIR (the predecessor rule to the CSAPR) pending the EPA's further consideration of the rule. In October2012, the EPA and certain other parties that supported the CSAPR filed petitions with the D.C. Circuit Court seeking review bythe full court of the panel's decision to vacate and remand the CSAPR. In January 2013, the D.C. Circuit Court denied theserequests for rehearing, concluding the CSAPR rehearing proceeding. In March 2013, the EPA and certain other parties thatsupported the CSAPR submitted petitions to the US Supreme Court seeking its review of the D.C. Circuit Court decision. Wecannot predict whether the US Supreme Court will grant or deny the petitions or the outcome of any granted review.State Implementation Plan (SIP)In September 2010, the EPA disapproved a portion of the State Implementation Plan pursuant to which the TCEQ implementsits program to achieve the requirements of the CAA. The EPA disapproved the Texas standard permit for pollution control projects.We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. We challengedthe EPA's disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) arguing that theTCEQ's adoption of the standard permit conditions for pollution control projects was consistent with the CAA. In March 2012,the Fifth Circuit Court vacated the EPA's disapproval of the Texas standard permit for pollution control projects and remandedthe matter to the EPA for reconsideration. We cannot predict the timing or outcome of the EPA's reconsideration, including thefinancial effects, if any.19 Table of ContentsIn November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacingthat exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generationfacility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicabilityof the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and receivedthe generation facility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the Fifth CircuitCourt arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issuedis consistent with the CAA. In July 2012, the Fifth Circuit Court denied our challenge and ruled that the EPA's actions were inaccordance with the CAA. In October 2012, the Fifth Circuit Court panel withdrew its opinion and issued a second, expandedopinion that again upheld the EPA's disapproval. In November 2012, we filed a petition with the Fifth Circuit Court asking forreview by the full Fifth Circuit Court of the panel's second opinion. Other parties to the proceedings also filed a petition with theFifth Circuit Court asking the panel to reconsider its decision. In March 2013, the Fifth Circuit Court panel withdrew its secondopinion and issued a third opinion that again upheld the EPA's actions. In April 2013, the Fifth Circuit Court also denied ourNovember 2012 petition for rehearing of the panel's second opinion and denied the request by other parties for the panel toreconsider its second decision. Following the issuance of the mandate, we filed a motion to recall the mandate, which was deniedin a single-judge order. The parties to this proceeding have approximately 90 days to appeal the Fifth Circuit Court's decision tothe US Supreme Court. We cannot predict the timing or outcome of this proceeding, including the financial effects, if any, relatedto the EPA's disapproval of this SIP provision.Other MattersWe are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutionsof which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity orfinancial condition.20 Table of Contents7. EQUITYDividend RestrictionsWhile EFCH has no contractual dividend restrictions, the TCEH Senior Secured Facilities generally restrict TCEH frommaking any cash distribution to any of its parent companies for the ultimate purpose of making a cash distribution on their commonstock unless at the time, and after giving effect to such distribution, TCEH's consolidated total debt (as defined in the TCEH SeniorSecured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. At March 31, 2013, the ratio was 9.0 to 1.0.In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior SecuredNotes and TCEH Senior Secured Second Lien Notes generally restrict TCEH's ability to make distributions or loans to any of itsparent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior SecuredFacilities and the indentures governing such notes.Under applicable law, we are also prohibited from paying any dividend to the extent that immediately following paymentof such dividend, there would be no statutory surplus or we would be insolvent.Noncontrolling InterestsAs discussed in Note 2, we consolidate a joint venture formed in 2009 for the purpose of developing two new nucleargeneration units, which results in a noncontrolling interests component of equity. As discussed in Notes 2 and 4, prior to November2012, we also consolidated a VIE owned by EFH Corp. related to our accounts receivable securitization program, which resultedin a noncontrolling interests component of equity. Net loss attributable to the noncontrolling interests was immaterial for the threemonths ended March 31, 2013 and 2012.EquityThe following tables present the changes to equity for the three months ended March 31, 2013 and 2012.Three Months Ended March 31, 2013EFCH Shareholder's EquityAccumulatedRetained OtherCommon Earnings Comprehensive Noncontrolling TotalStock (Deficit) Income (Loss) Interests Equity$ 7,665 $ (18,129) S (42) $ 112 $ (10,394)-(526) --(526)Balance at December 31, 2012Net lossNet effect of cash flow hedgesInvestment by noncontrolling interestsEffect of debt push-down from EFHCorp. (a)Balance at March 31, 2013221I434 ---434$ 8,099 $ (18,655) $ (40)$ 113 $ (10,483)21 Table of ContentsThree Months Ended March 31, 2012EFCH Shareholder's EquityAccumulatedRetained OtherCommon Earnings Comprehensive Noncontrolling TotalStock (Deficit) Income (Loss) Interests Equity$ 7,351 $ (15,121) $ (49) $ 103 $ (7,716)-(253) --(253)Balance at December 31, 2011Net lossEffect of stock-based incentivecompensation plansNet effect of cash flow hedgesInvestment by noncontrolling interestsEffect of debt push-down from EFHCorp. (a)Balance at March 31, 201223232212 ---12$ 7,365 $ (15,374) $ (46) $ 105 $ (7,950)(a) Represents the interest and income tax effects of debt pushed down from EFH Corp. (Note 5).22 Table of Contents8. FAIR VALUE MEASUREMENTSAccounting standards related to the determination of fair value define fair value as the price that would be received to sellan asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a"mid-market" valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair valuefor the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the marketapproach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimizethe use of unobservable inputs.We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:Level I valuations use quoted prices in active markets for identical assets or liabilities that are accessible at themeasurement date. An active market is a market in which transactions for the asset or liability occur with sufficientfrequency and volume to provide pricing information on an ongoing basis. Our Level I assets and liabilities includeexchange-traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures andswaps transacted through clearing brokers for which prices are actively quoted.Level 2 valuations use inputs that, in the absence of actively quoted market prices, are observable for the asset or liability,either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets,(b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quotedprices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quotedintervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation orother means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilitiesthat are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes areavailable.Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observableinputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset orliability at the measurement date. We use the most meaningful information available from the market combined withinternally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assetsand liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs tothe valuations, including inputs that are not observable or easily corroborated through other means. See further discussionbelow.Our valuation policies and procedures are developed, maintained and validated by an EFH Corp. centralized risk managementgroup that reports to the EFH Corp. Chief Financial Officer, who also functions as the Chief Risk Officer. Risk managementfunctions include commodity price reporting and validation, valuation model validation, risk analytics, risk control, credit riskmanagement and risk reporting.We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on themarket approach of using prices and other market information for identical and/or comparable assets and liabilities for those itemsthat are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationshipsbetween different price curves.In utilizing broker quotes, we attempt to obtain multiple quotes from brokers (generally non-binding) that are active in thecommodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input asobservable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputsvaries depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends andvarious other factors. In addition, for valuation of interest rate swaps, we use generally accepted interest swap valuation modelsutilizing month-end interest rate curves.Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multipleinputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficientamount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significantunobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locationsand credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forward pricecurves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fairvalue measurements resulting from such curves are classified as Level 3.23 Table of ContentsThe significant unobservable inputs and valuation models are developed by employees trained and experienced in marketoperations and fair value measurement and validated by the company's risk management group, which also further analyzes anysignificant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upwardor downward changes in the fair value measurement.With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset orliability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fairvalue measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for theeffects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input tothe fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.Assets and liabilities measured at fair value on a recurring basis consisted of the following at March 31, 2013 and December31, 2012:March 31, 2013Level 1 Level 2 Level 3 (a) TotalAssets:Commodity contractsInterest rate swapsNuclear decommissioning trust -equity securities (b)Nuclear decommissioning trust -debt securities (b)Total assetsLiabilities:Commodity contractsInterest rate swapsTotal liabilities$ 192 $1,333 $I106 $1,6311276 159 -435-266 -266$ 468 S 1.,759 $ 106 $ 2,333$ 278 $ 135 $ 47 $ 460-1,918 -1,918278 $ 2.053 $ 47 $ 2,378December 31, 2012Level I Level 2 Level 3 (a) TotalAssets:Commodity contractsInterest rate swapsNuclear decommissioning trust -equity securities (b)Nuclear decommissioning trust -debt securities (b)Total assetsLiabilities:Commodity contractsInterest rate swapsTotal liabilities$ 180 $2491,784 $214483 $2,0472393-261 -261$ 429 $ 2.,191 $ 83 $ 2,703$ 208 $ 121 $ 54 $ 383-2,067 -2,067$ 208 $ 2,188 S 54 $ 2,450(a) See table below for description of Level 3 assets and liabilities.(b) The nuclear decommissioning trust investment is included in the investments line in the balance sheet. See Note 12.Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal derivative instruments enteredinto for hedging purposes and include physical contracts that have not been designated "normal" purchases or sales. See Note 9for further discussion regarding the company's use of derivative instruments.Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debtas well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 5 for discussion of interestrate swaps.Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement anddecommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securitiesconsistent with investment rules established by the NRC and the PUCT.24 Table of ContentsThere were no significant transfers between Level I and Level 2 of the fair value hierarchy for the three months ended March31, 2013 and 2012. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfers betweenLevel 2 and Level 3.The following tables present the fair value of the Level 3 assets and liabilities by major contract type (all related to commoditycontracts) and the significant unobservable inputs used in the valuations at March 31, 2013 and December 31, 2012:March 31, 2013Fair ValueContract Type(a)Electricitypurchases andsalesValuationAssets Liabilities Total TechniqueValuation$ 4 $ (8) $ (4) ModelSignificant Unobservable InputRange (b)$30 to $40/MWh$15 to $50/MWhElectricityspread optionsElectricitycongestionrevenue rightsCoalpurchasesOtherOption Pricing45 Model58(13)Illiquid pricing locations (c)Hourly price curve shape(d)Gas to power correlation (e)Power volatility (f)Illiquid price differencesbetween settlement points(h)Illiquid price variancesbetween mines (i)Probability of default (j)Recovery rate (k)25% to 90%15% to 35%394(3)(22)(1)Market36 Approach (g)Market(21) Approach (g)$0.00 to $30.00$0.00 to $1.000% to 40%0% to 40%3Total $ 106 $ (47) $ 5925 Table of ContentsDecember 31, 2012Fair ValueContract Type Valuation(a) Assets Liabilities Total Technique Significant Unobservable Input Range (b)Electricitypurchases and Valuation $20 to $40/sales 5 $ (9) $ (4) Model Illiquid pricing locations (c) MWhHourly price curve shape $20 to $50!(d) MWhElectricity Option Pricingspread options 34 (10) 24 Model Gas to power correlation (e) 20% to 90%Power volatility (f) 20% to 40%Electricity Illiquid price differencescongestion Market between settlement pointsrevenue rights 41 (2) 39 Approach (g) (h) $0.00 to $0.50Coal Market Illiquid price variancespurchases -(32) (32) Approach (g) between mines (i) $0.00 to $1.00Probability of default 0) 5% to 40%Recovery rate (k) 0% to 40%Other 3 (1) 2Total $ 83 $ (54) $ 29(a) Electricity purchase and sales contracts include wind generation agreements and hedging positions in the ERCOT westregion, as well as power contracts, the valuations of which include unobservable inputs related to the hourly shaping of theprice curve. Electricity spread options consist of physical electricity call options. Electricity congestion revenue rightscontracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences betweensettlement points within ERCOT. Coal purchase contracts relate to western (Powder River Basin) coal.(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.(c) Based on the historical range of forward average monthly ERCOT West Hub prices.(d) Based on the historical range of forward average hourly ERCOT North Hub prices.(e) Estimate of the historical range based on forward natural gas and on-peak power prices for the ERCOT hubs most relevantto our spread options.(f) Based on historical forward price changes.(g) While we use the market approach, there is either insufficient market data to consider the valuation liquid or the significanceof credit reserves or non-performance risk adjustments results in a Level 3 designation.(h) Based on the historical price differences between settlement points in the ERCOT North Hub for 2012 and the ERCOT Northand West Hubs in 2013.(i) Based on the historical range of price variances between mine locations.() Estimate of the range of probabilities of default based on past experience and the length of the contract as well as our andcounterparties' credit ratings.(k) Estimate of the default recovery rate based on historical corporate rates.26 Table of ContentsThe following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts)for the three months ended March 31, 2013 and 2012:Three Months Ended March 31,2013 2012Net asset balance at beginning of period 29 $ 53Total unrealized valuation gains (losses) 9 (69)Purchases, issuances and settlements (a):PurchasesIssuancesSettlementsTransfers into Level 3 (b)Transfers out of Level 3 (b)Net change (c)Net asset (liability) balance at end of periodUnrealized valuation gains (losses) relating to instruments held at end of period48(8)16 201 (7)-(2)30 (58)$ 59 $ (5)$ 14 $ (65)(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases andissuances reflect option premiums paid or received.(b) Includes transfers due to changes in the observability of significant inputs. Transfers in and out occur at the end of eachquarter, which is when the assessments are performed. Transfers out during 2012 reflect increased observability of pricingrelated to certain congestion revenue rights. Transfers in during 2012 were driven by an increase in nonperformance riskadjustments related to certain coal purchase contracts. All Level 3 transfers during the periods presented are in and out ofLevel 2.(c) Substantially all changes in values of commodity contracts are reported in the income statement in net gain (loss) fromcommodity hedging and trading activities. Activity excludes changes in fair value in the month the position settled as wellas amounts related to positions entered into and settled in the same month.27 Table of Contents9. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIESStrategic Use of DerivativesWe transact in derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodityprice risk and interest rate risk exposure. Our principal activities involving derivatives consist of a commodity hedging programand the hedging of interest costs on our long-term debt. See Note 8 for a discussion of the fair value of all derivatives.Natural Gas Price Hedging Program -TCEH has a natural gas price hedging program designed to reduce exposure tochanges in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricitysales and related cash flows. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas.Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has soldforward natural gas through 2014. These transactions are intended to hedge a portion of electricity price exposure related toexpected lignite/coal- and nuclear-fueled generation for this period. Unrealized gains and losses arising from changes in the fairvalue of the instruments under the program as well as realized gains and losses upon settlement of the instruments are reported inthe income statement in net gain (loss) from commodity hedging and trading activities.Interest Rate Swap Transactions -Interest rate swap agreements are used to reduce exposure to interest rate changes byconverting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swapsare used to effectively reduce the hedged borrowing costs. Unrealized gains and losses arising from changes in the fair value ofthe swaps as well as realized gains and losses upon settlement of the swaps are reported in the income statement in interest expenseand related charges. See Note 5 for additional information about interest rate swap agreements.Other Commodity Hedging and TradingActivity -In addition to the natural gas price hedging program, TCEH enters intoderivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for shorter-term hedgingpurposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in naturalgas and electricity markets.Financial Statement Effects of DerivativesSubstantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accountingstandards related to derivative instruments and hedging activities. The following tables provide detail of commodity and otherderivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported inthe balance sheets at March 31, 2013 and December 31, 2012:Current assetsNoncurrent assetsCurrent liabilitiesNoncurrent liabilitiesNet assets (liabilities)March 31, 2013Derivative assets Derivative liabilitiesCommodity Interest rate Commodity Interest ratecontracts swaps contracts swaps Total$ 1,207 $ 1 $ -$ -$ 1,208424 ---424-- (448) (523) (971)-- -- (12) _ (1,395) (1,407)$ 1,631 $ (460)_ (1,918Current assetsNoncurrent assetsCurrent liabilitiesNoncurrent liabilitiesNet assets (liabilities)December 31, 2012Derivative assets Derivative liabilitiesCommodity Interest rate Commodity Interest ratecontracts swaps contracts swaps Total$ 1,461 $ 2 $ -$ -$ 1,463586 ---586-- (366) (528) (894)-- -(17) (1,539) (1,556)$ 2,047 $ 2 (383)$ (2,067 (40128 Table of ContentsAt March 31, 2013 and December 31 2012, there were no derivative positions accounted for as cash flow or fair valuehedges.The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealizedeffects:Three Months Ended March 31,Derivative (income statement presentation) 2013 2012Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a) $ (200) $ 358Interest rate swaps (Interest expense and related charges) (b) (3) (58)Net gain (loss) $ (203) $ 300(a) Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts relatedto positions settled are assumed to equal reversals of previously recorded unrealized amounts.(b) Includes unrealized mark-to-market net gain as well as the net realized effect on interest paid/accrued, both reported in "InterestExpense and Related Charges" (see Note 12).The following table presents the pretax effect (all losses) on net income and other comprehensive income (OCI) of derivativeinstruments previously accounted for as cash flow hedges. There were no amounts recognized in OCI for the three months endedMarch 31, 2013 or 2012.Three Months Ended March 31,Derivative type (income statement presentation of loss reclassified from accumulated OCI into income) 2013 2012Interest rate swaps (interest expense and related charges) $ (2) $ (3)Interest rate swaps (depreciation and amortization) (1) (1)Total _3_L3 (41There were no transactions designated as cash flow hedges during the three months ended March 31, 2013 or 2012.Accumulated other comprehensive income related to cash flow hedges at March 31, 2013 and December 31, 2012 totaled$40 million and $42 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. Weexpect that $5 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive incomeat March 31, 2013 will be reclassified into net income during the next twelve months as the related hedged transactions affect netincome.Balance Sheet Presentation of DerivativesConsistent with elections under US GAAP to present amounts on a gross basis, we report derivative assets and liabilities inthe balance sheet without taking into consideration netting arrangements we have with counterparties. This presentation can resultin significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties,resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet. Margindeposits received from counterparties are either used for working capital or other corporate purposes or are deposited in a separaterestricted cash account. At March 31, 2013 and December 31, 2012, margin deposits held were unrestricted.We maintain standardized master netting agreements with counterparties that allow for the netting of positive and negativeexposures. Generally, we utilize the International Swaps and Derivatives Association (ISDA) standardized contract for financialtransactions, the Edison Electric Institute standardized contract for physical power transactions and the North American EnergyStandards Board (NAESB) standardized contract for physical natural gas transactions. These contain credit enhancements thatallow for the right to offset assets and liabilities with other financial instruments and collateral received in order to reduce creditexposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthlysettlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.Certain entities are counterparties to both our natural gas hedge program positions and our interest rate swaps and haveentered into master agreements that provide for netting and setoff of amounts related to these positions.29 Table of ContentsThe following tables reconcile our derivative assets and liabilities as presented in the consolidated balance sheet to net amountsafter taking into consideration netting arrangements with counterparties and financial collateral:March 31, 2013Amounts Presented in Offsetting Financial Financial CollateralBalance Sheet Instruments (a) (Received) Pledged (b) Net Amounts (c)Derivative assets:Commodity contractsInterest rate swapsTotal derivative assetsDerivative liabilities:Commodity contractsInterest rate swapsTotal derivative liabilitiesNet amounts$1,631 $(1,011) $(454) $1661 (1) -- --1,632 (1,012) (454) 166(460) 329 89 (42)(1,918) 683 -(1,235)(2,378) 1,012 89 (1,277)$ (746) $ -$ (365) $ (1,111)December 31, 2012Amounts Presented in Offsetting Financial Financial CollateralBalance Sheet Instruments (a) (Received) Pledged (b) Net AmountsDerivative assets:Commodity contractsInterest rate swapsTotal derivative assetsDerivative liabilities:Commodity contractsInterest rate swapsTotal derivative liabilitiesNet amounts$2,047 $(1,263) $(597) $1872 (2) -- --2,049 (1,265) (597) 187(383) 319 29 (35)(2,067) 946 -(1,121)(2,450) 1,265 29 (1,156)$ (401) $ -$ (568) $ (969)(a) Offsetting financial instruments with respect to commodity contracts include amounts related to interest rate swaps and viceversa. Amounts exclude trade accounts receivable and payable related to settled financial instruments.(b) Financial collateral consists entirely of cash margin deposits.(c) Includes net liability positions totaling approximately $1.3 billion related to counterparties with positions that are securedby a first-lien interest in the assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEHSenior Secured Notes.30 Table of ContentsDerivative Volumes -The following table presents the gross notional amounts of derivative volumes at March 31, 2013and December 31, 2012:March 31, 2013 December 31, 2012Derivative type Notional Volume Unit of MeasureInterest rate swaps:Floating/fixed (a) $ 30,865 $ 31,060 Million US dollarsBasis $ 11,967 $ 11,967 Million US dollarsNatural gas:Natural gas price hedge forward sales and purchases (b) 743 875 Million MMBtuLocational basis swaps 463 495 Million MMBtuAll other 1,921 1,549 Million MMBtuElectricity 61,470 76,767 GWhCongestion Revenue Rights (c) 88,033 111,185 GWhCoal 11 13 Million tonsFuel oil 35 47 Million gallonsUranium 804 441 Thousand pounds(a) Includes notional amount of interest rate swaps with maturity dates through October 2014 as well as notional amount of swapseffective from October 2014 with maturity dates through October 2017 (see Note 5).(b) Represents gross notional forward sales, purchases and options transactions in the natural gas price hedging program. Thenet amount of these transactions was approximately 310 million MMBtu and 360 million MMBtu at March 31, 2013 andDecember 31, 2012, respectively.(c) Represents gross forward purchases associated with instruments used to hedge price differences between settlement pointsin the nodal wholesale market design in ERCOT.Credit Risk-Related Contingent Features of DerivativesThe agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent featuresthat could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement.Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies;however, due to our credit ratings being below investment grade, substantially all of such collateral posting requirements arealready effective.At March 31, 2013 and December 31, 2012, the fair value of liabilities related to derivative instruments under agreementswith credit risk-related contingent features that were not fully cash collateralized totaled $112 million and $58 million, respectively.The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterpartiestotaling $31 million and $12 million at March 31,2013 and December 31,2012, respectively. Ifall the credit risk-related contingentfeatures related to these derivatives had been triggered, including cross default provisions, at March 31, 2013 and December 31,2012, there were no remaining liquidity requirements.In addition, certain derivative agreements that are collateralized primarily with liens on certain of our assets includeindebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under otherfinancing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of suchindebtedness. At March 31, 2013 and December 31, 2012, the fair value of derivative liabilities subject to such cross-defaultprovisions, largely related to interest rate swaps, totaled $1.962 billion and $2.150 billion, respectively, before consideration ofthe amount of assets subject to the liens. No cash collateral or letters of credit were posted with these counterparties at March 31,2013 or December 31, 2012 to reduce the liquidity exposure. If all the credit risk-related contingent features related to thesederivatives, including amounts related to cross-default provisions, had been triggered at March 31, 2013 and December 31, 2012,the remaining related liquidity requirement after reduction for derivative assets under netting arrangements but before considerationof the amount of assets subject to the liens would have totaled $1.235 billion and $1.122 billion, respectively. See Note 5 for adescription of other obligations that are supported by liens on certain of our assets.31 Table of ContentsAs discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-relatedcontingent features, including cross-default provisions, totaled $2.074 billion and $2.208 billion at March 31,2013 and December31, 2012, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivableand derivative assets under netting arrangements and assets subject to related liens.Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amountsto be posted if the features are triggered. These provisions include material adverse change, performance assurance, and otherclauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosedabove exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.Concentrations of Credit Risk Related to DerivativesTCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. At March 31, 2013,total credit risk exposure to all counterparties related to derivative contracts totaled $1.712 billion (including associated accountsreceivable). The net expdsure to those counterparties totaled $226 million at March 31, 2013 after taking into effect nettingarrangements, setoff provisions and collateral. At March 31, 2013, the credit risk exposure to the banking and financial sectorrepresented 91% of the total credit risk exposure and 59% of the net exposure, a significant amount of which is related to thenatural gas price hedging program, and the largest net exposure to a single counterparty totaled $52 million.Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerancebecause all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases therisk that a default by any of these counterparties would have a material effect on our financial condition, results of operations andliquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to postcollateral in the event of a material downgrade in their credit rating.We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorizespecific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positiveand negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit,surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financialcondition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty.The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event ofdefault by one or more counterparties could subsequently result in termination-related settlement payments that reduce availableliquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlementsif the counterparties owe amounts to us.32 Table of Contents10. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANSOur subsidiaries are participating employers in the EFH Retirement Plan, a defined benefit pension plan sponsored by EFHCorp. that is described further below. Our subsidiaries also participate with EFH Corp. and certain other subsidiaries of EFHCorp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirementof such employees. The net allocated pension and OPEB costs applicable to us totaled $3 million and $10 million for the threemonths ended March 31, 2013 and 2012, respectively.The decrease in costs in 2013 reflected the implementation completed in the fourth quarter 2012 of certain amendments toEFH Corp.'s pension plan that resulted in:* splitting off assets and liabilities under the plan associated with employees of Oncor and all retirees and terminated vestedparticipants of EFH Corp. and its subsidiaries (including discontinued businesses) to a new plan sponsored andadministered by Oncor (the Oncor Plan);* splitting off assets and liabilities under the plan associated with active employees of EFH Corp.'s competitive businesses,other than collective bargaining unit (union) employees, to a Terminating Plan, freezing benefits and vesting all accruedplan benefits for these participants;* the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities under the TerminatingPlan, and" maintaining assets and liabilities under the plan associated with union employees of EFH Corp.'s competitive businessesunder the current plan.The discount rates assumed in net pension and OPEB costs for 2013 are 4.30% and 4.10%, respectively. The expected ratesof return on pension and OPEB plan assets reflected in the 2013 cost amounts are 5.4% and 6.7%, respectively.In the first three months of 2013 we made a $50 million payment to EFH Corp. to settle TCEH's allocation of 2012 pension-related charges. We expect to make additional contributions in 2013 of $2 million for the pension and OPEB plans.33 Table of Contents11. RELATED-PARTY TRANSACTIONSThe following represent our significant related-party transactions.TCEH's retail operations pay Oncor for services it provides, principally the delivery of electricity. Expenses recordedfor these services totaled $225 million and $227 million for the three months ended March 31,2013 and 2012, respectively.The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at March 31, 2013 andDecember 31,2012 reflect amounts due currently to Oncor totaling $121 million and $53 million, respectively, (includedin trade accounts and other payables to affiliates) largely related to these electricity delivery fees." In August 2012, TCEH and Oncor agreed to settle at a discount two agreements related to securitization (transition) bondsissued by Oncor's bankruptcy-remote financing subsidiary in 2003 and 2004 to recover generation-related regulatoryassets. Under the agreements, TCEH had been reimbursing Oncor as described immediately below.Oncor collects transition surcharges from its customers to recover the transition bond payment obligations. Oncor'sincremental income taxes related to the transition surcharges it collects had been reimbursed by TCEH quarterly undera noninterest bearing note payable to Oncor that was to mature in 2016. TCEH's payments on the note totaled $10 millionfor the three months ended March 31, 2012.Under an interest reimbursement agreement, TCEH had reimbursed Oncor on a monthly basis for interest expense onthe transition bonds. Only the monthly accrual of interest under this agreement was reported as a liability. This interestexpense totaled $7 million for the three months ended March 31, 2012." Notes receivable from EFH Corp. were payable to TCEH on demand (TCEH Demand Notes) and arose from cash loanedfor debt principal and interest payments and other general corporate purposes of EFH Corp. At December 31, 2012, thenotes consisted of:December 31, 2012Note related to debt principal and interest payments (P&I Note) $ 465Note related to general corporate purposes (SG&A Note) 233Total $ 698The TCEH Demand Notes were guaranteed by EFIH and EFCH on a senior unsecured basis. The TCEH Demand Noteswere pledged as collateral under the TCEH Senior Secured Facilities. In February 2012, $950 million of the P&I Notewas repaid by EFH Corp. The repayment was funded by a debt issuance at EFIH in February 2012. In January 2013,EFIH used $680 million of the proceeds from its August 2012 debt issuance to pay a dividend to EFH Corp., which EFHCorp. used with cash on hand to repay the entire balance of the TCEH Demand Notes. The average daily balance of theTCEH Demand Notes totaled $233 million and $1.109 billion for the three months ended March 31, 2013 and 2012,respectively. The TCEH Demand Notes carried interest at a rate based on the one-month LIBOR rate plus 5.00%, andinterest income related to the TCEH Demand Notes totaled $3 million and $15 million for the three months ended March31, 2013 and 2012, respectively.EFCH has a demand note payable to EFH Corp., the proceeds from which were used to repay outstanding debt. The notetotaled $82 million and $81 million at March 31, 2013 and December 31, 2012, respectively, and carried interest at a ratebased on the one-month LIBOR rate plus 5.00%. Interest expense related to this note totaled $1 million for both the threemonths ended March 31, 2013 and 2012.Receivables from affiliates are measured at historical cost and primarily consisted of notes receivable for cash loaned toEFH Corp. for debt principal and interest payments and other general corporate purposes of EFH Corp. as discussedabove. TCEH reviews economic conditions, counterparty credit scores and historical payment activity to assess theoverall collectability of its affiliated receivables. There were no credit loss allowances at March 31, 2013 and December31, 2012.34 Table of ContentsA subsidiary ofEFH Corp. bills our subsidiaries for information technology, financial, accounting and other administrativeservices at cost. These charges, which are settled in cash and primarily reported in SG&A expenses, totaled $62 millionand $58 million for the three months ended March 31,2013 and 2012, respectively. Beginning in the fourth quarter 2012,TCEH reimburses a subsidiary of EFH Corp. for an allocated share of computer equipment purchased by the subsidiary.Amounts paid by TCEH in the three months ended March 31,2013 related to new computer equipment totaled $6 million,which was accounted for as an intangible asset to be amortized over the life of the equipment. Previously, the depreciationof such equipment was included in the administrative cost billings.Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facilityis funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to TCEH forcontribution to the trust fund with the intent that the trust fund assets, reported in investments in our balance sheet, willultimately be sufficient to fund the actual future decommissioning liability, reported in noncurrent liabilities in our balancesheet. The delivery fee surcharges remitted to TCEH totaled $4 million for both the three months ended March 31, 2013and 2012. Income and expenses associated with the trust fund and the decommissioning liability incurred by TCEH areoffset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates.At March 31, 2013 and December 31, 2012, the excess of the trust fund balance over the decommissioning liabilityresulted in a payable totaling $326 million and $284 million, respectively, included in other noncurrent liabilities in ourbalance sheet.EFH Corp. files consolidated federal income tax and Texas state margin tax returns that include our results; however,under a tax sharing agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts,including income taxes payable to or receivable from EFH Corp., are recorded as if we file our own corporate incometax return. As a result, we had income taxes payable to EFH Corp. of $44 million and $31 million at March 31, 2013and December 31, 2012, respectively. In connection with an agreement reached between EFH Corp. and the IRS inMarch 2013, we recorded a noncurrent income tax liability to EFH Corp. totaling $1.115 billion, reported as affiliate taxsharing liability (see Note 12). We made no income tax payments to EFH Corp. for the three months ended March 31,2013 or 2012." Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of anyREP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility.Under these tariffs, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateralsupport in an amount equal to estimated transition charges over specified time periods. Accordingly, at March 31, 2013and December 31, 2012, TCEH had posted letters of credit in the amount of $10 million and $11 million, respectively,for the benefit of Oncor." Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstandingissues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter ofcredit in an amount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred,two or more rating agencies downgrade Oncor's credit rating below investment grade." In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders.These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of eachmember ofthe Sponsor Group have from time to time engaged in commercial banking transactions with us and/or providedfinancial advisory services to us, in each case in the normal course of business." Affiliates of GS Capital Partners are parties to certain commodity and interest rate hedging transactions with us in thenormal course of business." Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issuedby us in open market transactions or through loan syndications.35 Table of Contents* As a result of debt repurchase and exchange transactions in 2009 through 2011, EFH Corp. and EFIH held TCEH debtsecurities as follows (principal amounts):March 31, 2013 December 31, 2012TCEH Senior Notes:Held by EFH Corp. $ 284 $ 284Held by EFIH 79 79TCEH Term Loan Facilities:Held by EFH Corp. 19 19Total $ 382 $ 382Interest expense on the notes totaled $10 million for both the three months ended March 31, 2013 and 2012.See Notes 5 and 6 for guarantees and push-down of certain EFH Corp. debt and Note 10 for allocation of EFH Corp. pensionand OPEB costs to us.36 Table of Contents12. SUPPLEMENTARY FINANCIAL INFORMATIONOther IncomeOther income:Insurance/litigation settlementsAll otherTotal other incomeInterest Expense and Related ChargesThree Months Ended March31,2013 2012$ 2 $ 22 1$ 4 $ 3Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)Interest related to pushed down debtAccrued interest to be paid with additional toggle notes (Note 5)Unrealized mark-to-market net gain on interest rate swapsAmortization of interest rate swap losses at dedesignation of hedge accountingAmortization of fair value debt discounts resulting from purchase accountingAmortization of debt issuance, amendment and extension costs and discountsCapitalized interestTotal interest expense and related chargesThree Months Ended March 31,2013 2012$ 676 $ 6473 19-- 44(148) (110)2 32 365 46(7) (9)$ 593 $ 643Restricted CashAt March 31,2013 and December 31,2012, all restricted cash on the balance sheet related to TCEH's Letter of Credit Facility(see Note 5).Inventories by Major CategoryMaterials and suppliesFuel stockNatural gas in storageTotal inventoriesMarch 31, 2013 December 31, 2012$ 206 $ 201176 16826 24$ 408 $ 393InvestmentsMarch 31, 2013 December 31, 2012$ 701 $ 654Nuclear plant decommissioning trustAssets related to employee benefit plans, including employee savings programs, net ofdistributionsLandMiscellaneous otherTotal investments14088417$ 750 $ 71037 Table of ContentsNuclear Decommissioning Trust- Investments in a trust that will be used to fund the costs to decommission the ComanchePeak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as adelivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trustfund are offset by a corresponding change in a receivable/payable that will ultimately be settled through changes in Oncor's deliveryfees rates (see Note 11). A summary of investments in the fund follows:March 31, 2013Debt securities (b)Equity securities (c)TotalFair marketCost (a) Unrealized gain Unrealized loss value$ 252 $ 15 $ (1) $ 266247 198 (10) 435$ 499 $ 213 $ (11) $ 701December 31, 2012Fair marketCost (a) Unrealized gain Unrealized loss value$ 246 $ 16 $ (1) $ 261245 161 (13) 393$ 491 $ 177 $ (14) $ 654Debt securities (b)Equity securities (c)Total(a) Includes realized gains and losses on securities sold.(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio ratingof AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with municipal bonds. Thedebt securities had an average coupon rate of 4.29% and 4.38% at March 31, 2013 and December 31, 2012, respectively,and an average maturity of 10 and 6 years at March 31, 2013 and December 31, 2012, respectively.(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.Debt securities held at March 31, 2013 mature as follows: $76 million in one to five years, $64 million in five to ten yearsand $126 million after ten years.The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and lossesfrom such sales.Three Months Ended March 31,2013 2012$-- $-Realized gainsRealized lossesProceeds from sales of securitiesInvestments in securities$ 41 $$ (45) $10(14)Property, Plant and EquipmentAt March 31, 2013 and December 31, 2012, property, plant and equipment of $18.3 billion and $18.6 billion, respectively,is stated net of accumulated depreciation and amortization of $7.1 billion and $6.8 billion, respectively.Asset Retirement and Mining Reclamation ObligationsThese liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining,removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is noearnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through theregulatory process as part of Oncor's delivery fees.38 Table of ContentsThe following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrentliabilities and deferred credits in the balance sheet, for the three months ended March 31, 2013:Mining LandNuclear Plant Reclamation andDecommissioning Other Total$ 368 $ 168 $ 536Liability at December 31, 2012Additions:AccretionReductions:PaymentsLiability at March 31, 2013Less amounts due currentlyNoncurrent liability at March 31, 20136814-(25) (25)374 151 525-(76) (76)$ 374 $ 75 $ 449Other Noncurrent Liabilities and Deferred CreditsThe balance of other noncurrent liabilities and deferred credits consists of the following:Uncertain tax positions (including accrued interest)Asset retirement and mining reclamation obligationsUnfavorable purchase and sales contractsNuclear decommissioning cost over-recovery (Note 11)Retirement plan and other employee benefitsOtherTotal other noncurrent liabilities and deferred creditsMarch 31, 2013 December 31, 2012$ 448 $ 1,250449 452614 620326 28422283 9$ 1,862 $ 2,643The conclusion of all issues contested by EFH Corp. from the 1997 through 2002 IRS audit is expected to reduce the liabilityfor uncertain tax positions by approximately $85 million with an offsetting decrease in deferred tax assets that arose largely fromprevious payments of alternative minimum taxes. Approval from the Joint Committee on Taxation is expected to be received inthe second quarter 2013.The IRS audit for the years 2003 through 2006 was concluded in June 2011. The IRS proposed a significant number ofadjustments to the originally filed returns for such years. The adjustments relate to one significant accounting method issue andother less significant issues. In March 2013, EFH Corp. and the IRS agreed on terms to resolve the disputed adjustments. In thefirst quarter 2013, we adjusted the liability for uncertain tax positions to reflect the terms of the agreement, resulting in a netreduction of the liability for uncertain tax positions totaling $794 million. This reduction consisted of a $685 million reclassificationto a noncurrent affiliate tax sharing liability and a net adjustment of $109 million ($62 million after tax), largely representing areversal of accrued interest and reported as an increase in income tax benefit. In addition, in accordance with the provisions ofthe tax sharing agreement with EFH Corp., amounts previously recorded as accumulated deferred income taxes totaling $430million were reclassified to the affiliate tax sharing liability, the total amount of which is not expected to be settled within the nexttwelve months.Unfavorable Purchase andSales Contracts-The amortization of unfavorable purchase and sales contracts totaled $6 millionand $7 million for the three months ended March 31, 2013 and 2012, respectively. See Note 3 for intangible assets related tofavorable purchase and sales contracts.39 Table of ContentsThe estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:Year Amount20132014201520162017$ 26$$$$25252525Supplemental Cash Flow InformationCash payments (receipts) related to:Interest paid (a)Capitalized interestInterest paid (net of capitalized interest) (a)Noncash investing and financing activities:Effect of Parent's payment of interest, net of tax, on pushed down debtConstruction expenditures (b)Effect of push down of debt from parentDebt extension transactionsThree Months Ended March 31,2013 2012$ 546 $ 509(7) (9)$ 539 $ 500$ 18 $ 12$ 54 $ 84$ (420) $ -$ (340) $ -(a) Net of interest received on interest rate swaps.(b) Represents end-of-period accruals.40 Table of Contents13. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATIONAt March 31, 2013 TCEH and TCEH Finance, as Co-Issuers, had outstanding $5.237 billion aggregate principal amount of10.25% Senior Notes Due 2015, 10.25% Senior Notes due 2015 Series B and Toggle Notes (collectively, the TCEH Senior Notes)and $1.571 billion aggregate principal amount of 15% Senior Secured Second Lien Notes due 2021 and 15% Senior SecuredSecond Lien Notes due 2021 (Series B) (collectively, the TCEH Senior Secured Second Lien Notes). The TCEH Senior Notesand the TCEH Senior Secured Second Lien Notes are unconditionally guaranteed by EFCH and by each subsidiary (all 100%owned by TCEH) that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The guarantees issued bythe Guarantors are full and unconditional, joint and several guarantees of the TCEH Senior Notes and the TCEH Senior SecuredSecond Lien Notes. The guarantees of the TCEH Senior Notes rank equally with any senior unsecured indebtedness of theGuarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing thatindebtedness. The guarantees of the TCEH Senior Secured Second Lien Notes rank equally in right of payment with all seniorindebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the valueof the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of paymentto any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH SeniorSecured Facilities, the TCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extentof the value of the TCEH Collateral (see Note 5). All other subsidiaries of EFCH, either direct or indirect, do not guarantee theTCEH Senior Notes or TCEH Senior Secured Second Lien Notes (collectively the Non-Guarantors). The indentures governingthe TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes contain certain restrictions, subject to certain exceptions,on EFCH's ability to pay dividends or make investments. See Note 7.The following tables have been prepared in accordance with Regulation S-X Rule 3-10, "Financial Statements of Guarantorsand Issuers of Guaranteed Securities Registered or Being Registered" in order to present the condensed consolidating statementsof income and of cash flows of EFCH (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors for the three months endedMarch 31,2013 and 2012 and the condensed consolidating balance sheets at March 31,2013 and December 31,2012 of the Parent,Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method.The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5J, "Push Down Basis of Accounting Requiredin Certain Limited Circumstances," including the effects of the push down of $30 million and $62 million of the EFH Corp.10.875% Notes and Toggle Notes to the Parent at March 31, 2013 and December 31, 2012, respectively, $388 million of the EFHCorp. 9.75% Notes and 10% Notes to the Parent at December 31,2012, and the TCEH Senior Notes, TCEH Senior Secured Notes,TCEH Senior Secured Second Lien Notes and TCEH Senior Secured Facilities to the Other Guarantors at March 31, 2013 andDecember 31, 2012 (see Note 5 for further details of this debt, including the elimination of EFCH's guarantees of the EFH Corp.9.75% Notes and 10% Notes in January 2013). TCEH Finance's sole function is to be the co-issuer of the certain TCEH debtsecurities; therefore, it has no other independent assets, liabilities or operations.EFCH (parent entity) received no dividends/distributions from its consolidated subsidiaries for the three months endedMarch 31, 2013 and 2012.41 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCondensed Consolidating Statements of Income (Loss)Three Months Ended March 31, 2013(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ -$ -$ 1,260 $ 15 $ (15) $ 1,260Operating revenuesFuel, purchased power costsand delivery feesNet loss from commodityhedging and trading activitiesOperating costsDepreciation and amortizationSelling, general andadministrative expensesFranchise and revenue-basedtaxesOther incomeOther deductionsInterest incomeInterest expense and relatedchargesIncome (loss) before incometaxesIncome tax benefit (expense)Equity earnings (losses) ofsubsidiariesNet income (loss)Other comprehensive incomeComprehensive income (loss)(135)(13)(636)(62)(229)(344)(154)(636)(197)(229)(344)(158)(6)15(17)4(3)187(17)4(3)460(243)(7) (776) (618) (2) 810 (593)(7) (864)5 314(612)2607567(909)383(2) (194)(524) 26 --498 -(526) (524) (352) 5 871 (526)2 2 --(2) 2$ (524) $ (522 ) (352) $ 5 $ 869 $42 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCondensed Consolidating Statements of Income (Loss)Three Months Ended March 31, 2012(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ -$ -$ 1,222 $ 2 $ (2) $ 1,222Operating revenuesFuel, purchased power costsand delivery feesNet gain from commodityhedging and trading activitiesOperating costsDepreciation and amortizationSelling, general andadministrative expensesFranchise and revenue-basedtaxesOther incomeOther deductionsInterest incomeInterest expense and relatedchargesLoss before income taxesIncome tax benefitEquity earnings (losses) ofsubsidiariesNet lossOther comprehensive incomeComprehensive loss346(628)22(207)(330)(156)(628)368(207)(330)(155)(2)3(19)3(2)176(19)3(2)16(236)76(23) (794) (587) -761 (643)(23) (372) (506) -526 (375)8 98 196 -(180) 122(238) 36 --202 -(253) (238) (310) -548 (253)S3 ---3$ (253) $ (235) $ (310) -$ 548.43 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCondensed Consolidating Statements of Cash FlowsThree Months Ended March 31, 2013(millions of dollars)Cash provided by (used in)operating activitiesCash flows -financingactivities:Notes/advances due toaffiliatesRepayments/repurchases oflong-term debtNet short-term borrowingsunder accounts receivablesecuritization programContributions fromnoncontrolling interestsOther, netCash provided by (usedin) financing activitiesCash flows -investingactivities:Capital expendituresNuclear fuel purchasesNotes due from affiliatesPurchase of right to usecertain computer-relatedassets from parentProceeds from sales of assetsPurchases of environmentalallowances and creditsProceeds from sales ofnuclear decommissioningtrust fund securitiesInvestments in nucleardecommissioning trust fundsecuritiesCash provided by (usedin) investing activitiesNet change in cash and cashequivalentsCash and cash equivalents -beginning balanceCash and cash equivalents -ending balanceParent/ Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ (1) $ (910) $ 867 $ 30 $ -$ (14)2 1,379 --- (1,379) 2(1) (4) (11) ---(16)--- 7 -7--- -- 1 -- 1-(2) --(2)1 1,375 (13) 8 (1,379) (8)(130)(20)(681)(1)(131)(20)698-- 1,379(6)1(5)41(6)1(5)41-(45) --(45)-(845) (1) 1,379 533465937511-1,115 15 45 -1,175$ $ 1,580 $ 24 $ 82 $ -$ 1,68644 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCondensed Consolidating Statements of Cash FlowsThree Months Ended March 31, 2012(millions of dollars)Cash provided by (used in)operating activitiesCash flows -financingactivities:Notes due to affiliatesRepayments/repurchases oflong-term debtNet short-term borrowingsunder accounts receivablesecuritization programDecrease in other short-termborrowingsDecrease in income tax-related note payable to OncorContributions fromnoncontrolling interestsSale/leaseback of equipmentOther, netParent/ Other Non-Guarantor Issuer Guarantors guarantors Eliminations Consolidated$ (2) $ (31) $ 184 $ 13$ -$ 1643(i)880(17)(883)(18)(11)(11)(670)(670)(10)(10)221414___ __ ___ _ 1 --_ 1Cash provided by (usedin) financing activities 2 193 5 (9) (883) (692)Cash flows -investingactivities:Capital expenditures --(174) (3) -(177)Nuclear fuel purchases -(64) --(64)Notes/loans due fromaffiliatesChanges in restricted cashPurchases of environmentalallowances and creditsProceeds from sales ofnuclear decommissioningtrust fund securitiesInvestments in nucleardecommissioning trust fundsecuritiesOther, netCash provided by (usedin) investing activitiesNet change in cash and cashequivalentsCash and cash equivalents -beginning balanceCash and cash equivalents -ending balance421588392515(6)(6)1010(14)(14)-2 --2-(189) (3) 883 691162I16387 23 10 -120$ -$ 249 $ 23 $ 11 $ -$ 28345 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCondensed Consolidating Balance SheetsMarch 31, 2013(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations ConsolidatedASSETSCurrent assets:Cash and cash equivalentsAdvances to affiliatesTrade accounts receivable -netIncome taxes receivableInventoriesCommodity and other derivativecontractual assetsAccumulated deferred income taxesMargin deposits related to commoditypositionsOther current assetsTotal current assetsRestricted cashInvestmentsProperty, plant and equipment -netAdvances to affiliatesGoodwillIdentifiable intangible assets -netCommodity and other derivativecontractual assetsAccumulated deferred income taxesOther noncurrent assets, principallyunamortized amendment/issuance costsTotal assetsLIABILITIES AND EQUITYCurrent liabilities:Short-term borrowingsNotes/advances from affiliatesLong-term debt due currentlyTrade accounts payableTrade accounts and other payables toaffiliatesNotes payable to parentCommodity and other derivativecontractual liabilities$ -S 1,580 $24 $ 82 $ -$ 1,68625 -(25) -227 373 (44) 557--(86) -186408365408-8433-1,208(6)3-- -127 --127-5 79 --843 2,515 1,255 458 (161) 4,070-947 -(10,317) 23,409 787--18,211--9,486-4,952 ---1,7659135(13,138)(9,486)94775018,346-- 4,952-- 1,76541586993(872)424-953 961 8 (951) 971$ (10,314) $ 34,060 $ 32,474 $ 613 $ (24,608) $ 32,225$ -$ 2,0541 9,51011 602 582 --567S2,054 $1238189 $ (2,054) $-(9,511)2,14383389453(44)1411-- 144-- 83-- 97140446 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCondensed Consolidating Balance SheetsMarch 31, 2013(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations ConsolidatedMargin deposits related to commoditypositionsAccumulated deferred income taxesAccrued income taxes payable toparentAccrued taxes other than incomeAccrued interestOther current liabilitiesTotal current liabilitiesAccumulated deferred income taxesCommodity and other derivativecontractual liabilitiesNotes or other liabilities due affiliatesLong-term debt held by affiliatesLong-term debt, less amounts duecurrentlyAffiliate tax sharing liabilityOther noncurrent liabilities and deferredcreditsTotal liabilitiesEFCH shareholder's equityNoncontrolling interests in subsidiariesTotal equityTotal liabilities and equity4533448121-457(6) 45I8(86)44--44 --443 518 414 -(414) 521--218 --218100 13,170 3,842 145 (12,115) 5,14280 -2,896 -80 3,056-- 1,395126-- 1,407-- 6-- 38238294 29,589-(175)28,7151,290-(28,660) 29,738-- 1,1158 16 1,838 --1,862282 44,377 38,599 145 (40,695) 42,708(10,596) (10,317) (6,125) 355 16,087 (10,596)---113 -113(10,596) (10,317) (6,125) 468 16,087 (10,483)$ (10,314) $ 34,060 $ 32,474 $ 613 $ (24,608) $ 32,22547 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCondensed Consolidating Balance SheetsDecember 31, 2012(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations ConsolidatedASSETSCurrent assets:Cash and cash equivalentsAdvances to affiliatesTrade accounts receivable -netNotes receivable from parentIncome taxes receivableAccounts receivable from affiliatesInventoriesCommodity and other derivativecontractual assetsAccumulated deferred income taxesMargin deposits related to commoditypositionsOther current assetsTotal current assetsRestricted cashInvestmentsProperty, plant and equipment -netAdvances to affiliatesGoodwillIdentifiable intangible assets -netCommodity and other derivativecontractual assetsAccumulated deferred income taxesOther noncurrent assets, principallyunamortized amendment/issuance costsTotal assetsLIABILITIES AND EQUITYCurrent liabilities:Short-term borrowingsNotes/advances from affiliatesLong-term debt due currentlyTrade accounts payableTrade accounts and other payables toaffiliatesNotes payable to parent/affiliateCommodity and other derivativecontractual liabilities$-S 1,115 $26981536360410$ 45 $445(36)(97)1,17571069839395(410)(95)-- 393-1,1273336-1,463(6)3--71 --71--112 8 -1203 3,037 1,733 501 (644) 4,630-947 ---947(9,794) 23,382 747 9 (13,634) 710--18,422 134 -18,556--8,794-4,952 ---1,781-(8,794) --4,952-- 1,781575828115863 (831)4 781 806 3 (783) 811$ (9,787) $ 34,502 $ 32,294 $ 650 $ (24,686) $ 32,973$-$ 2,0548,83011 64-- 2$2,054 $ 82 $ (2,054) $--(8,830)2,1369638921387231128497(97)(95)3139818061089448 Table of ContentsENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCondensed Consolidating Balance SheetsDecember 31, 2012(millions of dollars)Parent Other Non-Guarantor Issuer Guarantors guarantors Eliminations ConsolidatedMargin deposits related to commoditypositionsAccumulated deferred income taxesAccrued income taxes payable toparentAccrued taxes other than incomeAccrued interestOther current liabilitiesTotal current liabilitiesAccumulated deferred income taxesCommodity and other derivativecontractual liabilitiesNotes or other liabilities due affiliatesLong-term debt held by affiliatesLong-term debt, less amounts duecurrentlyOther noncurrent liabilities and deferredcreditsTotal liabilitiesEFCH shareholder's equityNoncontrolling interests in subsidiariesTotal equityTotal liabilities and equity-- 596-- 3452(6)600492 433 -6 (410) 31--17 --1718 389 281 -(281) 4071 4 253 -(3) 255112 12,985 3,585 188 (11,776) 5,09479 -3,569 -111 3,7591,539382175-- 1,556-5-- 382-(28,428) 29,928515 29,355 28,48613 36 2,594 --2,643719 44,297 38,256 188 (40,093) 43,367(10,506) (9,795) (5,962) 350 15,407 (10,506)---112 -112(10,506) (9,795) (5,962) 462 15,407 (10,394)$ (9,787) $ 34,502 $ 32,294 $ 650 $ (24,686) $ 32,97349 Table of ContentsItem 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONSThe following discussion and analysis of our financial condition and results of operations for the three months ended March31, 2013 and 2012 should be read in conjunction with our condensed consolidated financial statements and the notes to thosestatements.All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwiseindicated.BusinessEFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. In April 2013, EFCH wasconverted from a Texas corporation to a Delaware limited liability company; the directors and officers and consolidated assets,businesses and operations are unchanged. We conduct our operations almost entirely through our wholly-owned subsidiary, TCEH.TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, includingelectricity generation, wholesale energy sales and purchases, commodity risk management and trading activities and retail electricitysales. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesalecustomers, are performed on an integrated basis; consequently, there are no reportable business segments.Sign ificant Activities and Events and Items Influencing Future PerformanceSee Note 1 to Financial Statements for discussion of TCEH liquidity and description of recent discussions with certaincreditors. See Note 12 to Financial Statements for discussion of an agreement with the IRS in 2013 to resolve disputed adjustmentsrelated to the IRS audit for the years 2003 through 2006 and related accounting effects, and see "Financial Condition -Liquidityand Capital Resources -Income Tax Matters" for discussion of a private letter ruling EFH Corp. received from the IRS in April2013 and the subsequent consummation of certain internal corporate transactions involving EFH Corp. and EFCH that resultedin the elimination of an excess loss account and a deferred intercompany gain.Natural Gas Price Hedging Program and Other Hedging Activities -Because wholesale electricity prices in ERCOThave generally moved with natural gas prices, TCEH has a natural gas price hedging program designed to mitigate the effect ofnatural gas price changes on future electricity revenues. Under the program, we have entered into market transactions involvingnatural gas-related financial instruments, and at March 31,2013, have effectively sold forward approximately 310 million MIvBtuof natural gas (equivalent to the natural gas exposure of approximately 36,000 GWh at an assumed 8.5 market heat rate) at weightedaverage annual hedge prices as shown in the table below. Volumes and hedge values associated with the natural gas price hedgingprogram are inclusive of offsetting purchases entered into to take into account new wholesale and retail electricity sales contractsand avoid over-hedging. This activity results in both commodity contract asset and liability balances pending the maturity andsettlement of the offsetting transactions.Taking together forward wholesale and retail electricity sales with the natural gas positions in the hedging program, we haveeffectively hedged an estimated 94% and 43% of the price exposure, on a natural gas equivalent basis, related to TCEH's expectedgeneration output for 2013 and 2014, respectively (assuming an 8.5 market heat rate). The natural gas positions were entered intowith the continuing expectation that wholesale electricity prices in ERCOT will generally move with prices of natural gas, whichwe expect to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOTmarket. If the relationship changes in the future, the cash flows targeted under the natural gas price hedging program may not beachieved.The company has entered into related put and call transactions (referred to as collars), primarily for 2014, that effectivelyhedge natural gas prices within a range. These transactions represented 49% of the positions in the natural gas price hedgingprogram at March 31, 2013, with the approximate weighted average strike prices under the collars being a floor of $7.80 perMMBtu and a ceiling of $11.75 per MMBtu.50 Table of ContentsThe following table summarizes the natural gas positions in the hedging program at March 31, 2013:Balance 2013Measure (a) 2014 TotalNatural gas hedge volumes (b) mm MMBtu -163 -146 -309Weighted average hedge price (c) $/MMBtu -6.89 -7.80 -Average market price (d) $/MMBtu -4.12 -4.23Realization of hedge gains (e) $ billions -$0.7 -$0.5 -$1.2(a) Balance of 2013 is from April 1, 2013 through December 31, 2013.(b) Where collars are reflected, the volumes are based on the notional position of the derivatives to represent protection againstdownward price movements. The notional volumes for collars are approximately 150 million MMBtu, which correspondsto a delta position of approximately 146 million MMBtu in 2014.(c) Weighted average hedge prices are based on prices of positions in the natural gas price hedging program (excluding offsettingpurchases to avoid over-hedging). Where collars are reflected, sales price represents the collar floor price.(d) Based on NYMEX Henry Hub prices.(e) Based on cumulative unrealized mark-to-market gain at March 31, 2013.Changes in the fair value of the instruments in the natural gas price hedging program are recorded as unrealized gains andlosses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continueto result in significant volatility in reported net income. Based on the size of the natural gas price hedging program at March 3 1,2013, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately$3 10 million in pretax unrealized mark-to-market gains or losses.The natural gas price hedging program has resulted in reported net gains (losses) as follows:Three Months Ended March 31,2013 2012Realized net gain $ 256 $ 513Unrealized net loss including reversals of previously recorded amounts related to positionssettled (366) (129)Total $ (110) $ 384The cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging program totaled$1.218 billion and $1.584 billion at March 31, 2013 and December 31, 2012, respectively. The decline was driven by settlementof maturing positions and increases in forward natural gas prices.Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains orlosses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in the future. If naturalgas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negativeeffect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices ofthe hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricityprices and will in this context be viewed as having resulted in an opportunity cost.51 Table of ContentsThe significant cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging programreflects the sustained decline in forward market natural gas prices as presented in the table below. Forward natural gas prices havegenerally trended downward over the past several years. While the natural gas price hedging program is designed to mitigate theeffect on earnings of low wholesale electricity prices, depressed forward natural gas prices are challenging to our liquidity andthe long-term profitability of our business. Specifically, low natural gas prices and their effect in ERCOT on wholesale electricityprices could have a material impact on our liquidity and TCEH's overall profitability for periods in which TCEH does not havesignificant hedge positions. See Note 1 to Financial Statements.DateDecember 31, 2008December 31, 2009December 31, 2010December 31, 2011*March 31, 2012June 30, 2012September 30, 2012December 31, 2012March 31, 2013Forward Market Prices for Calendar Year ($IMMBtu) (a)2013 (b) 2014 2015 2016$ 7.15 $ 7.15 $ 7.21 $ 7.30$ 6.67 $ 6.84 $ 7.05 $ 7.24$ 5.33 $ 5.49 $ 5.64 $ 5.79S 3.94 $ 4.34 $ 4.60 $ 4.85$ 3.47 $ 3.96 $ 4.26 $ 4.51$ 3.58 $ 3.95 $ 4.13 $ 4.29$ 3.84 $ 4.18 $ 4.37 $ 4.55$ 3.54 $ 4.03 $ 4.23 $ 4.42S 4.12 $ 4.23 $ 4.30 $ 4.38(a) Based on NYMEX Henry Hub prices.(b) For March 31, 2013, natural gas prices for 2013 represent the average of forward prices for April through December.The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas andcertain other commodity prices and market heat rates on realized pretax earnings for the periods presented. The estimates relatedto price sensitivity are based on TCEH's unhedged position and forward prices at March 31, 2013, which for natural gas reflectsestimates of electricity generation less amounts hedged through the natural gas price hedging program and amounts under existingwholesale and retail sales contracts. On a rolling basis, generally twelve-months, the substantial majority of retail sales undermonth-to-month arrangements are deemed to be under contract.$1.00/MMBtu change in natural gas price (b)0. 1 /MMBtu/MWh change in market heat rate (c)$ 1.00/gallon change in diesel fuel priceBalance 2013 (a) 2014 2015$ -20 $ -260 S -475$ -4 $ -30 $ -35$ -6 $-40 $-50(a) Balance of 2013 is from May 1, 2013 through December 31, 2013.(b) Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally beingon the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gasposition is assumed to be generated). Excludes the impact of economic backdown.(c) Based on Houston Ship Channel natural gas prices at March 31, 2013.TCEH Interest Rate Swap Transactions -TCEH employs interest rate swaps to hedge exposure to its variable rate debt.As reflected in the table below, as of March 31,2013, TCEH has entered into the following series of interest rate swap transactionsthat effectively fix the interest rates at between 5.5% and 9.3%.Fixed Rates5.5% -9.3%6.8% -9.0%Expiration DatesSeptember 2013 through October 2014October 2015 through October 2017Notional Amount$18.265 billion (a)$12.600 billion (b)(a) Swaps related to an aggregate $600 million principal amount of debt expired in 2013. Per the terms of the transactions, thenotional amount of swaps entered into in 2011 grew by $405 million in 2013, substantially offsetting the expired swaps.(b) These swaps are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes$3 billion that expires in October 2015 with the remainder expiring in October 2017.We may enter into additional interest rate hedges from time to time.52 Table of ContentsTCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achievedthrough the interest rate swaps. Basis swaps in effect at March 31, 2013 totaled $11.967 billion notional amount. The basis swapsrelate to debt outstanding through 2014.The interest rate swaps have resulted in net losses reported in interest expense and related charges as follows:Three Months Ended March 31,2013 2012Realized net loss $ (151) $ (168)Unrealized net gain 148 110Total $ (3) $ (58)The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.917 billion and$2.065 billion at March 31, 2013 and December 31, 2012, respectively, of which $62 million and $65 million (both pretax),respectively, were reported in accumulated other comprehensive income. These fair values can change materially as marketconditions change, which could result in significant volatility in reported net income. For example, at March 31, 2013, a onepercent change in interest rates would result in an increase or decrease of approximately $625 million in our cumulative unrealizedmark-to-market net liability.First-Lien Security for Natural Gas Hedging Program and Interest Rate Swaps -Approximately 85% of the positionsin the natural gas price hedging program and all of the TCEH interest rate swaps are secured by a first-lien interest in the assetsof TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes. Certain entitiesare counterparties to both our natural gas hedge program positions and our interest rate swaps and have entered into masteragreements that provide for netting and setoff of amounts related to these positions. At March 31, 2013, our net liability positionsrelated to these counterparties together with liability positions related to entities that are counterparties to only our interest rateswaps totaled approximately $1.3 billion. This amount is not expected to change materially through 2013 assuming market valuesdo not change significantly.Liability Management Program -At March 31,2013, we had $30.4 billion principal amount of long-term debt outstanding,including $30 million pushed down from EFH Corp. We and EFH Corp. have implemented a liability management programdesigned to reduce debt, capture debt discount and extend debt maturities through debt exchanges, repurchases and extensions.Amendments to the TCEH Senior Secured Facilities completed in April 2011 and January 2013 resulted in the extension of$16.4 billion in loan maturities under the TCEH Term Loan Facilities and the TCEH Letter of Credit Facility from October 2014to October 2017 and $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October2016.Other liability management activities since 2009 related to TCEH debt include debt exchange, issuance and repurchaseactivities as follows (all transactions occurred prior to 2012):Debt Debt Issued/Security (except where noted, debt amounts are principal amounts) Acquired Cash PaidTCEH 10.25% Notes due 2015 $ 1,513 $TCEH Toggle Notes due 2016 758TCEH Senior Secured Facilities due 2013 and 2014 1,604 -TCEH 15% Notes due 2021 -1,221TCEH 11.5% Notes due 2020 (a) 1,604Cash paid, including use of proceeds from debt issuances in 2010 (b) -- 343Total $ 3,875 $ 3,168(a) Excludes from the $1.750 billion principal amount $12 million in debt discount and $134 million in proceeds used fortransaction costs related to the issuance of these notes and the amendment and extension of the TCEH Senior SecuredFacilities. All other proceeds were used to repay borrowings under the TCEH Senior Secured Facilities, and the remainingtransaction costs were funded with cash on hand.(b) Includes $343 million of the proceeds from the October 2010 issuance of $350 million principal amount of TCEH 15%Senior Secured Second Lien Notes due 2021 that were used to repurchase debt, including $53 million used to repurchasedebt held by EFH Corp.53 Table of ContentsSince inception, TCEH's transactions in the liability management program resulted in the capture of approximately $700million of debt discount and the extension of approximately $19.6 billion of debt maturities to 2017-202 1.As the result of EFH Corp. and EFIH liability management transactions in December 2012 and early 2013, substantially allEFH Corp. debt guaranteed by EFCH was cancelled or amended to remove EFCH's guarantee, such that EFCH now guaranteesonly $60 million principal amount of EFH Corp. debt. See Note 5 to Financial Statements for discussion of these and other debt-related transactions and Note 1 to Financial Statements regarding "Liquidity Considerations" and "Discussions with Creditors."EFH Corp., EFCH and TCEH continue to consider and evaluate possible transactions and initiatives to address their highlyleveraged balance sheets and significant cash interest requirements and will likely from time to time enter into discussions withtheir lenders and bondholders with respect to such transactions and initiatives. These transactions and initiatives may include,among others, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equityexchanges or conversions, including exchanges or conversions of debt of EFCH and TCEH into equity of EFH Corp., EFCH,TCEH and/or any of their subsidiaries.In evaluating whether to undertake any liability management transaction, we will take into account liquidity requirements,prospects for future access to capital, contractual restrictions, tax consequences, the market price and maturity dates of ouroutstanding debt, potential transaction costs and other factors. Any liability management transaction, including any refinancingor extension, may occur on a stand-alone basis or in connection with, or immediately following, other liability managementtransactions.Recent EPA Actions -See Note 6 for discussion of the CSAPR and other EPA actions as well as related litigation.Mercury andAir Toxics Standard- In December 2011, the EPA finalized a rule called the Mercury and Air Toxics Standard(MATS). MATS regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases. Anyadditional control equipment retrofits on our lignite/coal-fueled generation units required to comply with MATS as finalized wouldneed to be installed within three to four years from the April 2012 effective date of the rule. In April 2012, we filed a petition forreview of MATS in the D.C. Circuit Court. Certain states and industry participants have also filed petitions for review in the D.C.Circuit Court. We cannot predict the timing or outcome of the D.C. Circuit Court's review of these petitions. In November 2012,the EPA proposed revised standards for new coal-fired generation units and other minor changes to MATS, including changes tothe work practice standards affecting all units. In March 2013, the EPA finalized the revised standards for new coal-fired unitsand certain other minor changes but did not address the work practice standards. The EPA is expected to address these standardsin a later rulemaking. We cannot predict the outcome of this rulemaking.Regional Haze -SO2 and NOx reductions required under the proposed regional haze/visibility rule (or so-called BARTrule) only apply to units built between 1962 and 1977. The reductions are required either on a unit-by-unit basis or by stateparticipation in an EPA-approved regional trading program such as the CAIR. In February 2009, the TCEQ submitted a StateImplementation Plan (SIP) concerning regional haze to the EPA, which we believe would not have a material impact on ourgeneration facilities. In December 2011, the EPA proposed a limited disapproval of the SIP due to its reliance on the CAIR anda Federal Implementation Plan for Texas providing that the inclusion in the CSAPR programs meets the regional haze requirementsfor SO2 and NOx reductions. In June 2012, the EPA finalized the limited disapproval of the Texas regional haze SIP, but did notfinalize a Federal Implementation Plan forTexas. We cannot predict whether or when the EPAwill finalize a Federal ImplementationPlan for Texas regarding regional haze or its impact on our results of operations, liquidity or financial condition. In August 2012,we filed a petition for review in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the EPA's limiteddisapproval of the Texas regional haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court'sdecision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and otherstates and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance ofFederal ImplementationPlans regarding regional haze. These cases were held in abeyance pending completion of the CSAPR rehearing proceedingdescribed in Note 6 to Financial Statements. We cannot predict when or how the Fifth Circuit Court or the D.C. Circuit Courtwill rule on these petitions.54 Table of ContentsFinancial Services Reform Legislation -In July 2010, the US Congress enacted financial reform legislation known as theDodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act). The primary purposes of the FinancialReform Act are, among other things: to address systemic risk in the financial system; to establish a Bureau of Consumer FinancialProtection with broad powers to enforce consumer protection laws and promulgate rules against unfair, deceptive or abusivepractices; to enhance regulation of the derivatives markets, including the requirement for central clearing of over-the-counterderivative instruments and additional capital and margin requirements for certain derivative market participants and to implementa number of new corporate governance requirements for companies with listed or, in some cases, publicly-traded securities. Whilethe legislation is broad and detailed, a few key rulemaking decisions remain to be made by federal governmental agencies to fullyimplement the Financial Reform Act.Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives (Swaps) market.The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we useto hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However,under the end-user clearing exemption, entities are exempt from these clearing requirements if they (i) are not "Swap Dealers" or"Major Swap Participants" and (ii) use Swaps to hedge or mitigate commercial risk. Existing swaps are grandfathered from theclearing requirements. The legislation mandates significant compliance requirements for any entity that is determined to be aSwap Dealer or Major Swap Participant and additional reporting and recordkeeping requirements for all entities that participatein the derivative markets.In May 2012, the CFTC published its final rule defining the terms Swap Dealer and Major Swap Participant. Additionally,in July 2012, the CFTC approved the final rules defining the term Swap and the end-user clearing exemption. The definition ofthe term Swap and the Swap Dealer/Major Swap Participant rule became effective in October 2012. Accordingly, we are requiredto assess our activity to determine if we will be required to register as a Swap Dealer or Major Swap Participant. Based on ourassessment, we are not a Swap Dealer or Major Swap Participant.The reporting requirements for entities that are not Swap Dealers or Major Swap Participants became effective in April2013. However, in April 2013, the US Commodity Futures Trading Commission (CFTC) issued a no action letter that precludedany enforcement action on the reporting of Swaps for entities that are not Swap Dealers or Major Swap Participants until August2013. We are prepared to meet the reporting requirement.In September 2012, the District Court for the District of Columbia issued an order that vacated and remanded to the CFTCits Position Limit Rule (PLR), which would have been effective in October 2012. The PLR provided for specific position limitsrelated to 28 Core Referenced Futures Contracts, including the NYMEX Henry Hub Natural Gas Futures Contract, the NYMEXLight Sweet Crude Oil Futures Contract and the NYMEX New York Harbor No. 2 Heating Oil Futures Contract. If the PLR hadbeen approved by the court, we would have been required to comply with the portion of the PLR applicable to the contracts notedabove, which would result in increased monitoring and reporting requirements. We cannot predict when, or in what form, theCFTC will change the PLR.The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateralrequirements are unclear as to whether an end-user or its counterparty (e.g., swap dealer) is required to post cash collateral, thereis a risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. The final rulefor margin requirements has not been issued. However, the legislative history of the Financial Reform Act suggests that it wasnot Congress' intent to require end-users to post cash collateral with respect to swaps. If we were required to post cash collateralon our swap transactions with swap dealers, our liquidity would likely be materially impacted, and our ability to enter into OTCderivatives to hedge our commodity and interest rate risks would be significantly limited.Sunset Review -Sunset review is the regular assessment of the continuing need for a state agency to exist, and is groundedin the premise that an agency will be abolished unless legislation is passed to continue its functions. On a specified time schedule,the Texas Sunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agencyto the Texas Legislature, which action may include modifying or even abolishing the agency. The PUCT and the RRC are subjectto review by the Sunset Commission in 2013. In 2011, the Texas Legislature extended the authority of the RRC and the PUCTuntil 2013. In 2013, the RRC will undergo a full sunset review, and the PUCT will undergo a limited sunset review. We cannotpredict the outcome of the sunset review process.Summary -We cannot predict future regulatory or legislative actions or any changes in economic and securities marketconditions. Such actions or changes could significantly affect our results of operations, liquidity or financial condition.55 Table of ContentsRESULTS OF OPERATIONSSales Volume and Customer Count DataThree Months Ended March 31,2013 2012 % ChangeSales volumes:Retail electricity sales volumes -(GWh):ResidentialSmall business (a)Large business and other customersTotal retail electricityWholesale electricity sales volumes (b)Total sales volumes4,605 4,6601,190 1,3382,318 2,4508,113 8,4489,069 8,81317,182 17,261(1.2)%(11.1)%(5.4)%(4.0)%2.9 %(0.5)%2.7 %Average volume (kilowatt-hours) per residential customer (c)Weather (North Texas average) -percent of normal (d):Heating degree daysCustomer counts:Retail electricity customers (end of period and in thousands) (e):ResidentialSmall business (a)Large business and other customersTotal retail electricity customers2,9642,88793.5% 77.5%1,546 1,603176 17918 171,740 1,79920.6 %(3.6)%(1.7)%5.9 %(3.3)%(a) Customers with demand of less than 1 MW annually.(b) Includes net amounts related to sales and purchases of balancing energy in the "real-time market."(c) Calculated using average number of customers for the period.(d) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data fromreporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department ofCommerce). Normal is defined as the average over the 10-year period from 2000 to 2010.(e) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number ofmeters does not reflect the number of individual customers.56 Table of ContentsRevenue and Commodity Hedging and Trading ActivitiesOperating revenues:Retail electricity revenues:ResidentialSmall business (a)Large business and other customersTotal retail electricity revenuesWholesale electricity revenues (b) (c)Amortization of intangibles (d)Other operating revenuesTotal operating revenuesThree Months Ended March 31,2013 2012 % Change$ 597 $ 578 3.3 %157 175 (10.3)%161 174 (7.5)%915 927 (1.3)%275 230 19.6 %5 4 25.0%65 61 6.6%$ 1,260 $ 1,222 3.1 %Net gain (loss) from commodity hedging and trading activities:Realized net gains on settled positionsUnrealized net lossesTotal$ 296 $ 524(493) (156)$ (197) $ 368(43.5)%(a) Customers with demand of less than 1 MW annually.(b) Upon settlement of physical derivative commodity contracts, such as certain electricity sales and purchase agreements andcoal purchase contracts, that we mark-to-market in net income, wholesale electricity revenues and fuel and purchased powercosts are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result,these line item amounts include a noncash component, which we deem "unrealized." (The offsetting differences betweencontract and market prices are reported in net gain (loss) from commodity hedging and trading activities.) These amountsare as follows:Reported in revenuesReported in fuel and purchased power costsNet gainThree Months Ended March 31,2013 2012$ (1) $ (2)7 6$ 6 $ 4(c) Includes net amounts related to sales and purchases of balancing energy in the "real-time market."(d) Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting frompurchase accounting.57 Table of ContentsProduction, Purchased Power and Delivery Cost DataThree Months Ended March 31,2013 2012 % ChangeFuel, purchased power costs and delivery fees ($ millions):Fuel for nuclear facilitiesFuel for lignite/coal facilitiesTotal nuclear and lignite/coal facilitiesFuel for natural gas facilities and purchased power costs (a)Amortization of intangibles (b)Other costsFuel and purchased power costsDelivery feesTotalFuel and purchased power costs (which excludes generation facilitiesoperating costs) per MWh:Nuclear facilitiesLignite/coal facilities (c)Natural gas facilities and purchased power (d)44 $ 47194 174238 22153 7110 1249 45350 349286 279636 $ 628$$$8.4820.7846.01$$$8.7720.3543.25(6.4)%11.5 %7.7 %(25.4)%(16.7)%8.9 %0.3 %2.5 %1.3 %(3.3)%2.1 %6.4 %6.5 %(2.0)%5.5 %3.0 %(61.3)%(43.9)%(0.5)%(0.9)%6.7 %4.2 %Delivery fees per MWhProduction and purchased power volumes (GWh):Nuclear facilitiesLignite/coal facilities (e)Total nuclear and lignite/coal-facilitiesNatural gas-facilitiesPurchased power (f)Total energy supply volumes$ 35.08 $ 32.935,231 5,33811,286 10,69316,517 16,03155 142610 1,08817,182 17,261Capacity factors:Nuclear facilitiesLignite/coal facilities (e)Total105.3%65.2%74.2%106.3%61.1%71.2%(a) See note (b) to the "Revenue and Commodity Hedging and Trading Activities" table on previous page.(b) Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contractsand power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.(c) Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expenseline item, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (b) to the "Revenue andCommodity Hedging and Trading Activities" table on previous page.(d) Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (c) immediatelyabove.(e) Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal-fueled units totaling4,350 GWh and 2,920 GWh for the three months ended March 31, 2013 and 2012, respectively.(f) Includes amounts related to line loss and power imbalances.58 Table of ContentsFinancial Results -Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012Operating revenues increased $38 million, or 3%, to $1.260 billion in 2013.Retail electricity revenues decreased $12 million, or 1%, to $915 million reflecting a $37 million decline in sales volumespartially offset by $25 million in higher average prices. Sales volumes fell 4% driven by declines in business markets. Businessmarket volumes were lower reflecting changes in customer mix and lower small business customer counts driven by competitiveactivity. A 4% decline in residential customer counts was substantially offset by higher average usage driven by colder winterweather. Overall average retail pricing increased 3% driven by residential markets and due in part to higher delivery fees incurred.Wholesale electricity revenues increased $45 million, or 20%, to $275 million in 2013 driven by higher average prices,which reflected higher natural gas prices, and a 3% increase in sales volumes reflecting higher demand driven by the effects ofcolder winter weather and higher available generation due to lower unplanned outages.Fuel, purchased power costs and delivery fees increased $8 million, or 1%, to $636 million in 2013. Lignite/coal fuel costsincreased $20 million reflecting higher consumption, increased western coal in fuel blend and higher average lignite costs, partiallyoffset by lower western coal prices and transportation costs. Delivery fees increased $7 million reflecting higher rates, partiallyoffset by lower retail volumes. Purchased power costs decreased $13 million driven by lower purchased power volumes. Naturalgas fuel costs decreased $5 million reflecting a decrease in generation volumes.A 6% increase in lignite/coal-fueled production was driven by fewer unplanned outage days in 2013, while nuclear-fueledproduction decreased 2% reflecting a refueling outage in 2013.Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled$197 million in net losses and $368 million in net gains for the three months ended March 31, 2013 and 2012, respectively, andis largely reflective of the natural gas price hedging program discussed above under "Significant Activities and Events and ItemsInfluencing Future Performance -Natural Gas Price Hedging Program and Other Hedging Activities":Three Months Ended March 31, 2013Net Realized Net UnrealizedGains Losses TotalHedging positions $ 295 $ (481) $ (186)Trading positions 1 (12) (11)Total $ 296 $ (493) $ (197)Three Months Ended March 31, 2012Net Realized Net UnrealizedGains Gains (Losses) TotalHedging positions $ 514 $ (181) $ 333Trading positions 10 25 35Total $ 524 $ (156) $ 368While unrealized losses were recorded in both 2013 and 2012 to reverse previously recorded gains on positions settled inthe periods, the effect of increases in forward natural gas prices in 2013 compared to decreases in 2012 resulted in the increase inunrealized losses in 2013.Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues andpurchased power costs, as required by accounting rules, totaled $6 million and $4 million in net gains in 2013 and 2012, respectively(as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).Operating costs increased $22 million, or 11%, to $229 million in 2013. The increase reflected $13 million in higher costsprimarily for timing and scope of maintenance performed during outages at lignite units and $11 million in higher costs primarilyassociated with a planned spring nuclear unit refueling outage; there was no nuclear refueling outage during spring 2012.Depreciation and amortization increased $14 million, or 4%, to $344 million in 2013. The increase primarily reflected theaccelerated depreciation associated with retirements of generation assets during planned outages at three lignite units.59 Table of ContentsSG&A expenses increased $3 million, or 2%, to $158 million in 2013. The increase reflected $15 million in higher legaland consulting services costs primarily associated with our liability management program, partially offset by $9 million in loweremployee compensation-related costs and $3 million in lower retail marketing expenses.Interest income decreased $12 million, or 75%, to $4 million in 2013. The decrease was driven by EFH Corp.'s repaymentof the TCEH Demand Notes. See Note 11 to Financial Statements.Interest expense and related charges decreased $50 million, or 8%, to $593 million in 2013. The decrease was largely drivenby higher unrealized mark-to-market net gains on interest rate swaps and lower interest expense on push-down debt as a result ofDecember 2012 and January 2013 EFIH debt exchange transactions discussed in Note 5 to Financial Statements, partially offsetby higher amortization of debt issuance costs and discounts.Income tax benefit totaled $383 million and $122 million on pretax losses in 2013 and 2012, respectively. The effectiverate was 42.1% in 2013 and 32.5% in 2012, respectively. The increase in the effective rate reflected favorable resolution of acertain income tax position, as discussed in Note 12 to Financial Statements, including a $62 million net adjustment largely relatedto a reversal of accrued interest.After-tax loss increased $273 million to $526 million in 2013 driven by lower results from commodity hedging activities in2013, partially offset by the reversal of interest accrued on uncertain tax positions.Energy-Related Commodity Contracts and Mark-to-Market ActivitiesThe table below summarizes the changes in commodity contract assets and liabilities for the three months ended March 31,2013 and 2012. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $487 millionand $152 million in unrealized net losses in 2013 and 2012, respectively, arising from mark-to-market accounting for positionsin the commodity contract portfolio. The portfolio consists primarily of economic hedges but also includes trading positions.Three Months Ended March 31,2013 2012Commodity contract net asset at beginning of period S 1,664 $ 3,190Settlements of positions (a) (287) (510)Changes in fair value of positions in the portfolio (b) (200) 358Other activity (c) (6) (1)Commodity contract net asset at end of period $ 1,171 $ 3,037(a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and lossesrecognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amountsrelated to positions entered into and settled in the same month.(b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in forward natural gas prices on positionsin the natural gas price hedging program (see discussion above under "Significant Activities and Events and Items InfluencingFuture Performance -Natural Gas Price Hedging Program and Other Hedging Activities"), as well as net losses in 2013 andnet gains in 2012 related to other hedging positions. Excludes changes in fair value in the month the position settled as wellas amounts related to positions entered into and settled in the same month.(c) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt orpayment of cash or other consideration, generally related to options purchased/sold.60 Table of ContentsMaturity Table -The following table presents the net commodity contract asset arising from recognition of fair values atMarch 31, 2013, scheduled by the source of fair value and contractual settlement dates of the underlying positions.Source of fair valuePrices actively quotedPrices provided by other external sourcesPrices based on modelsTotalPercentage of total fair valueMaturity dates of unrealized commodity contractnet asset at March 31, 2013Less than1 year 1-3 years Total(85) $ (1) $ (86)785 413 1,19860 (1) 59760 $ 411 $ 1,17165% 35% 100%The "prices actively quoted" category reflects only exchange-traded contracts for which active quotes are readily available.The "prices provided by other external sources" category represents forward commodity positions valued using prices for whichover-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT's North Hub thatare deemed active markets extend through 2014 and over-the-counter quotes for natural gas generally extend through 2016,depending upon delivery point. The "prices based on models" category contains the value of all non-exchange-traded optionsvalued using option pricing models. In addition, this category contains other contractual arrangements that may have both forwardand option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certainmarket based inputs. See Note 8 to Financial Statements for fair value disclosures and discussion of fair value measurements.61 Table of ContentsFINANCIAL CONDITIONLiquidity and Capital ResourcesCash Flows -Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012-- Cash used inoperating activities totaled $14 million in 2013 compared to cash provided by operating activities of $164 million in 2012. Thechange of $178 million reflected net changes in margin deposits totaling $211 million. The change in margin deposits largelyrelates to the natural gas price hedging program; in 2013 margin deposits were returned to counterparties due to settlements ofmaturing positions and increases in forward natural gas prices, while in 2012 more margin deposits were received due to decreasesin forward natural gas prices than were returned due to settlement of positions. The change in cash flows also reflected an increaseof $39 million in interest payments and cash settlements with EFH Corp. of $50 million related to pension plan actions in 2012(see Note 10 to Financial Statements), offset by a favorable change of approximately $125 million in working capital reflectingtiming of accounts payable and accrued expense payments.Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statementof income by $43 million and $46 million for the three months ended March 31, 2013 and 2012, respectively. The differencerepresented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice,and amortization of intangible net assets arising from purchase accounting that is reported in various other income statement lineitems including operating revenues and fuel and purchased power costs and delivery fees.Cash used in financing activities totaled $8 million and $692 million in 2013 and 2012, respectively. Activity in 2012reflected repayments of borrowings under the TCEH Revolving Credit Facility.See Note 5 to Financial Statements for further detail of short-term borrowings and long-term debt.Cash provided by investing activities totaled $533 million and $691 million in 2013 and 2012, respectively. Amountsprovided in 2013 and 2012 reflect EFH Corp. repayments of TCEH Demand Notes, which totaled $698 million and $950 million,respectively, (see Note 11 to Financial Statements). Capital expenditures (excluding nuclear fuel purchases) decreased $46 millionto $131 million in 2013 reflecting decreased environmental-related spending, partially offset by increased spending on minedevelopment and lignite maintenance projects. Nuclear fuel purchases decreased $44 million to $20 million due to timing ofrefueling cycles.Debt Financing Activity -Activities related to short-term borrowings and long-term debt during the three months endedMarch 31, 2013 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related tocapital leases and exclude amounts related to debt discount, financing and reacquisition expenses):RepaymentsandBorrowings RepurchasesTCEH (a) $ 340 $ (15)EFCH -(1)EFH Corp. (pushed down to EFCH) (b) -420Total long-term 340 404Total short-term -TCEH (c) 7 -Total $ 347 $ 404(a) Borrowings represent noncash principal increases of TCEH Term Loan Facilities for fees in consideration of the extensionof $645 million of commitments under the TCEH Revolving Credit Facility. Repayments represent $14 million of paymentsof principal at scheduled maturity dates and $2 million of payments of capital lease liabilities.(b) Repurchases represent acquisitions by EFIH in debt exchanges in January 2013 as discussed in Note 5 to Financial Statements.(c) Short-term amount represents net borrowings under the accounts receivable securitization program (see Note 4 to FinancialStatements).See Note 5 to Financial Statements for further detail of long-term debt and other financing arrangements.62 Table of ContentsAvailable Liquidity -The following table summarizes changes in available liquidity for the three months ended March 31,2013.Available LiquidityMarch 31, 2013 December 31, 2012 ChangeCash and cash equivalents $ 1,686 $ 1,175 $ 511TCEH Letter of Credit Facility 212 183 29Total liquidity $ 1,898 $ 1,358 $ 540Available liquidity increased $540 million since December 31, 2012 reflecting EFH Corp.'s repayment of its borrowingsfrom TCEH under the TCEH Demand Notes, which totaled $698 million at December 31, 2012, partially offset by use of cash of$165 million for the three months ended March 31, 2013 reflecting cash used for capital expenditures, including nuclear fuelpurchases, and cash used in operating activities. See discussion of cash flows above.Debt Capacity -We believe that TCEH is permitted under its applicable debt agreements to issue additional senior secureddebt (in each case, subject to certain exceptions and conditions set forth in its applicable debt documents) as follows:" approximately $2.3 billion of additional aggregate principal amount of debt secured by substantially all of the assets ofTCEH and certain of its subsidiaries (of which $410 million can be on a first-priority basis and the remainder on a second-priority basis) and" an unlimited amount of additional first-priority debt in order to refinance the first-priority debt outstanding under theTCEH Senior Secured Facilities.These amounts are estimates based on our current interpretation of the covenants set forth in our debt agreements and donot take into account exceptions in the debt agreements that may allow for the incurrence of additional secured debt, including,but not limited to, acquisition debt, refinancing debt, capital leases and hedging obligations. Moreover, such amounts could changefrom time to time as a result of, among other things, the termination of any debt agreement (or specific terms therein) or amendmentsto the debt agreements that result from negotiations with new or existing lenders. In addition, covenants included in agreementsgoverning additional future debt may impose greater restrictions on our incurrence of secured or unsecured debt. Consequently,the actual amount of senior secured or unsecured debt that we are permitted to incur under our debt agreements could be materiallydifferent than the amounts provided above.Liquidity Effects of Commodity Hedging and Trading Activities -Commodity hedging and trading transactions typicallyrequire a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or tradinginstrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other formsof credit support to satisfy such collateral posting obligations. At March 31, 2013, approximately 85% of the natural gas pricehedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH SeniorSecured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral postingrequirements for those hedging transactions. See Note 5 to Financial Statements for more information about the TCEH SeniorSecured Facilities.Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take intoaccount the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin postedto take into account changes in the value of the underlying commodity). The amount of initial margin required is generally definedby exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factorsincluding market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other formsas negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and othercorporate purposes, including reducing short-term borrowings under credit facilities, or is required to be deposited in a separateaccount and restricted from being used for working capital and other corporate purposes. At March 31, 2013, all cash collateralheld was unrestricted. With respect to over-the-counter transactions, counterparties generally have the right to substitute lettersof credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterpartiesthereby reducing liquidity in the event that it was not restricted.With the natural gas price hedging program, increases in natural gas prices generally result in increased cash collateral andletter of credit postings to counterparties. At March 31, 2013, approximately 50 million MMBtu of positions related to the naturalgas price hedging program were not directly secured on an asset-lien basis and thus are subject to cash collateral postingrequirements.63 Table of ContentsAt March 31, 2013, TCEH received or posted cash and letters of credit for commodity hedging and trading activities asfollows:* $ 123 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), ascompared to $69 million posted at December 31, 2012;* $453 million in cash has been received from counterparties, net of $3 million in cash posted, for over-the-counter andother non-exchange cleared transactions, as compared to $598 million received, net of $2 million in cash posted, atDecember 31, 2012;$ $330 million in letters of credit have been posted with counterparties, as compared to $376 million posted at December 31,2012, and$ $3 million in letters of credit have been received from counterparties, as compared to $22 million received at December 3 1,2012.Income Tax Matters -EFH Corp. files a US federal income tax return that includes the results of EFCH and TCEH. EFHCorp. is a corporate member of the EFH Corp. consolidated group, while each of EFCH and TCEH is classified as a disregardedentity for US federal income tax purposes. Prior to the restructuring transaction in April 2013 discussed below, EFCH was acorporate member of the group. Pursuant to applicable US Treasury regulations and published guidance of the US Internal RevenueService, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.EFH Corp. and its subsidiaries (including EFCH and TCEH) are bound by a Federal and State Income Tax AllocationAgreement, which provides, among other things, that any corporate member or disregarded entity in the group is required to makepayments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it fileda separate corporate tax return.An excess loss account (ELA) and a deferred intercompany gain (DIG) were reflected in the tax basis of the EFCH stockheld by EFH Corp. The difference between EFH Corp.'s tax basis in the stock of EFCH and the amount of the stock investmentfor financial reporting purposes represented an outside basis difference. Because EFH Corp. had tax strategies available to it thatit believed would avoid triggering income tax payments upon a transaction involving its investment in EFCH, EFH Corp. did notrecord deferred income tax liabilities with respect to this outside basis difference. The ELA, totaling approximately $19 billion,was created in connection with financing transactions related to the Merger. The DIG, totaling approximately $4 billion, wascreated as a result of an internal corporate reorganization prior to the Merger. The financing transactions and internal corporatereorganization that created the ELA and DIG involved TCEH and its assets.In April 2013, EFH Corp. received a private letter ruling from the IRS in which the IRS ruled that upon the consummationof certain internal corporate transactions (Transactions) involving EFH Corp. and EFCH, the ELA and the DIG would be eliminatedwithout causing the recognition of tax gain or loss. On April 15, 2013, EFH Corp. and EFCH completed the Transactions, resultingin the elimination of the ELA and the DIG.In connection with the Transactions, (i) EFH Corp. contributed all of the EFCH stock to a newly formed wholly-ownedsubsidiary, EFH2 Corp. (EFI-I2) (a Texas corporation), (ii) EFCH was converted from a Texas corporation into a Delaware limitedliability company (the Conversion) and was renamed Energy Future Competitive Holdings Company LLC and (iii) EFH Corp.merged with and into EFH2 (the 2013 Merger), with EFH2 continuing as the surviving corporation. In connection with the 2013Merger, EFH2 was renamed Energy Future Holdings Corp.EFH2's directors and officers upon consummation of the 2013 Merger are the same as EFH Corp.'s directors and officersprior to the consummation of the 2013 Merger. Likewise, EFCH's managers and officers upon consummation of the Conversionare the same as its directors and officers prior to the consummation of the Conversion. Immediately after the consummation ofthe 2013 Merger, each of EFH2 and EFCH had, on a consolidated basis, the same assets, businesses and operations as EFH Corp.and EFCH had, respectively, immediately prior to the consummation of the Merger. The Transactions had no, and will have no,effect on EFH2's or EFCH's (or their respective subsidiaries') results of operations, liquidity or financial statements. EFH2 andEFH Corp. are both referred to as EFH Corp. throughout this quarterly report on Form I0-Q.Income Tax Payments -In the next twelve months, income tax payments to EFH Corp. related to the Texas margin taxare expected to total approximately $40 million, and we do not expect to make any payments to EFH Corp. related to federalincome taxes. There were no material payments or refunds for the three months ended March 31, 2013.See Note 12 to Financial Statements for discussion of uncertain tax positions.Interest Rate Swap Transactions -See Note 5 to Financial Statements for discussion of TCEH's interest rate swaps.64 Table of ContentsAccounts Receivable Securitization Program -TCEH participates in an accounts receivable securitization program witha financial institution. In accordance with transfers and servicing accounting standards, the trade accounts receivable amountsunder the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Underthe program, TXU Energy (originator) sells retail trade accounts receivable to TXU Energy Receivables Company, a consolidated,wholly-owned, bankruptcy-remote, direct subsidiary of TCEH. TXU Energy Receivables Company borrows funds from thefinancial institution using the accounts receivable as collateral. All new trade receivables under the program generated by theoriginator are continuously purchased by TXU Energy Receivables Company with the proceeds from collections of receivablespreviously purchased. Funding under the program totaled $89 million and $82 million at March 31,2013 and December 31, 2012,respectively. See Note 4 to Financial Statements.Financial Covenants, Credit Rating Provisions and Cross Default Provisions -The tem-s of the TCEH Senior SecuredFacilities and the accounts receivable securitization program (TCEH A/R Program) (see Note 4 to Financial Statements) containan identical maintenance covenant with respect to leverage ratio. At March 31, 2013, we were in compliance with such covenants.Covenants and Restrictions under Financing Arrangements -The TCEH Senior Secured Facilities and the indenturesgoverning substantially all of the debt we have issued in connection with, and subsequent to, the Merger contain covenants thatcould have a material impact on our liquidity and operations. In particular, the TCEH Senior Secured Facilities include a requirementto timely deliver to the lenders copies of audited annual financial statements that are not qualified as to the status of TCEH andits subsidiaries as a going concern.Adjusted EBITDA (as used in the maintenance covenant contained in the TCEH Senior Secured Facilities) for the twelvemonths ended March 31, 2013 totaled $3.346 billion for TCEH. See Exhibits 99(b) and 99(c) for a reconciliation of net loss toAdjusted EBITDA for TCEH and EFH Corp., respectively, for the three and twelve months ended March 31, 2013 and 2012.65 Table of ContentsThe table below summarizes TCEH's secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEHSenior Secured Facilities and the TCEH A/R Program and various other financial ratios of EFH Corp. and TCEH that are applicableunder certain other thresholds in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, theTCEH Senior Secured Notes, the TCEH Senior Secured Second Lien Notes and the EFH Corp. 10.875% Notes and EFH Corp.Toggle Notes at March 31, 2013 and December 31,2012. The debt incurrence and restricted payments/limitations on investmentscovenants thresholds described below represent levels that must be met in order for EFH Corp. or TCEH to incur certain permitteddebt or make certain restricted payments and/or investments. EFCH and its consolidated subsidiaries are in compliance with theirmaintenance covenants. In January 2013, in accordance with amendments to the terms of the EFH Corp. 9.75% Notes and EFHCorp. 10% Notes and their governing indentures, restrictive covenants to those notes were removed. Accordingly, the relatedcoverage ratios are not reflected below (see Note 5 to Financial Statements).March 31, December 31,2013 2012Threshold Level atMarch 31, 2013Maintenance Covenant:TCEH Senior Secured Facilities and TCEH A/R Program:Secured debt to Adjusted EBITDA ratioDebt Incurrence Thresholds:TCEH Senior Notes, Senior Secured Notes and SeniorSecured Second Lien Notes:TCEH fixed charge coverage ratioTCEH Senior Secured Facilities:TCEH fixed charge coverage ratioRestricted Payments/Limitations on Investments Thresholds:EFH Corp. 10.875% Notes and Toggle Notes:General restrictions (Sponsor Group payments):EFH Corp. leverage ratioTCEH Senior Notes, Senior Secured Notes and SeniorSecured Second Lien Notes:TCEH fixed charge coverage ratioTCEH Senior Secured Facilities:Payments to Sponsor Group:TCEH total debt to Adjusted EBITDA ratio6.18 to 1.00 5.88 to 1.00 Must not exceed 8.00 to 1.00 (a)1.1 to 1.0 1.2 to 1.01.2 to 1.0 1.2 to 1.0At least 2.0 to 1.0At least 2.0 to 1.010.7 to 1.0 10.1 to 1.0 Equal to or less than 7.0 to 1.01.1 to 1.0 1.2 to 1.0At least 2.0 to 1.09.0 to 1.0 8.5 to 1.0 Equal to or less than 6.5 to 1.0(a) Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities and up to $1.5 billion ($906million excluded at March 31, 2013) principal amount of TCEH senior secured first lien notes whose proceeds are used toprepay term loans or deposit letter of credit loans under the TCEH Senior Secured Facilities.Material Credit Rating Covenants and Credit Worthiness Effects on Liquidit.-As a result of TCEH's non-investment gradecredit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, at March 31, 2013,counterparties to those contracts could have required TCEH to post up to an aggregate of$17 million in additional collateral. Thisamount largely represents the below market terms of these contracts at March 31, 2013; thus, this amount will vary depending onthe value of these contracts on any given day.Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REPto support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under thesetariffs, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equalto estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as thetime period of transition charges covered, varies by utility. At March 31, 2013, TCEH has posted collateral support in the formof letters of credit to the applicable utilities in an aggregate amount equal to $26 million, with S10 million of this amount postedfor the benefit of Oncor.The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customerdeposits, if necessary. Under these rules, at March 31, 2013, TCEH posted letters of credit in the amount of $65 million, whichare subject to adjustments.66 Table of ContentsThe RRC has rules in place to assure that parties can meet their mining reclamation obligations, including through self-bonding when appropriate. If Luminant Generation Company LLC (a subsidiary of TCEH) does not continue to meet the self-bonding requirements as applied by the RRC, TCEH may be required to post cash, letter of credit or other tangible assets ascollateral support in an amount currently estimated to be approximately $850 million to $1.1 billion. The actual amount (if required)could vary depending upon numerous factors, including the amount of Luminant Generation Company LLC's self-bond acceptedby the RRC and the level of mining reclamation obligations.ERCOT has rules in place to assure adequate credit worthiness of parties that participate in the "day-ahead," "real-time" andcongestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantlyin the form of letters of credit, totaling $140 million at March 31,2013 (which is subject to daily adjustments based on settlementactivity with ERCOT).Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issuesin the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in anamount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred, two or more ratingagencies downgrade Oncor's credit ratings below investment grade.Other arrangements of EFCH and its subsidiaries, including the accounts receivable securitization program (see Note 4 toFinancial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may beadjusted depending on the relevant credit ratings.Material Cross Default/Acceleration Provisions- Certain of our financing arrangements contain provisions that could resultin an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenantsthat could or does result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration"provisions.A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to theaccounts receivable securitization program, in an aggregate amount in excess of $200 million may result in a cross default underthe TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity ofoutstanding balances ($22.635 billion at March 31, 2013), under such facilities.The indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and the TCEH Senior Secured Second LienNotes contain a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtednessunder any instrument or instruments of TCEH or any of its restricted subsidiaries in an aggregate amount equal to or greater than$250 million may cause the acceleration of the TCEH Senior Notes, TCEH Senior Secured Notes and TCEH Senior SecuredSecond Lien Notes.Under the terms ofa TCEH rail car lease, which had $40 million in remaining lease payments at March 31,2013 and terminatesin 2017, if TCEH failed to perform under agreements causing its indebtedness in an aggregate principal amount of $100 millionor more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the paymentof any remaining lease payments due under the lease.Under the terms of another TCEH rail car lease, which had $43 million in remaining lease payments at March 31, 2013 andterminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third partycreditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their originalstated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaininglease payments due under the lease.The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that appliesin the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under theprogram. TXU Energy Receivables Company (a direct subsidiary of TCEH) has a cross default threshold of $50,000. If any ofthese cross default provisions were triggered, the program could be terminated.We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event ofdefault or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess ofthresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on thecontract.67 Table of ContentsEach of TCEH's natural gas hedging agreements and interest rate swap agreements that are secured with a lien on its assetson a pani passu basis with the TCEH Senior Secured Facilities and TCEH Senior Secured Notes contain a cross default provision.In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but rangingfrom $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedgingagreements would have the right to terminate its hedge or interest rate swap agreement with TCEH and require all outstandingobligations under such agreement to be settled.Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to resultin a significant effect on liquidity.Guarantees -See Note 6 to Financial Statements for discussion of guarantees.OFF-BALANCE SHEET ARRANGEMENTSSee Notes 2 and 6 to Financial Statements regarding VIEs and guarantees, respectively.COMMITMENTS AND CONTINGENCIESSee Note 6 to Financial Statements for discussion of commitments and contingencies.CHANGES IN ACCOUNTING STANDARDSThere have been no recently issued accounting standards effective after March 31, 2013 that are expected to materiallyimpact our financial statements.68 Table of ContentsItem 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKAll dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwiseindicated.Market risk is the risk that we may experience a loss in value as a result of changes in market conditions affecting factors,such as commodity prices and interest rates, that may be experienced in the ordinary course of business. Our exposure to marketrisk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as wellas the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interestrate risk related to debt, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to managecommodity price risk.Risk OversightWe manage the commodity price, counterparty credit and commodity-related operational risk related to the competitiveenergy business within limitations established by senior management and in accordance with overall risk management policies.Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groupsthat operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies.These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value fromchanges in market conditions and include, but are not limited to, position review, Value at Risk (VaR) methodologies and stresstest scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review),operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validationand reporting, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.EFH Corp. has a corporate risk management organization that is headed by the Chief Financial Officer, who also functionsas the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respectivepolicies and procedures to ensure compliance with such limits and evaluates the risks inherent in our businesses.Commodity Price RiskOur business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products we market or purchase. We actively manage the portfolio of owned generation assets, fuel supply and retail salesload to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannotfully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads(differences between the market price of electricity and its cost of production).In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts withcustomers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. Wecontinuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to useconsistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.Natural Gas Price Hedging Program -See "Significant Activities and Events and Items Influencing Future Performance"above for a description of the program, including potential effects on reported results.VaR Methodology-- A VaR methodology is used to measure the amount of market risk that exists within the portfolio undera variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidencelevel and considers, among other things, market movements utilizing standard statistical techniques given historical and projectedmarket prices and volatilities.A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effectiveway to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this methodrequires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., thetime necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlationdata.69 Table of ContentsTrading VaR -This measurement estimates the potential loss in fair value, due to changes in market conditions, of allcontracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five days.March 31, 2013 December 31, 2012Month-end average Trading VaR: $ 3 $ 7Month-end high Trading VaR: $ 4 $ 12Month-end low Trading VaR: $ 2 $ 1VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting -This measurement estimates thepotential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principallyhedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holdingperiod of five to 60 days.March 31, 2013 December 31, 2012Month-end average MtM VaR: $ 83 $ 132Month-end high MtM VaR: $ 97 $ 206Month-end low MtM VaR: $ 68 $ 96Earnings at Risk (EaR) -This measurement estimates the potential reduction of pretax earnings for the periods presented,due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). A95% confidence level and a five to 60 day holding period are assumed in determining EaR.March 31, 2013 December 31, 2012Month-end average EaR: $ 27 $ 109Month-end high EaR: $ 31 $ 161Month-end low EaR: $ 23 $ 77The decrease in the Trading VaR risk measure above reflected lower market volatility and a decrease in trading positions.The decreases in the MtM VaR and EaR risk measures above reflected a reduction of positions in the natural gas price hedgingprogram due to maturities and lower market volatility.Interest Rate RiskAt March 31, 2013, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $17 million, taking into account the interestrate swaps discussed in Note 5 to Financial Statements.Credit RiskCredit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policieswith regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potentialcounterparty's financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific riskmitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negativeexposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businessesincluding methodologies to analyze counterparties' financial strength, measurement of current and potential future exposures andcontract language that provides rights for netting and setoff. Credit enhancements such as parental guarantees, letters of credit,surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed toassess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering intoan agreement with a counterparty that creates exposure. Further, we have established controls to determine and monitor theappropriateness of these limits on an ongoing basis. Prospective material changes in the payment history or financial conditionof a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. Thisprocess can result in the subsequent reduction of the credit limit or a request for additional financial assurances.70 Table of ContentsCredit Exposure -Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) andnet asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $1.069billion at March 31, 2013. The components of this exposure are discussed in more detail below.Assets subject to credit risk at March 31, 2013 include $383 million in retail trade accounts receivable before taking intoaccount cash deposits held as collateral for these receivables totaling $63 million. The risk of material loss (after considerationof bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances foruncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historicalexperience, market or operational conditions and changes in the financial condition of large business customers.The remaining credit exposure arises from wholesale trade receivables, commodity contracts and hedging and tradingactivities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions,electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketingcompanies. At March 31, 2013, the exposure to credit risk from these counterparties totaled $686 million taking into account thenetting provisions of the master agreements described above but before taking into account $454 million in credit collateral (cash,letters of credit and other credit support). The net exposure (after credit collateral) of $232 million decreased $23 million for thethree months ended March 31, 2013.Of this $232 million net exposure, essentially all is with investment grade customers and counterparties, as determined usingpublicly available information including major rating agencies' published ratings and our internal credit evaluation process. Thosecustomers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are ratedusing internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitorsand manages credit exposure to these customers and counterparties on this basis.The following table presents the distribution of credit exposure at March 31, 2013 arising from wholesale trade receivables,commodity contracts and hedging and trading activities, all of which matures in two years or less. This credit exposure representswholesale trade accounts receivable and net asset positions in the balance sheet arising from hedging and trading activities aftertaking into consideration netting provisions within each contract, setoff provisions in the event of default and any master nettingcontracts with counterparties. Credit collateral includes cash and letters of credit, but excludes other credit enhancements suchas liens on assets. See Note 9 to Financial Statements for further discussion of portions of this exposure related to activitiesmarked-to-market in the financial statements.ExposureBefore Credit Credit NetCollateral Collateral ExposureInvestment grade $ 684 $ 453 $ 231Noninvestment grade 2 1 1Totals $ 686 $ 454 $ 232Investment grade 99.7% 99.6%Noninvestment grade 0.3% 0.4%In addition to the exposures in the table above, contracts classified as "normal" purchase or sale and non-derivative contractualcommitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that isfavorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.Nonperformance could have a material impact on future results of operations, liquidity and financial condition.Significant (10% or greater) concentration of credit exposure exists with four counterparties, which represented 22%, 15%,15% and 12% of the $232 million net exposure. We view exposure to these counterparties to be within an acceptable level of risktolerance due to the counterparties' credit ratings, each of which is rated as investment grade, and the importance of our businessrelationship with the counterparties.71 Table of ContentsWith respect to credit risk related to the natural gas price hedging program, all of the transaction volumes are withcounterparties that have an investment grade credit rating. However, there is current and potential credit concentration risk relatedto the limited number of counterparties that comprise the substantial majority of the program, with such counterparties being inthe banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that wouldrequire the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. Anevent of default by one or more hedge counterparties could subsequently result in termination-related settlement payments thatreduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts ofexpected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with thesecounterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through thevarious ongoing risk management measures described above.72 Table of ContentsFORWARD-LOOKING STATEMENTSThis report and other presentations made by us contain "forward-looking statements." All statements, other than statementsof historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that addressactivities, events or developments that we expect or anticipate to occur in the future, including such matters as activities underour liability management program, financial or operational projections, capital allocation, future capital expenditures, businessstrategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets,market and industry developments and the growth of our businesses and operations (often, but not always, through the use ofwords or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "projection,""target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertaintiesand is qualified in its entirety by reference to the discussion of risk factors under Item I A, "Risk Factors" in our 2012 Form 10-K and the discussion under Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations"in this report and the following important factors, among others, that could cause our actual results to differ materially from thoseprojected in such forward-looking statements:" prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas,the US Congress, the US Federal Energy Regulatory Commission, the NERC, the TRE, the PUCT, the RRC, the NRC,the EPA, the TCEQ, the US Mine Safety and Health Administration and the CFTC, with respect to, among other things:o allowed prices;o industry, market and rate structure;o purchased power and recovery of investments;o operations of nuclear generation facilities;o operations of fossil-fueled generation facilities;o operations of mines;o self-bonding requirements;o acquisition and disposal of assets and facilities;o development, construction and operation of facilities;o decommissioning costs;o present or prospective wholesale and retail competition;° changes in tax laws and policies;o changes in and compliance with environmental and safety laws and policies, including the CSAPR, MATS andclimate change initiatives, ando clearing over the counter derivatives through exchanges and posting of cash collateral therewith;" legal and administrative proceedings and settlements;* general industry trends;" economic conditions, including the impact of an economic downturn;* our ability to collect trade receivables from counterparties;* our ability to attract and retain profitable customers;" our ability to profitably serve our customers;" restrictions on competitive retail pricing;* changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;* changes in prices of transportation of natural gas, coal, crude oil and refined products;" changes in market heat rates in the ERCOT electricity market;* our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heatrates and interest rates;* weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts ofsabotage, wars or terrorist or cybersecurity threats or activities;* population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT;* changes in business strategy, development plans or vendor relationships;" access to adequate transmission facilities to meet changing demands;" changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;* changes in operating expenses, liquidity needs and capital expenditures;" commercial bank market and capital market conditions and the potential impact of disruptions in US and internationalcredit markets;" the willingness of our lenders to extend the maturities of our debt instruments and the terms and conditions of any suchextensions;" access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability offunds in capital markets;73 Table of Contents" activity in the credit default swap market related to our debt instruments;* restrictions placed on us by the agreements governing our debt instruments;" our ability to generate sufficient cash flow to make interest payments on, or refinance, our debt instruments;" our ability to successfully execute our liability management program or otherwise address our debt maturities, includingthe potential exchange of debt securities for equity securities;" any defaults under certain of our financing arrangements that could trigger cross default or cross acceleration provisionsunder other financing arrangements;" our ability to make intercompany loans or otherwise transfer funds among different entities in our corporate structure;" competition for new energy development and other business opportunities;" inability of various counterparties to meet their obligations with respect to our financial instruments;" changes in technology used by and services offered by us;" changes in electricity transmission that allow additional electricity generation to compete with our generation assets;* significant changes in our relationship with our employees, including the availability of qualified personnel, and thepotential adverse effects if labor disputes or grievances were to occur;" changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits,pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure underthe Employee Retirement Income Security Act of 1974, as amended;" changes in assumptions used to estimate future executive compensation payments;" hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resultingfrom such hazards;* significant changes in critical accounting policies;" actions by credit rating agencies;* adverse claims by our creditors or holders of our debt securities;" our ability to effectively execute our operational strategy, and" our ability to implement cost reduction initiatives.Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, weundertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it ismade or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us topredict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors,may cause results to differ materially from those contained in any forward-looking statement. As such, you should not undulyrely on such forward-looking statements.INDUSTRY AND MARKET INFORMATIONThe industry and market data and other statistical information used throughout this report are based on independent industrypublications, government publications, reports by market research firms or other published independent sources, including certaindata published by ERCOT, the PUCT and NYMEX. We did not commission any of these publications or reports. Some data isalso based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sourceslisted above. Independent industry publications and surveys generally state that they have obtained information from sourcesbelieved to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each ofthese studies and publications is reliable, we have not independently verified such data and make no representation as to theaccuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we donot know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly,while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and wemake no assurances that the predictions contained therein are accurate.74 Table of ContentsItem 4. CONTROLS AND PROCEDURESAn evaluation was performed under the supervision and with the participation of our management, including the principalexecutive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls andprocedures in effect at the end of the current period included in this quarterly report. Based on the evaluation performed, ourmanagement, including the principal executive officer and principal financial officer, concluded that the disclosure controls andprocedures were effective. During the most recent fiscal quarter covered by this quarterly report, there has been no change in ourinternal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controlover financial reporting.PART II. OTHER INFORMATIONItem 1. LEGAL PROCEEDINGSReference is made to the discussion in Note 6 to Financial Statements regarding legal proceedings.Item 1A. RISK FACTORSIn addition to the other information set forth in this report, you should carefully consider the risk factors discussed in Part1, "Item IA. Risk Factors" in our 2012 Form 10-K. The risks described in such report are not the only risks facing our Company.Item 4. MINE SAFETY DISCLOSURESWe currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities.These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safetyand Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RRC andOffice of Surface Mining. The MSHA inspects US mines, including ours, on a regular basis, and if it believes a violation of theMine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompaniedby a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction ofthe severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders andproposed assessments are provided in Exhibit 95(a) to this quarterly report on Form I0-Q.75 Table of ContentsItem 6. EXHIBITS(a) Exhibits filed or furnished as part of Part 11 are:Exhibits(2)2(a)Previously Filed AsWith File Number* ExhibitPlan of Acquisition, Reorganization, Arrangement, Liquidation or Succession-Plan of Conversion of Energy Future Competitive HoldingsCompany(3(i)) Articles of Incorporation3(a) -Certificate of Formation of Energy Future Competitive HoldingsCompany LLC(3(ii)) By-laws3(b) -Limited Liability Company Agreement Of Energy FutureCompetitive Holdings Company LLC(4) Instruments Defining the Rights of Security Holders, Including IndenturesEnergy Future Holdings Corp.4(a)1-12833Form 1O-Q(May 2, 2013)4(a)-Fifth Supplemental Indenture, dated April 15, 2013, to the Indenture,dated October 31, 2007, among Energy Future Holdings Corp., theguarantors named therein and The Bank of New York Mellon TrustCompany, N.A., as trustee, relating to Senior Notes due 2017 andSenior Toggle Notes due 2017.Texas Competitive Electric Holdings Company LLC4(b)4(c)4(d)(10)1-12833Form I0-Q(May 2,2013)1-12833Form IO-Q(May 2,2013)1-12833Form I0-Q(May 2,2013)4(i)4()4(k)-Third Supplemental Indenture, dated January 11, 2013, to theIndenture dated October 31, 2007, among Texas CompetitiveElectric Holdings Company LLC, TCEH Finance, Inc., theguarantors party thereto and The Bank of New York Mellon TrustCompany, N.A., as trustee, relating to 10.25% Senior Notes due2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25%Senior Toggle Notes due 2016.-Supplemental Indenture, dated January 11, 2013, to the Indenturedated April 19, 2011, among Texas Competitive Electric HoldingsCompany LLC, TCEH Finance, Inc., the guarantors party theretoand The Bank of New York Mellon Trust Company, N.A., as trustee,relating to 11.5% Senior Secured Notes due 2020.-Fourth Supplemental Indenture, dated January 11, 2013, to theIndenture dated October 6,2010, among Texas Competitive ElectricHoldings Company LLC, TCEH Finance, Inc., the guarantors partythereto and The Bank of New York Mellon Trust Company, N.A.,as trustee, relating to 15% Senior Secured Second Lien Notes due2021 and 15% Senior Secured Second Lien Notes due 2021, SeriesB.Material ContractsCredit Agreements and Related Agreements10(a) 1-12833 Form 8-K(filed January 7,2013)10(b) 1-12833 Form 8-K(filed January 7,2013)10.110.2-December 2012 Extension Amendment, dated January 4, 2013, tothe $24,500,000,000 Credit Agreement.-Incremental Amendment No. 1, dated January 4, 2013, to the$24,500,000,000 Credit Agreement.(31)31(a)Rule 13a -14(a)/15d -14(a) CertificationsCertification of John F. Young, principal executive officer of EnergyFuture Competitive Holdings Company LLC, pursuant to Section302 of the Sarbanes-Oxley Act of 2002.76 Table of ContentsPreviously Filed AsExhibits With File Number* Exhibit31(b) -Certification of Paul M. Keglevic, principal financial officer ofEnergy Future Competitive Holdings Company LLC, pursuant toSection 302 of the Sarbanes-Oxley Act of 2002.(32) Section 1350 Certifications32(a) -Certification of John F. Young, principal executive officer of EnergyFuture Competitive Holdings Company LLC, pursuant to 18 U.S.C.Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32(b) -Certification of Paul M. Keglevic, principal financial officer ofEnergy Future Competitive Holdings Company LLC, pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of theSarbanes-Oxley Act of 2002.(95) Mine Safety Disclosures95(a) -Mine Safety Disclosures.(99) Additional Exhibits99(a) -Condensed Statement of Consolidated Income -Twelve MonthsEnded March 31, 2013.99(b) -Texas Competitive Electric Holdings Company LLC ConsolidatedAdjusted EBITDA reconciliation for the three and twelve monthsended March 31, 2013 and 2012.99(c) -Energy Future Holdings Corp. Consolidated Adjusted EBITDAreconciliation for the three and twelve months ended March 31,2013and 2012.XBRL Data Files101.INS -XBRL Instance Document**101.SCH -XBRL Taxonomy Extension Schema Document**101.CAL -XBRL Taxonomy Extension Calculation Document**101.DEF -XBRL Taxonomy Extension Definition Document**1O0.LAB -XBRL Taxonomy Extension Labels Document**1O0.PRE -XBRL Taxonomy Extension Presentation Document*** Incorporated herein by reference** Furnished herewith77 Table of ContentsSIGNATUREPursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signedon its behalf by the undersigned hereunto duly authorized.Energy Future Competitive Holdings Company LLCBy: /s/ STAN SZLAUDERBACHName: Stan SzlauderbachTitle: Senior Vice President and Controller(Principal Accounting Officer)Date: May 1, 201378 Exhibit 31(a)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCertificate Pursuant to Section 302of Sarbanes -Oxley Act of 2002I, John F. Young, certify that:1. I have reviewed this quarterly report on Form 1O-Q of Energy Future Competitive Holdings Company LLC;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which such statements were made, not misleading with respect tothe period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a-l 5(e) and 15d-1 5(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a-15(f) and 15d-15(f)) for the registrant and have:a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed underour supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period in which this report is being prepared;b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles;c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusionsabout the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based onsuch evaluation; andd. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during theregistrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materiallyaffected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalentfunctions):a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reportingwhich are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financialinformation; andb. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: May 1, 2013 /s/ JOHN F. YOUNGName: John F. YoungTitle: Chair, President and Chief Executive Exhibit 31(b)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCertificate Pursuant to Section 302of Sarbanes -Oxley Act of 2002I, Paul M. Keglevic, certify that:I have reviewed this quarterly report on Form I 0-Q of Energy Future Competitive Holdings Company LLC;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which such statements were made, not misleading with respect tothe period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a-15(e) and 15d-I 5(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a-15(f) and 15d-15(f)) for the registrant and have:a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed underour supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period in which this report is being prepared;b. Designed such internal control over financial reporting, orcaused such internal control over financial reporting to be designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles;c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusionsabout the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based onsuch evaluation; andd. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during theregistrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materiallyaffected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalentfunctions):a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reportingwhich are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financialinformation; andb, Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: May 1, 2013 /s/ PAUL M. KEGLEVICName: Paul M. KeglevicTitle: Executive Vice President and Chief FinancialOfficer Exhibit 32(a)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCertificate Pursuant to Section 906of Sarbanes -Oxley Act of 2002CERTIFICATION OF CEOThe undersigned, John F. Young, Chair, President and Chief Executive of Energy Future CompetitiveHoldings Company LLC (the "Company"), DOES HEREBY CERTIFY that, to his knowledge:1. The Company's Quarterly Report on Form 10-Q for the period ended March 31,2013 (the "Report")fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of1934, as amended; and2. Information contained in the Report fairly presents, in all material respects, the financial conditionand results of operations of the Company.IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 1 st dayof May, 2013./s/ JOHN F. YOUNGName: John F. YoungTitle: Chair, President and Chief ExecutiveA signed original of this written statement required by Section 906 has been provided to Energy Future Competitive HoldingsCompany LLC and will be retained by Energy Future Competitive Holdings Company LLC and furnished to the Securities andExchange Commission or its staff upon request. Exhibit 32(b)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCertificate Pursuant to Section 906of Sarbanes -Oxley Act of 2002CERTIFICATION OF CFOThe undersigned, Paul M. Keglevic, Executive Vice President and Chief Financial Officer of EnergyFuture Competitive Holdings Company LLC (the "Company"), DOES HEREBY CERTIFY that, to hisknowledge:1. The Company's Quarterly Report on Form 1O-Q for the period ended March 31,2013 (the "Report")fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of1934, as amended; and2. Information contained in the Report fairly presents, in all material respects, the financial conditionand results of operations of the Company.IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 1 st dayof May, 2013.Is! PAUL M. KEGLEVICName: Paul M. KeglevicTitle: Executive Vice President and Chief FinancialOfficerA signed original of this written statement required by Section 906 has been provided to Energy Future Competitive HoldingsCompany LLC and will be retained by Energy Future Competitive Holdings Company LLC and furnished to the Securities andExchange Commission or its staff upon request. Exhibit 95(a)Mine Safety DisclosuresSafety is a top priority in all our businesses, and accordingly, it is a key component of our focus on operational excellence,our employee performance reviews and employee compensation. Our health and safety program objectives are to prevent workplaceaccidents and ensure that all employees return home safely and comply with all regulations.We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities.These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safetyand Health Act of 1977, as amended (the Mine Act), as well as other regulatory agencies such as the RRC. The MSHA inspectsUS mines, including ours, on a regular basis and if it believes a violation of the Mine Act or any health or safety standard or otherregulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citationsand orders can be contested and appealed to the Federal Mine Safety and Health Review Commission (FMSHRC), which oftenresults in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. The number ofcitations, orders and proposed assessments vary depending on the size of the mine as well as other factors.Disclosures related to specific mines pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer ProtectionAct and Item 104 of Regulation S-K sourced from data documented at April 4, 2013 in the MSHA Data Retrieval System for thethree months ended March 31, 2013 (except pending legal actions, which are at March 31, 2013), are as follows:ReceivedReceived Notice of LegalTotal Dollar Total Notice of Potential ActionsSection Section Value of Number Pattern of to Have Pending Legal Legal104 104(d) MSHA of Violations Pattern at Last Actions ActionsS and S Section Citations Section Section Assessments Mining Under Under Day of Initiated ResolvedCitations 104(b) and II0(b)(2) 107(a) Proposed Related Section Section Period During DuringMine (a) (b) Orders Orders Violations Orders (c) Fatalities 104(e) 104(e) (d) Period PeriodBeckville 3 ....7 ---5 -IBig Brown .....- -.2 -IKosse 5 ..... ... 5 --Oak Hill 3 ..... .- -2S u lp h u r S p rin g -...... .. I --Tatum .... .. ... I --Three Oaks 1 ..... ...3 1 2Turlington -2 1 -Winfield South -. ..... ..--I(a) Excludes mines for which there were no applicable events.(b) Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injuryif left unabated.(c) Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in thethree months ended March 31, 2013, including but not limited to Sections 104, 107 and 110 citations and orders that are notrequired to be reported.(d) Pending actions before the FMSHRC involving a coal or other mine. All 20 are contests of proposed penalties. Exhibit 99(a)ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLCCONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)(Unaudited)Operating revenuesFuel, purchased power costs and delivery feesNet loss from commodity hedging and trading activitiesOperating costsDepreciation and amortizationSelling, general and administrative expensesFranchise and revenue-based taxesImpairment of goodwillOther incomeOther deductionsInterest incomeInterest expense and related chargesLoss before income taxesIncome tax benefitNet lossTwelve Months EndedMarch 31, 2013(millions of dollars)$ 5,674(2,824)(176)(910)(1,358)(662)(79)(1,200)14(188)33(2,789)(4,465)1,184$ (3,281) Exhibit 99(b)Texas Competitive Electric Holdings Company LLC ConsolidatedAdjusted EBITDA Reconciliation(millions of dollars)Net lossIncome tax benefitInterest expense and related chargesDepreciation and amortizationEBITDAInterest incomeAmortization of nuclear fuelPurchase accounting adjustments (a)Impairment of goodwillImpairment and write-down of other assets (b)Unrealized net (gain) loss resulting from commodity hedgingand trading transactionsEBITDA amount attributable to consolidated unrestrictedsubsidiariesCorporate depreciation, interest and income tax expensesincluded in SG&A expenseNoncash compensation expense (c)Transition and business optimization costs (d)Transaction and merger expenses (e)Restructuring and other (f)Charges related to pension plan actions (g)Expenses incurred to upgrade or expand a generation station (h)Adjusted EBITDA per Incurrence CovenantExpenses related to unplanned generation station outagesAdjusted EBITDA per Maintenance CovenantThree Months Three Months Twelve Months Twelve MonthsEnded Ended Ended EndedMarch 31, 2013 March 31, 2012 March 31, 2013 March 31, 2012$ (524) $ (238) $ (3,234) $ (1,677)(378) (115) (1,157) (877)586 622 2,716 3,823344 330 1,357 1,438$ 28 $ 599 $ (318) $ 2,707(4) (17) (33) (77)39 42 153 1475 9 51 128--1,200 ---6 4304871521,861(222)(2)(2)(7)1744172 3 6 155 9 29 4510 10 38 3616 (1) 31 88--141 -46 26 100 100$ 638 $ 834 $ 3,280 $ 3,40710 26 66 149$ 648 $ 860 $ 3,346 $ 3,556(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements,environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclearfuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Twelve months ended2012 includes $46 million related to an asset sale.(b) Impairment of assets in the twelve months ended 2012 includes impairment of emission allowances and certain mining assets due to EPArule issued in July 2011.(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and excludecapitalized amounts.(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costsrelated to generation plant reliability and supply chain efficiency initiatives.(e) Transaction and merger expenses primarily represent Sponsor Group management fees.(f) Restructuring and other in the three and twelve months ended 2013 includes costs associated with the liability management program.Restructuring and other in the twelve months ended 2012 includes fees related to the amendment and extension of the TCEH SeniorSecured Facilities.(g) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employeesof EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pensionobligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensiveincome.(h) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs. Exhibit 99(c)Energy Future Holdings Corp. ConsolidatedAdjusted EBITDA Reconciliation(millions of dollars)Net lossIncome tax benefitInterest expense and related chargesDepreciation and amortizationEBITDAOncor Holdings distributions of earningsInterest incomeAmortization of nuclear fuelPurchase accounting adjustments (a)Impairment of goodwillImpairment and write-down of other assets (b)Debt extinguishment gainsEquity in earnings of unconsolidated subsidiary (net of tax)Unrealized net (gain) loss resulting from commodity hedgingand trading transactionsEBITDA amount attributable to consolidated unrestrictedsubsidiariesNoncash compensation expense (c)Transition and business optimization costs (d)Transaction and merger expenses (e)Restructuring and other (f)Charges related to pension plan actions (g)Expenses incurred to upgrade or expand a generation station (h)SubtotalAdd Oncor Adjusted EBITDA (reduced by Oncor Holdingsdistributions)Adjusted EBITDA per Restricted Payments CovenantThree Months Three Months Twelve Months Twelve MonthsEnded Ended Ended EndedMarch 31, 2013 March 31, 2012 March 31, 2013 March 31, 2012$ (569) $ (304) $ (3,625) $ (1,855)(475) (180) (1,526) (1,099)784 785 3,505 4,436351 337 1,387 1,467$ 91 $ 638 $ (259) $ 2,94931 36 142 136-(2) (1) (2)39 42 153 1475 21 58 175--1,200 --1 47 434-- --(51)(67) (57) (280) (293)4871521,861(222)--43 4 10 176 9 32 4310 10 39 3816 -33 102--285 -46 26 100 100$ 667 $ 880 $ 3,424 $ 3,573384 350 1,634 1,537$ 1,051 S 1,230 $ 5,058 $ 5,110(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements,environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclearfuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Twelve months ended2012 includes $46 million related to an asset sale.(b) Impairment of assets in the twelve months ended 2012 includes impairment of emission allowances and certain mining assets due to EPArule issued in July 2011.(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and excludecapitalized amounts.(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costsrelated to generation plant reliability and supply chain efficiency initiatives.(e) Transaction and merger expenses primarily represent Sponsor Group management fees.(f) Restructuring and other in the three and twelve months ended 2013 includes costs associated with EFH Corp.'s liability managementprogram. Restructuring and other in the twelve months ended 2012 includes fees related to the amendment and extension of the TCEHSenior Secured Facilities.(g) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employeesof EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pensionobligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensiveincome.(h) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs.

Enclosure

9B with TXX-13095Additional Documentation forTexas Competitive Electric Holdings Company LLCCertificate of Formation of TXU Energy Company LLC (Delaware)Certificate of Amendment of TXU Energy Company LLC (name change)Fourth Amended and Restated LLC Agreement of Texas Competitive Electric HoldingsCompany LLC I .°State of DelawareOffice of the Secretary of State PAGE 1I., HARRIET SMITH WINDSOR, SECRETARY OF STATE OF THE STATE OFDELAWARE, DO HEREBY CERTIFY THE ATTACHED IS A TRUE AND CORRECTCOPY OF THE CERTIFICATE OF FORMATION OF "TXU ENERGY COMPANY.iLLC", FILED IN THIS OFFICE ON THE FIFTH DAY OF NOVEMBER, A.D.2001, AT 8:30 O'CLOCK A.M.flar,4et Smith Windsor, Seeiary of StateIAUTHENTICATION: 1426871DATE: 11-05-013453288 8100010554839 (i ....STATE OF DELAWARESECRETARY OF STATEDZVISZON OF CORPORATZONSFILED 08:30 AM 1/05/2001010554039 -3453288CERTIFICATE OF FORMATIONOFTXU ENERGY COMPANY LLC(a Delaware limited liabilty company)FIRST: The name of the limited liability company (the "Company") is TXU EnergyCompany LLC.SECOND: The Company's registered office in the State of Delaware is 1209 Orange94g Cky Candy of New Caud* Delaware 19601. The nameof itsaregldwagent at such address is The Corporation Trust Company.THIRD: The Company has a board of managers and the business and affairs of theCompany shall be managed by or under the direction of the board of managers. The Companyshall be a separate, independent entity from its member and its member, in such capacity, and byreason of its status as such, shall have no right or authority to bind or act for the Company.FOURTH: The number ofmanagers of the Company shall be fixed, from time to time, inthe manner provided in the Limited Liability Company Agreement of the Company and shall beone (1) or more.The number of managers constituting the initial board of managers is six (6), and thenames and addresses of the persons who are to serve as managers until thleir successors are dulyelected and qualified are:Brian N. Dickie Energy Plaza1601 Bryan StreetDallas, Texas 75201H. Jarrell Gibbs Energy Plaza1601 Bryan StreetDallas, Texas 75201Michael J. McNally Energy Plaza1601 Bryan StreetDallas, Texas 75201Erie Nye Energy Plaza1601 Bryan Street.Dallas, Texas 75201 (Philip G. TurbervilleR.A. WooldridgeEnergy Plaza1601 Bryan StreetDallas, Texas 75201Energy Plaza1601 Bryan StreetDallas, Texas 75201IN WITNESS WHEREOF, the undersigned has caused thisbe signed this 5d day of November, 2001.Certificate of Formation toR.&. Woolduidge, an Auth4AHPeronL:ACL1EfTTUCOXOOI30\Forntian Docun~ntsAJXU Encre Con~wy LLCertofforwowiaanoc2 DelawarePAGE 1Fhe First StateI, HARRIET SMITH WINDSOR, SECRETARY OF STATE OF THE STATE OFDELAWARE, DO HEREBY CERTIFY THE ATTACHED IS A TRUE AND CORRECTCOPY OF THE CERTIFICATE OF AMENDMENT OF "TXU ENERGY COMPANYLLC", CHANGING ITS NAME FROM "TXU ENERGY COMPANY LL-C" TO "TEXASCOMPETITIVE ELECTRIC HOLDINGS COMPANY LLC", FILED IN THIS OFFICEON THE TWENTY-NINTH DAY OF JUNE, A.D. 2007, AT 11:53 O'CLOCKA.M.AL4WHarriet Smith Wind~or, Secretary of StateAUTHENTICATION: .5805504DATE: 06-29-073453288 8100070767578 State of DelawareSecretary of StateDivision of CorporationsDelivered 11:53 AM 06/29/2007F=LED 11:53 AM 06/29/2007SRV 070767578- 3453288 FILECERTIFICATE OF AMENDMENT OFCERTIFICATE OF FORMATION OFTXU ENERGY COMPANY LLCTXU Energy Company LLC, a limited liability company organized and existingunder and by virtue of the Delaware Limited Liability Act (the "Company") does herebycertify:I. The present name of the Company is TXU Energy Company LLC.2. The original Certificate of Formation was filed with the Secretary of Stateof the State of Delaware on November 5, 2001 (the "Certificate of Formation").3. The Certificate of Amendment to the Certificate of Formation amends andrestates the First Article of the Certificate of Formation so that, as amended, said Articleshall read in its entirety as follows:"FIRST: The name of the limited liabili y company (the"Company") is Texas Competitive Electric Holdings Company LLC."IN WITNESS WHEREOF the undersigned has executed this Certificate ofAmendment this g day of., 2007.ZTXU ENERGY CO ~IANY LCKim ICW. ucker Secretary and Assistant TreasurerDoc #43 EXECUTION COPYFOURTH AMENDED AND RESTATEDLIMITED LIABILITY COMPANY AGREEMENTOFTEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY LLCDated .as.of August 29, 2011U9 354747v.2 Table of CQontents_PageARTICLE I DEFINITIONS ....... .... W........... ....... ....... ........ 2SECTION 1.01 DefmfitiOihs .............................. .............. ............................ 2SECTION 1i.02 Othfer Defifnitional Provisions .............................................................. ..7ARTICLE I ORGANIZATION OF THE COMPANY ................................,,.. 8SECTION 2.01 Formation ........ .................. ........ 8SECTION 2.:02 Names ..... ... ........ ............. 9SECTION 2.03 Registered Agent Offices.,. ............... ......SECTION 2.04 Term..... ....... w ............ ............................. 9SECTION 2.05 Purposes and Powers .............................................................................. 9SECTION 2.06 Limitation of Liability ......................... .......L ..................... 9SECTION 2.07 Limited Liability and Separateness...........................................10ARTICLE III MANAGEMENT OF THE COMPANY ......... ........ ....... .....10SOECON 3,01 MI nagement ........... .......................10SECTION 3.02 Bpardof Managers, ......... ......... ...... ... 10SECTION 3.03 Nutnber and Qualificatinsg..................... ................... i ..........................10SECTfION 3.04. L ngih of Service" ............................................................................... 11SECTION 3.05 R esignation .............................................................................................. 11SECTION 3.06 Meetings of. Managers .......... ........................ ........... 1$SCTION 3.07 Quorum; Majority Vote........................SEC.TION 3.08 Methods of V. g 11SECTION 3.09 Aetions Without a Meeting,.,....... ........ ................... 11SECTION 3.10 Board of Managers' Powers ..................................................................... 12S EC-TION 3.11 Diaties and Obligations oi'the Board of Managers ....... ...................... 12SECT IO N 3.12 O fficers. ....1...........................................2...... ............ ......... .................. 12SWETION 3.13 Electo'n, Removal and Rsignatkin .of Officers. ...........ARTICLE !V MEMBER$S. VOTING RIGHTS-................. ., .......14SECTION 4,01 Meetings of Members .... ..... ......... ;.............. 14SECTION 4.02 V oting Rights ................................................................................... 14SECTION 4.03 Registered Mermbers .................................. 14SIECTION 4.04 Withdrawal.; Resignation ............ ................. , ............ ... 15SECTION 4.05 Death or Dissolution of a Member.................... 15SECTION 4,06 Authoty. ....... ......................... 15ARTICLE V MEMBERSHIP INTERESTS. MEMBERSHIP ........................... ......... i5SECTION 5.01 M em bership Interests ...........................5.......... ...............................SECT.ION 5.02 New Members.............................. 15ARTICLE VI CAPITAL CONTRIBUTIONS AND CAPITAL ACCOUNTS.- REDEMPTIONS 16SECTION 6.01 .apital Cobttibutitns ................ 4 ...................... 16SECTION 6.02 Capital Ateounts .................................................................................. 16SECTION 6.03 NoWithdrawal ....... .................... ....... ... 16SECTION 6.04 Loans From Memters ...................16US 354147i).2 SECTION 6.05 St.atus of Capital Contributions..... ..... ... 16ARTICLE VII DISTRIBUTIONS ......... ............ .................SECTION 7,01 Prority of Distribut.ions........ ..... i .. .17SECTION 7.02 Liniitations On Distributions .. ..... .................... 17ARTICLE VIII ALLOCATIONS ................................................................................................ 17SECTION 8.01 Allocatons .................................... ......7...... 7SECTION 8.02 Special Allocations............................ ................................... 17SECTION 8.03 Curafive Allocations ...... i................ ................... 9SECTION 8.04 Code Section 704(d) Tax Allocations.., .. ................ ........ 19SECTION 8.05 Other Allocation Rules ......... ........ ; ........... .........19ARTICLE IX ELECTIONS AND REPORTS ........................................................................ 20SECTION 9.01 Accountitig Biooks ftnd Records ............................................................... 20SECTIOON 9.02 Reports ................................................... ............. ........ ...................... 20SECTION 9.03 Tax Elections .... .......................... ........... ....2SECTION 9,04 Ta. Controversies................... ............ .....21SECTION 9.0.5 Tax Status and Returns...... ..... ....................... I 21ARTICLE X DISSOLUTION AND LIQUIDATION ..,,....... ............................... ................. 21SECT IO N 10.01 D issolutiOn ............................................................................................. 21SECTION 10.02 Liquidationt ............................................................................ 22ARTICLE X!i TRANSFER OF MEMBERSHIP INTERE TS; COVERSION'S ......... ......;.3SECTION 11.01 R.s...c.tions. ......... ......... ......... 23SECTION 11.02 Ge..n~era! Restrictions on Ttansfer.......... .... ...2-3.SECTION 11:03 Ptrcedues 'for Ttansfef .,.... ............ ................... 24SECTION 1.1.04 Lim itations ........... ................................................................... 24ARTICLE XII INDEM NIFICATION ....................................................................................... 24SECTION 12.01 Right to Indemnification .......124....................................... ....................... 24SECTION 12.02 Limitation on Indemnification... -....25SECTION 12.03 Advancement of E~penses,... ..... -.25SECTION 12.04 Appearance as .Wimess ..... ......... ................... 25SECTION 12.05 Non-exclusivity of Rights ..... ............... .. ...25SECTION 1.2.06 C0ntract Rights ..................................................... ! ............................ 25-SECTION 12.07 Insurance............................................ 26SECTION 12.08 Savings .Cause ........ ..... .. .26SECTION 12109 Cons.ltaton with ........ .. .. ; .....26ARTICLE XI EXCULPATION. ........ ... ...... ......... ........ I ........ 27SECTION 13.0 ExculpatiOn... ................ i ..... .............. 27ARTICLE XIV M ISCELLANEOUS .......................................................................................... 27*SECTION 14.01 Notices .................... ............ ...........27SECTION 14.02 No Action for Partition .......... ...... .28SECTION 14.03 Headings and Sections.. ........... ............. 28SECTTION 14.04 Am e dm e ts ...... ........................................... ...................... 28SECTION 14.05 Biniding Effett ...........................d....................................................... 28SECTION 14.06 Governing Law .............. , .........28SECTION 14.07 Certifiicat4 of Fomation................................. 28SECTION 14.'08 Severability ... ................. ............ ......................... ... 28SECTION 14.09 Additioiial Dotumieits and Acts ................................ ; .......................29iiUS 35474'7v.2 SECTIQN 14..10 No Third Party Beneficiaries ... ...... ...... 29US 354747v.2 This FOURTH AMENDED AND RESTATED LIMITED LIABILITY COMPANY(this "greeme~nt") of Texas Competitive Electric loldings Company LLC(f/k/a TXU Energy Company LLC), a Delaware fimthed liability company (the ".ompany"), isentered into as of August ., 2011, by arid among the Company and Erergy Juture Co.mpetitiveHoldings Company f/k/,a TXU US Hbldings Company), a Texas corporation (-'Member").WHEREAS, Member formed the Company as. a limited liability company under the lawsof the State of Delaware by filing a of Formation (the "Original Certificate ofFormation") with the Secre.tary of St.ate of The State of Delaware on November 5, 2001, and inconnec.tion therewith entered into a Limited Liability Company Agreem ent f~r the Company onNovember i1Z, 2001 (the "Original Agreement");WHEREAS on November 21,.1002, Member contributed 1% of the menibership interestsin the Company to TXU Energy Holdngs Company ('"Energy Holdings") and Energy Holdingswas admitted as a member to the Company;WHEREAS, .on November 21, 2002, the Company, Member 4nd' Energy Holdingsentered into the First Atnended and Restated Limited Liability Company Agreefiment ("Fit'stAmendment"'), which amended and restated the Original Agfeement in its entirety in connectionwith the sale by the Company of $750 million principal amount of its 900* ExdhangableSubordinated Notes .due2012 (the "Notes") to certain entities affiliated Uwlh DU MerchantBanking Partners II, jLP, (the "DLJ Entities");.WHEREAS, on Deceember 19, 2002, with the conetit of the Company,. the DU Entitiestransferred $250 milliont prineipal amount of tht Notes to certain, entities affiliated withBerkshire Hathaway Tnc. (the "1BH Entities");WHEREAS, on July 1., 2003, the Company exercis.ed its right, to re¢j fire holders of theNotes to exchange their. Notes for a preferred equity interest in the .Cdmpany (the "NoteExchange");WHEREAS, on July 1, 2003, the Company, the Members, the DLU Entities, ad the BHEntities entered into the Second Amended and Res.tated Limited Liability Co npany Agreement(the "Second Amendmenit") which amended and restated the-First Amendment in its entirefy inconnectiOn -with the Note Exchange;WHEREAS., as set forth in the Second Amendment, Member held 99% Of the Class AMembership Interests (as defined in the Sgeond Amendment), Energy Holdings held 1% of theClass A Membership titerests, and the DIJ Entities -and the BH Erntities held all of the Class BPreferred Meffibetihip Interests (as defined in the Second Amendment);WHEREAS, on Apr.i 26, 2004, TXU Corp. (n/k/a Enfergy Fptture Holdings -Corp,)purchased all, of the Class B Preferred Membe.ship 1teqt.ests from the DU Entities and the BHEntities and executed joinders to the Second Amendment as h6lder of the Class B PreferredMethbership Ihtetesgts,WHEPREAS,-on De.ember 2.2, 2005, EFH Corp. cont~jbuted all of the Class B P.efe redMembership Interests to Member, ahd Memh ber c-offtributeid 1% of the Class B Membership.US 354747v.2 Interests to Energy Holdings (collectively, the "Contributions"), and Member and EiergyHoldings executed joinders to the Second Amendment as holders of the Class B MembershipInterests;WHEREAS, as a result of the Contributions, Member 4ad Energy H146dings held all ofthe Membership Interests (the Class A Membership Iterests and the Class B PreferredMembership Interests) in the Company in a r.atio of 99% to 1 %, respetively;WHEREAS, on September 29, 2006, Member and Energy Holdings recapitalized theCompany by converting their Class A Membership Interests and their Class B PreferredMembershp Interests into a single class of uncertificated Membership nterests to be owned....... .... -.-.... ....... I f s ... .......o .... ......... .. ..99% by Member and I % by Energy Holdings (the "Recapitalization");WHEREAS, on Septerriber 29. 2006, the Company, Member and Energy Holdirngsentered into the Third Amended and Restated Limited Liability Company Ag'eement (the"Third Amendmaent') which amended and restated the Second Amendmen:t in its entirety inconnection with the Recapitalization;. andWHEREAS, Member, which currently owns 100% of the Class B Membership Interests,desires to amend and restate the Third Amendment in its entirety to further establish thelimitation of liability, indemnification rights and exuelpdAtion rightg of Coveted Persons; andWHIBREAS,, this Agreement amends and restates the Third Amendment in all respects,and constitutes the governing instrument of the Company,.NOW, THEREFORE, ih consideration of the mutual covenants and agreements hereinmade and ether good and cdnsideratiion, the Member hereby agrdes as follows-ARTICLE IDEFINITIONS9ECTION 1.01 Definfitions.The following terms used in this Agreement shall have the following meanings (unlessotherwise expressly provided in this Agreement):"Affiliate" means with respect to any Person, any other Person controlling, controlled by,or under common control with such first Person."Agreement" has the meaning set forth in the Preaxiible."Bankruptcy" means, with respect to a Person, .(a) that such PersOn has (i) made anassignment for the benefit of creditors; (ii) filed a voluntary petition in bankruptcy' (iii) beenadjudged bankrupt, or insolvent. or had .entered against such Person -an order of relief in anyba6nrptcy or insolvency proceeding; (iN) filed a petition Or ati afswer seeking fof such Personany reorganization, arrangement, composition, readjustment, liquidation, dissolution or similarrelief under any statute, law or regulation -or riled .n answer or other pleading admitting or2US 354747v.2 failing to contest the material allegations of a petitioft filed against such Person in anyproceeding of such nature; or (V) sought, consented to, or acquiesced in the appointment of atrustee, receiver or liquidator of succh. or of all -or any substantial part of such Person'sproperties, (b) 60 days have elapsed after the commenmcement of .ry pr cd ing against suchPerson seeking reorganization, arrangement, composition, r.eadjustmentt,. liquilation, dissolutionor similar relief under any statute, law or regulation and such proceeding has niot been dismissed;or (c) 60 days haVe elapsed since the appointment wifhout such PerSon's consent or acquiescenceof A trustee, receiver or liquidator of such Person or .of all or any substantial part of such Person'sproperties and such appointihent has not been, vacated or stayed or the appointment is notvacated within 60 days after the expiration of such stay."Board of Managers" hag the meaning set forth in.Section 3.02.:iBusinesslDayý' means any day other than a Saturday, Sunday or any other day which isa legal holiday under the laws of he State of Texas or a day on which natIonal bankingassociations in such $tates are authorized or required by law or other governmental action toclose."Capital Account" meanS, with respect to any Member, the account niaiitained for suchMember as provided in Article VI and in accordance with Treasury Regulations Section 1.704-1 (b)(2)(iv) and this A.greement."Capital Contribution" means, with tespect to any Member, the aggregate amount ofmoney and the initial Gross Asset Va1u6 of any (other than mholley) contributed to theCompany, whenever made, In the case of a Member that acquires a'n interest in the Company byvirtue of a Transfer in accordance with the terms Of this Agreement, '"Capital Contributior"includes the Capital Contribution of such Member's predecessor in interest.."Certilicate of Formation" means the Original Certificate of Formation as may beatneffded, testated, supplemented or otherwise modified from time to tinie o:n or after the datehereof."Code" means the UnJited States Internal Rev~enue Code of 1986, as amended from timeto time."Company" has the meaning set forth in the Preamble."Covered Persopn" means any Person that is. or has been, at any time from and after theformation of the Company, (a) a Member or an Affiliate of any Member -or their respectivemembers, officers, directots, employees, agents, stockholders Or partners, (b) A Manager, Officer,employee or agent bf the Company or (-) a Person who serves oil behalf of the company as apartner, manager, member, officer, director, employee -or agent of any other entity."Delaware Act" means the Delaware Limited Liability Company Act, 6 Del. § 18-101 etseq., as the same may be amended from time to time.'`Depreciation' means, for each Fiscal Year or other period, an amount equal to thedepreciation, amortization or other cost recovery dedicftoion allowable for federal income taxUS 354747v.2 purposes with respect to an asset for such Fiscal Year or other period; provided, however, that ifthe Gross Asset Value of an asset differs from its adjusted basis. for federal in&ome tax purposesat the beginning of such Fiscal Year or other period, Depre iation shall be an amount that bearsthe same ratio to such beginning Gross Asset Value as the f.ederal inco 1e" {ax depremciati0m,amortization or other cost recovery deduction with respect to such asset tfor such Fiscal Year orother period bears to such beginning adjusted tax basis; and provided further that, if the federalincome (ax depreciation, amortization or other cost recovery deduction for sueh Fiscal Year orother period is zero, Deprecjiation. shall be determined with reference to such beginning GrossAsset Value using any.reasonable method selected by the Members."Dissolution Event" has the meaning set forth in Section i0.01(a)."Distribute" means to make one or more Distributions."Distribution" means, with respect to a Member, the amount of money and the GrossAsset Value of property other than money (net of any liabilities secured by such property thatsuch Member is considered to assume or take subject to as provided in Treasury RegulationSection 1.704-1 (b)(2)(iv)(b)(5)) distributed to such Member by the Company (a) on acdount ofsuch Member's Membership Interest as provided in Article VII or (b) 'in redemption orliquidation of all or any por(ion of such Meniber's Membership Interest, but shall not includepayments to a Member (i) pursuant to a loan or advance made by such Member to the Companyor in respect of any other transaction in Which such Member acts other than in such Member'scapacity as a patner within th meaning of Setion 70.7(a) of the Co.de .or (ii) which M aeguaranteed payments within the meaning of Section 707(c) of the Code."E~ncumbrance" means any lien, mortgage, pledge, collateral assignment, securityinterest, hypothecation or other encumbrance."Fair Market Value" of any asset as of any date means the purchme price which awilling buyer having all relevant knowledge wotild pay a willing Seller for such asset in an arms'length transaction."Ftscai Year me.ans the annual accounting period of the Company. which shall be thecalendar year or such portion of a caleiidar yea during which the Company ismin existence."GAAP" means generally accepted accounting principles in the United States of Americaas in effect:from time to time, consistently applied."Gross Asset Value" means, with respect to any asset, such asset's adjusted basis, forfederal income tax purposes, except as follows:(a) the initial Gross Asset Value of any asset (other than money) contributedby a Member to the Company shall be the- gross Fair Market. Value ofisuch asset;(b) the Gross Asset Value of all assets of the Company shall be adjusted toequal their respective gross Fair Market Values (talrg .Code section 7701(g) intoaccount), as determined by the Board of Managers, imnuediately prior to the followingtemesg- (i) the acquisition of an additional initerest in the. Company by any new or existing4US 354747v..2 Member in exchange for more than a de minimis Capital Contribution; (ii) thedistribution by the Company to a Member of more than. a de ininmiis amount of Companyassets as consideration for an interest in the Compaiay; and (iii) the liquidation of theCompany within tht meanfing Of Treasury Regulation Section 1.704-1 (b)(2)(ii)(g); and(c) the Gross Asset Value of any Company asset distributed in kind to anyMember shall be the gross Fair Market Value (taking Code section 7701(g) into account)of such asset on the date of distribution, as determined by the Board of Managerspursuant to Section 10.02(a).If the Gross Asset Value of an asset has been determined or adjusted pursuant to paragraph (a) orparagraph (b) above, such Gross Asset Value shall thereafter be reduced b~y the Depreciationtaken into account with respect to such asset for purposes. of computing Net Incomxe and NetLosses."Gross Income" .means all items of gross income and revenues for the applicable period,including any proceeds of any actual or deemed asset sales."Indemnification Amounts" has the meaning set forth in Section 12.01."Invested Capital" means the initial investment made by holders of MembershipInterests, as may be reduced from tihie to time by any redemption ot.return of capital."Joilnder" has the meaning set forth in Section 5.02."Law" means any United States or non-United States federal, national, supranational,state, ptovinciAl, local or similar statute, law, ordinance, regulation, rule, code, order,requirement or nile of law (including,without limitation, cominoii law)."Liquidation Event" means any liquidation, dissolufion or winding up of the affairs ofthe Company, Whether voluntary or involuntary."Liquidatorý' has the meaning set -forth in Section 10.02(a).'Majority in interest" means at any time, a Member or Members that own a majority ofthe Membership Interests outstanding at such time."Manager" means a member of the Board of Managers."Member" has the meaning set forth in the Preamble. 'Members 'Schedule" has themeaning set forth in Section 5.01."Meniberghip lntercist of .any Member at any time means the entire ownership interestof such Member in the Company at such time, including all benefits to whichl tbe owner of suchMembership Interest is entitled under this Agreem.ent and applicable law, together with allobligations of such Member under-this Agreement and applicAble law.US 354747v.2 "Net income" and "Net Losses" mean, for each Fiscal Year, an armount equa1 to theCompany's taxable income or loss for -such Fiscal Year, determined in accordance With Section703(a) of the C-ode (but including in taxable in.come or loss, for this purpose, all items of income,gain. ioss or deducton required to be stated separately pursuant to Section 703(a)(1) of theCode), with the following adjustm.ents:(a) any income df the Company exempt from federal income tax and nototherwise taken into account in computing Net Income or Net Losses pursuant to thisdefinition shall be added to such taxable income or loss,;(b) any expeAditures of the Company desdribed .in. Section 705(a)(2)(B) of-theCode (or treated as expenditures described in Section 705(aX)(2)(B) of-the Code pursUantto Treasury Redulationi Setiofi 1.704- 1(b)(2)(iv)(i)) and not otherwise taken into accountin computing Net Income or Net Losses pursuant to this definition shall be subtractedfrom such taxable income or loss;(c) in the event the.Gross Asset Value of afiy asset of the Compamy is adjustedin acootdatice with paragraph (b) or paragiaph (c) of the definition of "'Gross AssetValue" above, the amounti of such adjtlstmeint shall be tiken into account .as gain or lossfrom the &sposition of such asset for purposes of computing Net Income or Net Losses;(d) gain or loss resulting from any disp-osition of -any asset -of the Company-with respect to which'gain or loss is recog _ized for federal income tak purposes shall becomputed by reference. to the Gross Asset Value'of the -asset disposed of, notwithstandingthat the adjusted tax basis of suich asset differs fromi its Gtoss. Aset Vilue; *(0 in lieu of the depreciation, a'mortizatia.n and other cost, recoverydeductiqns taken into account in computing such taxable ifcome or loss, there shall betaken into account Depreciation for sgcbh Fiscal Yea-r or other period, computed inaccordance with tha defirion, of "DIe p"eiation" a.ove.t and(f0 any items which are specially illocated pursuant to Sections. 8.02 or 8.03shall not be account in compruting Net In ome or Net Los.The amounts of the items of Company incomej gain, loss or deduction available to be speciallyallocated putstuant to Sections 8.02 0or 803 shall, be determined by applying rules analogous tothose set forth in subparagraphs (a) through (e) above."Officer" means an officer of the Company.'Original Certificate of Formation" has the Meaning set forth in the Recitals."Person" means any individual, corporationA partnership, limited liability comrpany, trust,joint venture, governmental entity or other unincorporated entity, as.sociation or group."Proceeding7" has the meaning set forth in Section 12.01."Regulatory Allocations" has the meaning set forth in Section .8.03.6US 354747v.2 "State" means any one of the 50 states of the United States of America or the District ofColumbia."Tax" .or "Taxes" means all federal, State, local and foreign income, profits, franchise,gross receipts. environmental, customs duty, c.aptal stock, severance, stamp, windfall profit,.payroll, sales, use, transfer, employment, unemployment, disability, use, property, withholding,excise, productioa, value added, occupancy hnd other taxes, duties or assessments of any naturewhatsoever, together With all interest, penalties and additions impoged with respect thereto."Tax Matters Member" has -the meaning set fortth in Secfion.9.04."Transfer" means (a) as a noun, the transfer of ownership by sale, exchange, assignment,gift, donatibn, .grant or other conveyance of any kind, whether vOluntaty or. involuntary,including Transfers by operation of law or legal process (and hereby eXpresSly including, withrespect to a Member, assignee or other Person, any voluntary or involuntary appointment of areceiver, trustee. liqufidator, custodian or other similar official for such. Member or all or any partof such Member, assignee or other Person or all or any part of the property of such Member,assignee or other Person under .any bankruptcy, reorganization or insolvency law and (b) as averb, the act of making any voluntary or involuntary Transfer."Treastiry Regulations" means the income tax regulations promulgated under the Codeas amended.SECTION 1.02 Other Definitionai Provisions.(a) All terms in this Agreement shall have the defined meanings When used inany certificate or other document made or delivered pursuant hereto unless otherwisedefined therein.(b) As used in this Agreement and in any cerfificate or other documients madeor delivered pursuait hereto or thereto, accounting terms not~def'red in this Agreement or'in Afy such certificate or other document, and accoutnting terms partly defined in .thisAgreement or in any such ceftificdte or other document to the extent not defined, shallhave the respfective mieanangs given to them under G.AA. To the extent. tha.t thedefinitons of accounting terms in this Agreemejnt or i.n any such certificate or otherdoctmoent ;are inconsistent with the meanings of such terms under GAAP, the definitionscontained in this Agreement or in any such certificate or other docunmet shall conitrol.(c) The words "hereof", "herein", "hereunder", and words of ....ar importwhen used in this Agreement shall refer -to this Agreement as a whole and not to anyparticular provision of this Agreement; Section references contained: in this Agreementare references to'Sections in this Agreement unless otherWise specified; and the term"including" shall mean "includirig without limitationr.(d) The definitions contained in this Agreement are applicable to the singularas Well as the- plural forms of such terms.7US 354747v.2 (e) Common nouns and pronouns and any vaniations thereof shall be deemedto refer to masouline, feminine, ot tieuter, singular or plural, as the iden.tity of the Person,Persons or other -reference in the context requires. 'Whenever used herein, shallinclude both the conjunctive arid disjuctaive, .'arty". shall mean '0ohie or "micore," and"including' shall mean "including without linitationf'(f) Any agreement, instrument or statute defined or referred to herein or inanty ins'tument or certificate delivered in connection herewith means Such agreement,instrument or statute as from timý to time amended, thodified or AUpplemerntted andincludes (in the case of agreements .or insttuments) references to all attachments theretoand instruments incorporated therein; references to a Person are also to its permittedsuccessors and assigns.ARTICLE UIORGANIZATION OF THE COMPANYSECTION 2.01 Formati(a) The Company was formed upon the filing of the Original Certifiiate ofFormiation with the Secretary of State of the State of Delaware on November 5, 2001,pursuant to. the 'Delaware Act and such filing is hereby approved a4nd tallfied in allrespects. The. Managers and ach Officer are here inaiker'designatýd as "auithorizedpersons" within the mreaning of die Delaware Act.(b) Any Person designated as an "authorized person" :by the Board ofManagers is authorized to execute, deliver and file, of catise to be exee6ted, delivered andfiled, firom time to time on'. behalf of the Company .(i) -any anid all ainendments to andrestatements of the Certificate of Formation, and (ii) all other instruimients, .certificates,not Ies and documents, as an authorized person within -the meaning of:the DA-laware Act.In addirtioi, any Person. de.signated as an "'authorized person" by the Board of Managers isauthorized to do. or cause to be doine all such .filing, reording, publisiqg and other acts,in each case, as may be necessary or appropriate from time tW rime to comply, with all*applieable teqjuirenents for the formAtion andi/or operation and, When appropriate,.termination of z limited liability :companY in the State of Delaware and .all otherjurisd&ictions where the Company shall desire to conduct its busines'. This Agreementshall constitute the "limited company agreement" (as that t'erm is used in theDelaware Act) of the Company. The rightt, powers, duties, obligations and liabflities ofthe Membeit shall be determined putsuarit to the Delaware Adt and this Agreement. Tot.dhe 3xtent bthat the rights, powers, duties, obi.igations and liabiities 0f anyMember ,aredi.ferent by .reasonof-any provision of this Agreement than -they Would be in the 'absenceof s50Ch. provision., this Agreement shall, to the extent perrmitted by 'the Delaw.re Act,control,(c) The Company shall, to the extent permissiblb, elet 'to be treated as apa.rtn.ership for federal income tax purposes, and te Membership Interes!ts shal betreated as interests in a partnership for such purposes. Each Member and the CompanyUS 354747v,2 shall file All tax returns and shall otherwise take all tax and -financial reporting poshionsin a manner consistent -with such treatment ;ad no Member. shall take any actioninconsistent with such treatment.SECTION 2.02 Name; The naniie of the Company is "'Texas Competitive ElectticHoldings Cbmpany LLC', or such Other nathe or namies as the Board of Mahagers may fromtime to time designate; provided, howevei, that the name shail always gontain the words"Limited Liabilty Company", LLC" or L.L.C.SECTION 2.03 Registered Agent: Offices& The Company's registered Agent and officewithin the State of Delaware shall be The C-orpration Trust Company located at 1209 OrangeStrdet, Wilmington., Delaware 19801, or such other place as the Board of Minagers may fromtime to time ditermine. The Company's principal executive office shall be located at EnergyPlaza, 1601 Bry.an Street, 'Daf!as, Tietas 75201-34.11, or 'such other Place as the Board ofManagers may from time to time determe.SECTION 2.04 Term. The tertn of existence of the Company shall be perpetual from thedate the Original Certificate of Formation was filed with the Secretary of State ofthe State -ofDelaware, uriless the Company is dissolved in accordance with the provisions of this Agreementor the Delaware Act.SECTION 2.05 Pu'poses and Powers The purpose of the CPompain s to engage in anyactivity and to:¢xercie,aany powewr permxittit to liftiited liability tompahies unider the. laws of theState. of Delaware.SECTION 2.06 Linitation of Liability.(a) Except as otherwise expressly provided by the Delaware Act, no CoveredPerson shall be liable foir the. debts- dbligations or liabilities of the Cornpany (whetherasinig in contract, tort or otherwise),, iieluiding, without limiitation, tiider a judgment,decree orforder of a court, by reaýon 6f'being a Coveted Petton.bo) E:ch Member shall have the same limitation. of persqtnal liability as isextended to stockholders of a cprivate cOrporaiion for profit incorporated under theGeneral Corporation Law of theState of Delaware.(c) No Manager or Officer shall be subject in such..capacity to any personalliability whatsoever to any Person,, other. than thre Company or any Memberin the limitedcircumstances. allwed herein, in connecijon with the assets or the affairs of theCompany; and, subject to the provisions of XII, all. such Persons shall look solelyto the assets .of the Company f6r satisfaction of.Chainfh 9Of any nature arisin~g Jn connectionwith the affairs of the Company.(d) The failure of the Company to obgerve any formalities or requirementstelating to thd exercise of itS poWers Ot mildagemenit of the Company or its .affairs underthis Agreement or the DelawareAct shafl notbe grounds.fo r.imposing perso.,ai liabilityon any Covered Person for liabilities of the Company.9US 354747.22 (e) Such protections from personal liability shall apply to the fullest extentpermitted by applieable law, as the same exists or may hereafter be.ammended (but, in thecase of -any such amendment, only to the exteit that such amendment permits theCompany to provide greater or broader indemnification rights than such law permittedthe Company to provide prior to such amendment).(f) To the extent that, at law or in a equityj a Coveted Person or any otherperson has duties (including fiduciary duties) to the Company or to another Member orManager or to another person that is a.party to or is otherwise bound by this Agreement,those duties are hereby elirminated to (he fullest extent allowed under tDelaware law andthe Delaware Act, including §18-1. 101 of the Delaware Act. All liabilities for breach ofcontract and breach of duties (including fiduciary duties) ,of a Covered Person or anyother person to the -Company or to another Member or Manager ot any other person thatis a party to or is othetwise bound by this Agreement are hefdby eliminated to the fullestextent allowed under Delaware law and the Delaware Act, including §18-1101 of theDelaware Act. The elimination of duties and liabilities set forth in this Section 2.06(f)shall be deemed to apply from and after the formation of the Company.-SECTION 2.07 Limited Liability..and. Segarateness. The Company shall be operated insuch a manner as the Managers deem reasonible and necessary or apprbpriate4to preserve (a) thelimited liability of each oi the Members .(or their successofs) in the Cor.pahy and (b) theseparateness of the Company from the business of each Member of the Company' or any otherAffiliate= thereof.ARTICLE IN1MANAGEMENT OF THE COMPANYSECTION 3101 Management. The Company shall be managed by a Bbard of Managers.SECTION 3.02 Board of.ManagerS,.(a) The Company shall have a "Board ofManage-rs", made up of at least one(i) member, which shall be chose.n"by the Majority in Intere.5t.(b) Any Maisager may be removed at any time, with or wjthout cause, by theaffirrnative vote of the Majority in Interest. Any Manager who is femoved in accordancewith the provisions of this Section 3.02(b), or resigns or otherwise ceases to hold officeby reason of his death, shall be replaced by the affirmative vote 9f the Majority inInterest.SECTION 3.03 Numbero and Qualifications. The number of ManagerS of the Companyshall be at least one (1), .subject to modification by the Board of Managers in, accordance to thisAgreement, but no decrease in the number of Managers shall have the effect of.shortening theterm of any incumbent Manager.10US 354747v.2 SECTION 3.04 Length of Service. EaCh Manager shall h6ld 6ffide until his or hersuccessor shall be. selected as provided in Section 3.02 of this Agreement and qualified, or untilhis or her earlier death, resignation or removal -as provided in this Agreement.SECTION 3.05 Resignation. Any Manager may fesign at any timo. Such resignationshall be .made in writing and shall -take effect. at the time specified thereir or, if no time isspecified therein, at the time of its receipt by the remaining Manager. The acceptance of aresignation shall not be necessary to make it effective, unless so expressly provided in theresignation.SECTION 3.06 Meetings of Board of Managers.(a) All meetings of the Board 'of Managers shall be held telephonically, byvideoconference (such participation in any such meeting shai1 constitute presence inperson at such meeting, except where a Person participates in such meeting for theexpress purpose of objecting to the transaction of any business on thh ground that suchmeeting is not lawfully called or convened) or at the principal office of the Company orat such other place within or without the State of Delaware, as may be determined by theChaitperson of the Board of Managers or the member(s) of the Board of Managerscalling the meeting, as the case may be, and set forth in the respective notice or waiversof notice of such meeting. A record shall be maintained of each meeting of the Board ofManagers.(b) Meetings of the Board of Managers may be called by (i) the Chairpersonof the Board of Managers or (ii) by one or more MAnagers.SECTION 3.07 Quorum: Majority Vote. Except as otherwise provided herein or byapplicable law,. the presence in person or by telephone of a majority of the Managers shallconstitute a quorum of the Board of Managers for putrposes of conducting business,- unless agreater nurabet is required by this Agreement or by law. Omne a quorum is present at a mteetingof the Board of Managers, the subseqaueit Withdrawal. from the meeting of an& MAnhager prior toadjournment or the refusal of any Manager to vote shall not. dffect thd presence of a quorum at:the meeting. If, however, such quorum shall not be present at ,ay meeting of the Board ofManagers, fhe Managers at such meeting shall have the ptwer .to adjourn the meting, withoutnotice ofther than armouncement at the meeting, until a majority of the Managers shall be present.Except as otherwise provided herein, or required by applicable law, resolutions of the Managersat any meeting of Board of Managers shai be adopted by the affnimative vote of a majority ofthe Managers at such meeting at which a quorum is present. The act of a majority of the Board ofManagers present in person or by telephone at a meeting at which a quorum is present in personor by telephone shall be the act of the Managers, except as ofherwise provided by law or anyother provision in this Agreement.SECTION 3.08 Methods of Voting. A Manager may vote either in person or bytelephone.SECTION 3.09 ActiOnS.Without a Meeting. Any action required Or permitted to betaken at a meeting of the Board of Managers may be taken without a meeting, without prior11US 354747v.'2 notice., and without a vote, if a consent in writing, setting forth the -action so. taken, is signed by amajority of the Managers entitled to vote on the action. Copies of any such consemts shall befiled with the minutes and permanefit xecords of the Compny.SECTION 3.10 Board of Managers'. Powers. The Board of Managers shall have theauthority on behalf and in the name of the Company to perform all acts necessary and desirableto the objects and purposes of the Company, suibject to the rig.hts of the Liquidator to liquidatethe Company rand take all actions incidental thereto .during the period of Iiquidtion.SECTION 3.11 Duties and Obligations of the Board of Managers.(a) The Board of Managers may engage one or more managers or Officers toadvise the Board of Managers and be responsible for directiqg the day-to-day operatioiisof the Company under the supervision of the Board of Managers. Each Manager shall bedeemed a 'imanag'er" of the Company -for all purposes of, and with the meaning set forthin, the Delaware Act..(b) The Board of Managers shall have the power to delegate authority to suchManagers, Officers, employees, agents and representatives of the Company, as it mayfrom time to time deem appropriate.SECTION 3.12 Officers.(a) The Officers of the Company, as such, shall have limited authority, andShall be subject to the provisions arid limitations of this Article ill. All Officers named inthis Agreement or elected or appointed pdrsuant to this Article Ill shall be responsible to,and subject to the authority and direction of, the Board of Managers in connection withmatters over which the Board of Managers has authority.(b) The Board of Managers may elect a Chairperson of ihe Boatd who, ifelected, shall preside at all meetings of the Members And of the Board of Managers andshal peforeif such other duties as may be prescribed by the 9Board of Managfrs from timeto time.(c) The Company may elect a Chief Execuitive Officeer, who, if eleted,. shallhave general active man.agement. of the business of the Company, and in the -absence ofthe Chairpersoi of the Board of Managers or if the office of Chairperson of the Boaita ofManagers is vacarit, shall preside at -meetings of the members and Board of Managers,shall see tiat a. orders and resolutions of the Board of Managers are ,-arri.ed. into effect,shall have authority to sign and deliver in the name of the Conipan-y any deeds,mortgages, bonds, contracts, or othdr instruments pertaining -to the business of theCompany, except in cages in which the authority to sign aid deliver iS reqluired by law tobe exercised by anofher person, is expressly deleigated by this Agreement 'or the Board ofManagers to some oiler Officer or agent of the Comopany or as may generakly bedelegated in the ordinary course of business, may maintain records of and certifyproceedinfgs of the Board of Managers and Members, and hall peifottn such other dtitiesas may from. time to time be ptescribed by the Board of Maiiagerg.12US 354747v.2 (d) The Company may have a President, who -shal. be the. hief ope.ratingdfficer of. the Comqpany, shafl have a.u tority to exercise the. of the (Thief ExecutiveOfficer in his .abseic.., and in the abýsen.e of fte Chairperson of the Board of Managersand the chief Exeoutive Officer; ar. if -.both suoch offices .are -v.acat, shall pteside atmeetings. ofthe Menibers A.d Board of Managers. The Coftpay may also have one ormore Vice. Presidents, who shall have*authority toexercise the power !of the President inhis absence.(ee) The Comp.any may have a Treasurer,. w..ho unless provide.d btherwise bythe Board of Manageirs, shall keep .acUrate finaneial rectords for t1e Company, -shalldeposit all moneys, draft's, and .heekg ih -the Niahe ofantd to the credit -of the Company,shall endorse for deposit all notes, cheeks, and drafts teceived by the tompany, makingproper vouchers therefor, shall disburse. Company funds and issue checks and drafis inthe nnmpe ,of th* (ompany; shail rendzer to the .President and tahe B~ard of Managers,w.henever requeste.d, an account of all sjuch. Officer's trgansactiong 4.s Chief FilnancialOfficer and of the financial cor¢dition of the C~ofpar.y, and shall performi such otherduties -as the Board of Managers. or the President May prescribe, ftr6mtime to tiMd.(f) The Company 'may have %a Secretary, who shall have primaryresponsibility to maintain records of -actions of, .and wýhenevr necessaryc certify allproceedinags -f ihne M2mbers. The $ecretpary slall1 keep th-e re.rS of theConp~a~ry, Wheri. so directed by the person or persons authorized to Cal-l such metings,shall giye -or t.ai"Se to be given C otieeof aibeelbgs of the Metnbees;, and. shall peffol sfchother duties. and have .sucrh ofher poweos as the Members 6r -the Ptds:ident niday pzescribefrom tithe to time..(g) The Compa..ny. may hpave additional Officers as detrmi 4ed by the Board ofMan~agers.t(h) No Officer need be a Manager,. 4 Member, a Delaware tesident or -a. UnitedStates Citrien.SECTION 3.13 Election. Removal and.Regignation of Officers.(a) Stabject io the other provisions of this.gAtticle Ill, the Board of Managersmay elect or appoint other Officers or agents of the Company, with such t-itles, duties, andauthority as they shall designate. Subject to. tbe other provdstons o.this Articlee1l, and toary other limit{ti0pns that the Board of Managers-- may impose, the Chief Exe ufiveOfficer may 4ielegate authority and appoirnit:ot0.r Offioers and agents of the Company,with such titles, d "ties, and authofity as the Chief vEedutive :Officei ghal1 desigtate, TheChief 8xcfuive Officer, at any tinie, rhay remove or terminate the authority .of anyOfficer or agent that was appointed by the Chief Executive: Officer.(b) Any Officer may be temoved as: s.uch, with orw-itho.tit catise, by tha Boardof Matiagers at any time. Any Officer mhy resign as such at any time iipon written notice.to the Company. Such resignation shall be made in writmng an.n4 sha.i- take effect at bhe.13US 354747v.2 time spedified therein or,, if no -time is specified therein, at the time of its te.ceipt by theBoatd of Managers.ARTICLE IVMEMBERS. VOTING RIGHTSSECTION 4.01 Meetings of Members.(a) Generally, Meetings of the Members may be called by.. (i) the Board ofManagers or :(i) a Majority in. Interest, All. meeetings of the Members shall be heldtelephonically, by videoconfererice or at the prin.ipal .office of -the Company or at suchothef place within or without the ,State of Delaware, as may be determined by the Boardof Managers or the Membet(g) calling the hieetihg; as the tage may be.(b) PEroxy, Each Member may authorize any Person or Persons to act for it byproxy on al _matters in which a Member is entitled to ppaticjpat, including waivingnotice of any meeting, or voting ,or parficipatoig at a meeting. Evqry proxy must beSigned by the Member or fts aitorney-ii-fact. Every proxy shall be revocable orirre'vocable at the plpeagure ofthe Memb&f ex-ecuting it.(0) O.uorim: Voting. Except as otherwise provided here'i or by applicable!aw, a Majority in. Interest, repiesented in. person Qr byoproxy,. shall constitute p quomof Members for pprposes of conducting businerss. Once.a quorum is. present at a meeting.of the Members, the wubseqtuieit withdrawal from theo.meetinag oof anyý Member prior toadjournment or the tefu.sal of any MWmber to vote sihall :not affect the pres.ence of aquorum at the meeting. If, hoWevef, suich qtohiaut shall hot be present at any.meetinig Ofte Members, the Members entitled to vote at such meeting shall have the power toadjourn the meeting, without .noftice other than alnnouncerment 4at the meeting, until aMajority .in shall be present ..r represenied. Except as otherwise provi{ded hereinor required by applicable law, resolutions of the Merebers at any m eeting of MembersShall be adopted bly the affirmative 00ote of a Majority in Interest.rpepresented and entitledto vote at such -meeting at which a qilonmn iS presetit.(d) Actions Without a Meeting. Unless otherwise prohibIted by law, anyaction to be taken at a meeting of the Members may be taken witlfoqt a meeting if aconflett in writing; setting forth the actiofi so taken, shall be signed by a Majority inInterest arid such coftsent is delivered to the Secretary of the Compan'y pgomptly after theeffective date of such consent.. A record shall be maintained b"y- the Secretary of theCompaniy of e~ac.h such action taken by written consent of the Membeirs.SECTION 4.02 Voting Rights, Except as specifically provide.d in thli Agreemeht orotherwise. required by applicable law., Cor all ptrposes .heretnder, iieludng- for purposes ofArticle Il hereof, the Members shall be entitled to vote pro rata in accordance with MembershipInterests.SECTION 4.03 Registered Members. The Companiy shall be entitled to -treat the ownerof record of any Membersiiip fnterests as the -owner in fact of such Membership Interest for all14US 354747v.2 purposes, and, accordingly, shall not be bound to recognize ay equitable or other claim to orinterest in such Membership Interest on the part of any; 0ther 'Person, whether or not it shall haveexpress or. other notice of such claim or interest, except as expressly provided by this Agreementor the laws of the. State of Delawre,SECTION 4.04 WithdrawaL,. Regiaatkicn. A Member shall not cease to be a Member asa result of the Bankruptcy of such Memýber or as result of ahy other events specified !i Section18-304 of the Delaware Act. So long as a Member continues 'to own or hold any MembershipInterests, such Member shall not have the ability to resign as a Member prior to the dissolutionand winding-up of the. Company and any su6h resignation or attempted resignation by a Memberprior to the dissolution or -winding-tip of the Company shall be null and void, As soon as anyPerson who iS a Member ceases to own or hold any Membership Interests, such Personi shall nolonger be a Member.SECTION 4.05 Death or Dissolution of a Member. Except as provided in Section 10.01,the death or dissolution- of any- Member shall not cause the dissolution of the Comipa.y. i suchevent, the Company and its business shall be continued by the- remaining Memnber or Members.SECTION 4.06 Authority. No Member, in its capacity as a Menil er, shall have thepower to act for or on behalf of, or to bind the Conipany.ARTICLE VMEMBERSHIP INTERESTS; MEMBERSHIPSECTION 5.01 Menibership Interests. The Membership Interests of the Company shallconsist of one class of Membership Interests, with such class having the rigfits and privileges,including voting rights, if Any,. set forth 'n this Agreeemen. Upon issuance.olf any Members.hpInterests as providjfed in this Agreement, the Membership Ioterests so issued shall be deemed tobe duly and validly issued. The Secretary of the Compay shall maintain a schedule of allMembers from time to time, shall include their respective mailing adalresses- and theMembership interests held by them (as the same may be amended, modified or suppleinentedfrom time to time, the 'iMembers a copy of. whik.ch as of the date hereof is attachedhereto as Schedule A. The Members sha.ll 'have no Interest in the Company other (han theMembership Interests confetred by this Agreement, which shall be deemed to be personalproperty giving only the rights conferred by this Agreement. Ownership of a MembershipInterest shall not entitle a Member to call for a partition or division of any property of theCompany.SECTION 5.02 New Membets. In ordor for a PersOn to be admitted hs a Member of theCompany pursuant to the issaandce of Meffmbrershfip .Iterests to such Personi such Perfon shallhave executed and del. ivered to the Secretary-of the Colphqy a written andeitaking to be boundby the terms agd conditions of this Agreement substantially in -the form o4 Exhibit A hereto(each, a "Joinder"). Upon execution of a Joinder, the amendment of the Members Schedule bythe Secretary of Company and the satisfaction of any other apllicable conditions, including thereceipt by the CompAny of payment for the is-stuance of the aj)plicable Mehibeiship Interests,such Person shall be admitted as a Member and deemed listed as such on the books and records15US 354747v.2 of the Company and thereupon shall be issued his or its Membership Interests. The Board ofManagers shall then adjust the Capital Accounmts of the Members as necessary in accordance withSection 6.02.ARTICLE VICAPITAL CONTRIBUTIONS AND CAPITAL ACCOUNTS; REDEMPTIONSSECTION 6.01 Capital Contributions. Prior to, or as of, the date here of, each Personwho is a Member as of' the date hereof has made or is deemed to have made, CapitalContributions to the Company and is deemed to own the percentage of Membership Interests setforth opposite such Member's naame on the Members Schedule as in effect on the date hereof.SECTION 6.02 Capital Accounts.(a) Each holder of a Membership Interest shall have a Capital Account equalto its (i) Invested Capital, (ii) plus any Net Income or items of Gross Income allocated tosuch holder and (iii) less (x) any Distributions to suc'h holder and (y) any Net 'Loss oritems of loss or deduction allocated to such lioider.(b) Such Capital Accounts shall be maintained in accordance with TreasuryRegulations Section 1 .704-1 (b)(2)(iv).SECTION 6.03 No Withdrawal. No Member will be entitled to withdfaw any part of itsCapital Contribution or Capital Account or to receive any Distribution from the Company,except as expressly provided'in this Agreement. ISECTIION 6.04 Loans FromMembers. Loans by Members to the Company shall not beconsidered Capital Contributions.SECTION 6.05 Status of Capital Contributions.(a) No- Member shall. receive any interest, salary or drawing with respect to itsCapital Contributions or its Capital Account, except as: otherwise specifically provided inthis Agreement. I(b) Except as otherwise provided by applicable law, no Member shall bereqttired to lend any funds to the Company or to make any additional CapitalContributions to the Company.(c) No Member shall have any personal liability for the repayment of anyCapital Contribution of any other Member.ARTICLE VIIDISTRIBUTIONS16US 354747v.2 SECTION 7.01 Priority -of Distributions. Distributions in any formi includi.ng cash orother assetS., shall be made to the holders of Membership IntOrests pro rata in acCordance-withtheir Membership Interests at the tihtes and in ihe aggrtegatd amiunrts determined by the Bo3ard. ofManagers. NotV'ithstanding any provisions to the c~ntfafy cohtained in -this Agreement, theCompany shall not be required to make a distribution to any Memiber on account of Its interest inthe Company if such disti ibiutnion would violate Section 18-5$0 df'the A.t or any other applicablelaw., A Member shall not be entitled to receipt. of a. D ristbution, and, thus, shall not be de.emed acreditor of the Company with respect to a, Distribution as, by Sebtion 18.60.6 of theAct, until the -date specified by the Board of Managers in the re.ohlution authorizing suchDistribution, aand if no such date is specified by the Board of Managers, thdn such entitlementdate shall be -the payment :date for such Distribution set forth in the -resolution authorizing suchDistribution.SECTION 7.02 Limitations. on .Distributions. Notwithstanding any provision to thecontrary contained in this Agreemenrt, the Company shall not make any Distribution if suchDistribution would violate Section 18-601 of the DelaWate Act or other applieable law or if suchDistribittion would violate any of the Company's debt financing agreements or any other debtfinancing agreenient of which the Company is a guarantor, but shall instead make suchDistribution as soon as practicable after such time as the rn. g of such Distribution would notcause such violation.ARTICLE VIIIALLOCATIONSSECTION 8.01 Allocations.(a) Net Income shall be ailocated fot each Fiscal Yeari -to the holders ofMetnbership Ihtefests pro rata in accordance with. their Membership Initerests.(b) Net Losses shall be allocated for each Fiscal Year to the holders ofMemboership Interests pro rata in accordance with their Membership Interests.SECTION 8.02 S:pegial Allocations. The following speciaI allocatiofis shall be made inthe following order to the extent iterms of income, gain, loss or dedkuction are available:(a) Partnership Minimum -Gain.Chargeback. Except as otherwise provided inTre.asuty Regulation Section 1,704-2(0, notwithgtatiding any othet provision of thisArticle VIII, if there is a net decrease in pattnership minimum gain during any FiscalYear, each Member shall be specially allocated items of Company irlcome and gain forsuch Fiscal Year (and, if necessary, siubsequent Fiscal Years) in an arhount equal to suchMemiber0. share of the net. decr-ease in partnershifp minimum gain, detetirnied inaccordance with Tre~asury Re gulation Section 1.704-2(g). Allocations pursuant to theptevious .sentence shall be made in oroportion to the respective amounts requlred -to beallocated to each Member pursuant thereto. The items to be so -allocated shall beThermne itemsc bec so i cte shal bedetermined in. accordance wh Treasury Regulation Secions .704-2.(0(6) and1,704.-2")(2).. Th~is Section .8,02(aW is intended to comply with the mininiutamr gain17US 354747v,2U dhargeback -requirement in Treasury Regula.tion Section 1.704-2(0 and sh ail be.interpreted consis:tntly therewith.(b) Partner Minimum. Gaint Chatgeback. Except as OthetWise provided inTreasury Reguilation Section 1.7,04-2(0)(4), iiotw iftstandink any other provision of thisArticle if there is a net decrease in partner nonrecourse debt miiuimum g4inattribut.able io a partner nonrecourse ddbt during any Fiis.at Yega, eadh Mnember who hasa share of the partner npnrecourse debt minimurm ,gain aftributable to such partnertinrecourse debt, determin.ed in a~cordancie with Treasury Rgutilatiom Section1.704--2(i)(5), glhall be specially allocated items of Company fiicome" and gain for suchFiscal Year (and, if necessary, subkeqient Fiscal Years) in an am6iunt equal to suchMember's share of the net decrease in partner nonrecourse debt minimum gainattribuable Ito such par.tner nponreourse debt,. determined 'in accordnce with TreasuryRegulation Se.tion 1.704.2(i)(4). All-ocations pursuant to the previoul sentence shall bemade in proportion to (he respective amo.ums required to be alloc-ated to each Memberpursuant thereto, The items to b. sO allocatel shall b.e detetm',ined in accordance withTreasury Regulation Sections 1.704-1(i)(.4) -and 1.704-2(j)(2). This -Sectiotf 8.02(b) isintended to comply with the minimum gain. chargeback reluirement in TreasuryRe.gulafion Section.1!,704-2(i)(4) and shall be. interprete consistently therewith.(c) Qualified.Income.Offset. .I the event any Member ..nn.xpecttdly receivesany adjustments, allocafions 6r disributions .described in Treasury Regulation Sections1.704-1.(b)(2)(ii)(d)(4), 1.704 1(b)(2)(ii)(d)(5) or 1.704-1(b)(2)(ii)(d)(6), items ofCompany ircome and gain shall be specially allocated in an amount and mannersufficient :to eliminate, to the extent 'required by ithe Tieasury Regulations, the AdjustedCap4tal ApcxQo.uo Deficit of such Member as qu icly as possb.le, proqvidie, thqt anallopation ,porsuant to this Section 8:02(c) shall boe mde :oly if and to the e n.x t 'that.such. Member wouId have an" .Adjusted Capital Ace..t.. Defiit .after ,l! ther ai.c:.ti.onsprovided for in this .S-eetion 8.02(e) have been te=ntaiely made as if this Section 8.02(L).wefe not conitaied in .hiN Agreeiierit. For this purpoge, Adjnsted Capital Account Ddficitmeans, with respect to any Member, the deficit balance, if many, in such Memberes CapitalAccount as of the end of the relevant Fiscal Year, pfter giing to the followingadjustmentA: 'i) 0such CQapital Account shall be deemed to be increas.d by .apy amoiuntsthat such MIldber is obligated ttO restore to the Comprany -(parsutant to this Agreemernt: orotherwise) or is deeiiied tb. be obligated to restore pursuant to: (A) the penultitatesentence .of Treasdtiy Regulation Secti0n 1.704-2(g)(1)-, -bt (B.) the penultifnate sentenceof Treasury. Regulation Section I .704-2(i)(5), and (ii) such Capital Account shall bedeemed to be deceased by the items described in Treasury Reguiaiiorn Section 1.704-1~b)(2)(ii)(d)(4.), (5) and (6).(d) Gross Income Allocation. In the event any Member has a deficit 'CapitalAccount at the end -of any "Iscail Year which is io excess of the .sun of. (i) the amountsjuch Member is obligated to restore pursuant to any provision of this Agreement and (ii)the amount such Member is deemed to be obligated to r¢st~te pursuant to the pentiltimatesentences of Tre-asury RoegflAtion :Seetions 1 .704 2(g)(l) and 1.704-2(i)(5),-each sdchMember shall be specially allocated items of Gross Income in the. amount of such excessas quickly as possible, proviided, thai an allocation pursuant to this, Sect-ion ,8,02(d) shallU8US 354747.v.2 be made only if and to the extent that such Member would have a defiit Capitai A c-cntin excess of such sum after all other allocations p 'ovided for in this lSection 802, havebee n made as if S-ection 8.02(d) aNd this Section 8.02(d) were not eontainid iii thisAgreement.SECTION 8.03 Curative. Ailoeations. The allocations set forth in jSection 8.02 (the"Regulatory Allocations") are intendeOd to comply with certain requiremenis of the TreasuryRegulations. It is the intent of the MeW hers that, to the extent possible, all RegulatotyAllocations shall be offset tither with other Regulatory Allocations or with spcial allocations :ofother itedis of Coompafty ificoine, gain, logs or deductioti pursuant to this Section 8.03.Therefore, notwithstanding any. -other provision of this Article Viii (other than the "RegulatoryAllo4cations), :the Members shall makeý such offsetting special allocations of :Company income,gain, los.s or dleduetion in whatever manner the Board of Managers deterin, es appropriate sothat, after such offsetting allocations made, each Menriber's Capital Account balance is,, to theextent possible, equal to the Capital :Ae-iount balance such Member wouldd have had if theRegulatory Allocations were not tonlairied in this Agreement Aid all Company items wereallocated pursuant to this Article VIIi Withouit regard to the Regulatory Allocafions. In exetdisingits discretion under this Secton ., the Board .of Managers shall -take into account futureRegulatory Allocations under 5ection 28.02 that, although not yet made, are likely to offset otherRegulato.ry Allocations previpo.sly iiiode under Section 8.02.SECTION 8.04 Code Section 704(c-) TAx Allocations. In accordatice with Code Section704(c) iind the Tteasry' Regiiiilatidns thereunder, iicOcfne, gain, loss, and dedoction with..-egpectto any property ,contributed to the. capital of the. Coftipafty shall, solely fo' -tax purposes, beallocated among the Members so as to take -account of any variation between the adjiusted basisof suqh propeity to the Company for federal income tax purposes and its Gr,"ss Asset Value at-the tinye of its con.tribo.tion. In the event.thepGross Asset Vaiue of any Company asset reflected inthe Members' Capital Accounts is adjusted pursuant to the provisions .above: subseque..nt;allocations of income, gain, logs and deduction with reSpect to smuh asset sh9ll take acfount ofany variation hetWeeni the adjus'ted basis of sluch asset for feder-al income tak purposes and theadjusted Oross Asset Value of such property as reflected in the 'Menibeks' capital Accounts in..e same manner as u~nder Code Section 704,(c) .and -te Treasur~y Regul4aons th.r.eunder.Allocations pursuant to this Section -8.04 are solely for federal income t-ax piupo.es and shall notaffect, or in any way be talkeen into acouant in ornmputing, any Member's Capital Account oirshare of Net income, Net Losses, or other items, or distributions pu-suart to ainy provision of thisAgreement. Except as,0therwise phovidl 'in this Agreement, all items of Company income, gaini,loss, deduction and any other allocations not otherwise provided for, shall be divided among theMembers -in the same proportions as they share Net Income, Net Lqsses, oý "amounts speciallyallocated pursuant to Sections -8.03 or.8.041 as the case inay be, for-the Fiscal Year.SECTION 8.05 Other Allocation Rules.(a) Excopt as otherwi-se provided in 'Section_8.04 and rieX, for Taxptjposes, each item of income, gain, loss and dedtuetioii will, to the tx:ent apptropriate, beallocated among the Menribers ini the same manner as its correlatie itemf of 4book'incoMegain, .loss or --deduction has been allocated pursuant to the other provisions of thisAg-eeie.nt.19US 35,447V.2 (b) For purposes of determining the Net Income and Net ILosses or any otheritems allocable to any period, Net Income and Net Losses and any such other items shallbe determined on a daily, monthly -or other basis, as die.ermined by the Tax MattersMember using any method that is pernmissible -under Code Section 706 and the TreasuryRegulations thereunder.ARTICLE IXELECTIONS AND REPORTSSECTION 9.01 Accounting Books and Records.(a) The Company shall. keep on site at its principal place of business each ofthe following:(i) separate books of accouht for the Company which shall show atrue and accurate record of all costs aid expenss incurred, al) charges made, allcredits made and received, and all income derived in connection with. the conductof the Company and the operation of its business in .acdordance with thisAgreement;(ii) a current list of the full name and last known business, -residence,or mailing address of each Member, both past and present;(iii) a copy of the Certificate of Formation, together with executedcopies of any powers of attorney pu.rsu ant to wh.ich -any amendment has beenexecuted;(iv) copies of the C6opany-' federal.,. State, local and. foreign incomeTax returns and reports, if any *(v) copies of this Agreem.e~nt;(vi) copies of any writings permitted or .reqiuit d urder SeCtion 18-502of the Delaware Act regarding the 6bligation of a Meifier to perform anyenforceable promise to conttribute cash or property or tW terfomi services asconsideration for such Member's.Capital Contrf. bu.i.tion; and I(vii) any written, consents obtained from Members ýursuant to Section18-302 of the Ielaware Act regarding action taken by Members without ameeting.(b) The Company shall use the accrual method of accounting for Taxpurposes and shall use GAAP in the 4r~paration of its financial repots and shall keep itsbooks and records in accordance with the foregoing.SECTION 9-.02 Rgports. The Board of Managers shall be tesponsible, for causing thepreparation of financial reports of the Company, including the appointme!nt of the Company's20US 354747v.2 accountants., and the coordination of financial matters of the Company with the Company'saccountants.SECTION9.03 Tax Elections. The taxable year will be the Fiscal Y.ar, unless the TaxMatte.rs Member determines another taxable year is required in order to comly with applicablelaws. Unless otherwise provided, in this Agreement, the Tax Matters Member will dete.rminewhether to mnke or revoke any available election purguant to the Code,SECTION 9.04 Tax Controversies. The Member is. designated the -Ta MattersMember" for the Com pany-, and in sqch capacity slhall be considered to be the "tax matterspartner" within .tie meaning of Section 6231 of the Code. The Tax Matters Member is authorizedand required to represent the (at the Company's expense) in conneetion with allexaminations of the Companty's affairs by Tax authorities, including res-ulting administrative'andjudicial proceedin~gs, and to expend COmpany funds for professional 'ervices and costsassociated iherewidi.SECTION 9,0.5 Tax Status and Returns. Each of the parties hire.to:1(a4) recognlizes andintends that4 for U.S. fed.eral inco'un tax purposes, the Company shal be treated asa partnershipin which -each Member is a partner and (b) agrees to refrain from taking of teonsenting to anyaction the result. of which 4buld result in the 61assification or treathfient of the Company asanything other than a partnership in which each Member is -a partner for U.S.. federal income taxp~irposes. To the extent that any -of the parties hereto is required to report any item of income,gain, 1.oss, deduction, or credit rla.tng .to te Company for G.. come tax purposes,such party shall -report such item in a. manner consistent with the Company's tax returns andstateinents.ARTICLE XDISSOLUTION AND LIQUIDATIONSECTION 10,01 Dissolution.*(a) The Company shall be dissolved and its affairs wound up only upon thehappening of any of the following: events (each a "Dissolution Eventi):(i) the sale or other disposition by the Company of all or substantiallyall of the assets it then owns ih .accordance w"-iththe terms of thlis Agreement; or(i_) a Liquidation Event or the Bankruptc.y of the C6mpany; or(iii) the entry -of a decree of judicida dissolution utdir Section 18-802of ihe Delaware Act;(b) Diss~olution of the Compa y shall be effective on ih &ay on which theevent occurs givilig rise to such di'solution, but the Companiy shall no t terminate until thewinding-up of the Company has bden completed, the assets of the &ompany have beeinDi stributed as provided in -Section 10.02 and the Certificate of Forma Iion shaII have beenicanceled.21US 354747v.2 SECTION 10.02 Liquidafion.(a) Liquidator. Upon the occurrence of a Dissolution Event, the Board ofManragers will appoint a Person to act as the "Liquidator", and such person shall act asthe Liquidator unless and until a successor Liquidator is appointed as provided in thisSection 10.02. The Liquidator will agree not to rtign at any time without 30 days' priorwritten notice to the Board of Managers. The Liquidator may be removed at any time, forOr without cause, by notice of removal and appointment of a subcessor Liquidatorapproved by the Board of Managers. Any successor Liquidator will succeed to all rights,powers and duties of the former Liquidator. The right to appoint a successor or substiuteLiquidator in the manner provided in this Section .10.02 wilI be recurring and continuingfor so long as the" functions. and services of the Liqcuidator are authorized to continueunder the provisions Of this Agreemerit, and every refetence in this Agreement to theLiquidator will be deemed to refer also to any such successor or substitute Liquidatorappointed in the manner provided in this Section .10.02. The Liquidator shall receivereimbursement of its reasonable out-of-'pocket expenses in performing its duties.(b) Liquidating Actrions. The Liquidator will liquidate the assets of theCompany and apply, and )istribu6te the proceeds of such liqtaidation, in the followingorder of priority, unless otherwise required by mandatory provisions of applicable law:(i) frst,, to the.payment in full of the Compan y's dekbts and obligationsto its creditors (ineluding in order of !be priority provided by law;(ii) second, to the establishmedit of and Additions to such reserves asthe Board of Managers deems reasonably necessary or appropriate; and*(iii) 0hird, after first giving effect to. the allocations described in Section8.01 throuigh Section 8.,03 and Section. 10.01 above, first tW settle the CapitalAccounts of the holders of Membershbip Iterests.For the .avoidanc.e of doubt, the allocations and Distributions provided for in thisAgreement are intended to result in the Capital Account of each Member immediatelyprior to the Distribution of the Company's assets pursuant to this Section. 10.02(b) beingequal to the amount whic-h such Member would be entitled to in akcordance with thepriority of Distributions under Section 7.0i.(c) Distribution in. Kind. Notwithstanding the provisions of Section 10.02(b)which require the liquidaiion of the assets of the Company, but subject to the order ofpriorities set forth in Section 10:02(b), if upon dis.solution of the Coimpany the Board ofManagers determines ihat an iinmediate sale of part or all of the Company's -assets wouldbe impractical. or could cause undue loss to the Members, the Board of Managers may, inits sole discretion, defer the liquifdation of any assets except those ie cessary to satisfyCompany liabilities and reserves, and may, in i(s absolute discretkon, Distribqte to theholders of the Membership Interests, in lieu of caSh, as tenants in common and inaccordance with the provisions of Section J0.02(b),. undivided interests ift such Companyassets as the Liquidator deems not suitable for liquidation. Any such bDistribution in kind22US 354741v.2 will be subject to sucfh conrdifions relating to the disposito" n and management -of suchproperties as the Liqtiidator deems reasonable and equitable and 'to any agreementsgoverning the operating of such properties at such time. For puiposes of any suchDistribution, the Fair Market Valae of any prbperty to be distfibuted, shall be that valueagreed to by a Majority in Interest and a majority of the Board of ManAgefs.d Time- to Wind.Up. A reasonable time will be alIlwed for the orderly,win ding up of the business aand affairs of the Company and the liqujidation of its assetsputsuant to Section 10.02(b)l in order to minimize afty- losses otherwise attendant uponsuch winkding tip. Distributions wpon liquidationh of the. Company (.or aty Mefnbir'sinterest in the Company) and related adjustments will be made. by the efid of the FiscalYear of the Liquidation (or, iflater, with-n 90 days after the d4,te of Such liquidation) oras otherwise permitted by Treasury Reguigtion Section 1.704-i(b)(2) ii)(b).(e) Termination. Upor completion of the Distribution Of the assets of theCompany .as provided in- Section 10.02(b) hereof, the Compainy hall be terminated andthe L4iqu idator shall causedthe cancedlatiofi of the Cettificate of Formnation in the State ofDelaware and of all qualifications and registrations of the Company as .a foreign 'limitedliablity company in jurilsdictions other than th e State of Delaware and shall take suchother actions as maybe necessary to terminate the Company.ARTICLE XITRASFER OF MEMBERSHIP INTERESTS; CONVERSIONSSECTION 11.01 Restrictions. Each -Member acknowledges and agrees that suchMember shall not Trnsfer, .r.ereate or suffer to exist any Enctumbrance againist, anyMembeirship Interests except in aecord aiae with the .ptovisiorls of this Article XI. Any attemptedTransfer ,or EncunbraceU in violatiof of the: preceding segntence shall be de-med vOid ab iiditioand of no force Or effect whatgoe-Ver, and the Company will riot record AY such Tfransfer orEncurnbrance on its boOcks or treat any purported transferee as the owner such MemlershipInterests for any purpose.SECTION 11.02 General Restfictions on Transfer. Notwithstandihg Atythitig to thecontrary in this Agrieeient, no transferee of any Mefribership ifftereSt9 rediived pursuant to -aTransfer shall become a Member in respect of or be deemed to have any ownership rights in theMembership interests so Trans~ferred unless the. purported transferee is admitted as a Member,(a) Following a Transfer of any MembeNfiip Ifitorestw that is per rmitted underthis Atticle XI, the transferee of sitch Membership interests Shall .suteeed to the CapitalAccount associated with such. Membership In.!terests and shall-recive allocations andDistibut~ions hereunder in r"pect of such Mermbejship Interests. Nottwithstanding theforegoing. Net Income .and Net Losses and other item's will be allocated between thetransferor and the transferee according t6 Section 706 of the Code..23US 354747v.2 (b) Any Member who Transfers All of its Membership Interests: (i) shall ceaseto be a Member upon such Transfer, and (ii) shall no longer possess or.. have the power toexercise any ights or powers of a Member of the Comp.any. iSECTION 11.03 Procedureg for TrAnsfer. Subject in all events. to the genera! testrictionson Trasfters contained :in ihig Ar-tile XI, a Member may Transfer all 6r Any part of itsMembership 'Interests in accordance with the following conditions!(a) No Transfer of Membership Interests may be .cQoMpleted -until thepro:speefive transferee is admitted as a Member of the. Companty by executi ng anddelivering to the Secretary -of the Co0impany a Jo.irdeti UpOn exec-dtioin f a Joinder, theamendment of -the M 6mbedt Schedtle by the Sectetr.y of the Company arid thesatisfaction of any other applicable conditions., such prospective transferee. shall beOamitted as a Member and deemed listed as such on the books :Lnd Tecords of theCompany and thereupon the Company shall res.sue the applicable MWmberghip Interestsin the name of such prospective transferee,(b) The transferor aid transferee shall .furnifsh thes C'mpaxiy with thetransferee's taxpayer identification nunber, sufficiertt iftfotmatjohi to (determiine thetragsferee's initial tax basis in the Membership Interest transferred, and any otherinformation reaso~nably neessary jo permit the Compan y to file Qal r.quired federal andState tax r. etns and other -legally -required information statpemrnts or returns, Withoutthe generality of the foregoiqg, th.e Co-p. y shal. no.t_ e-requtirep to -make -anydis'tribution 6iherwise provided for in this Agreement with respect to any ttansf rredMembership Intdetsts .wtil it has receiv.ed such information.SECTION 111,04 Limitations. Notwithfstai.ding .anythng to the contrary :in thisAgreement. no Membership lpt rest may be Transferred aid the Co-m.pany' may n'o4t issue anyMembership lnterest 'dfless:. 0i) suc-h TranSfer .or isuan _he, .0s- cse C may be., sbal not ,affect theCompany"/s existence or .qualificatfon -gg a liftifted liability company wider tho Dolaware Aqt, (ii)such 'Ttansfet ot igsilante, as the case may be, shall iot cdatisd ithe C`iftpfiy to be 6iassified asother than a partnership for United States -federal income tax purposes and A!i) such Transfer orissuance, ;as the case may be, shall. not result in a terminatiorn of th.e .ompany under CodeSection 708, unless the Board of M aagtp determines that any su.h termination will not have amaterial adverse impact. on te Members.ARTICLE XIIINDEMNIFICATIONSECTION 12.01 Right to Indeminification. Subject to the limitatiota Iard conditions asprovided iln. this, Article Xil each Co vered Person who was or is -made a party-or is threatened -tobe made a party to0 or i s. invdived in any threatened, pending ior fcomple~ed action or otherproceeding, whether civil, criminal, administratioe, et.itrative or investi~gatfie, or an.y appeal insuch a proteedifg o. any or inveutigation that C.olI lead to such. a piroceeding (hereaftera 'Proceeding".), by re~son of any actions of omissions or alleged aWtS bu, omissidos of suchCovered Person relating to the Company, shall be indemnified .. the Company to the fullest24US 354747v.2 extenit permitted by applicable law, as the same exists or may .hereafter be amended, againstjudgments, penialties (mncluding excise arid similar taxes arid pntin-Vei daij ages), finesisettlements and reasonable expenses (including, without limitation, attorneys' fee.) (allcollectively the 1!ndemnifiAti~on Amounts'-") actually incurred by such Covered Person at thetime any such Indemnification Amounts ar.e ncUrred. in. connection with s.ch p roceeding.Indefiificafioan under this Antikle. XII shall eonttdiu as to a Covered Personwho .has .eased toserve in the capacity whieh. initially entittled 'guh person to indemnity hereu~nder. Withoutlimiting the .generality of the foregoing, it is expressly .acknOWledged that. the iiidenificationprovided in this Article Xfl could involve indemnification for negligerice oi under theories ofstrict liability.S.ECTION 2102 Limitation on Indemnification, Subject to applicable law,notwithstanding any langua-ge iri this Atticle Xii to the contrary, in no event :hall any Person beentitled to indemriification pUrsUant .to this Aiticle XtI if it is tgtablighed or adniitted either (a) ina final judgment of a court of competent jurisdiction or (b) by such Persdn in any affidavit,sworn statement, plea arrangement or other cooperation with any :governmnent or regulatoryauthority that the Pers6oi-s acts qr omissions that would otherwise be subject; to indemnriiicatlonunder this Article XII constituted fraud.,SECTION 12.03 Advancement .of Exftege The right to indemhifi6,ation conferred inthis Article XIi shall include fhe right to be Paid or reimbursed by the Company the reasonableexpenses incurred by a Covered Person.of the type entitled to be indemnified. above who was, isor is threatenred to be made a named defendant or respondnt .in a Procee.ing in advance of thefi-m.l disposition of the Proceeding, without gny determjnation as to such, Covered Person'sUiltifate entilement to indemnification under, umpon receipt of a written affirmation by suchCovered Person ,of such Coveted Perqon'gs good faith baliaf that strch P.rson has met thestandard of eonidudt fvecessary for indeiiificatioii untder applic-able lawy- and *this ArtiCleXII anda written undertaking by or on behair of sudh Covered Person to repay all amrioufts so advanced1f it shall ultimately be deternmined ihat such Covered Person is not ent'itled t6 be indemnified bythe Company under this, ALt.te XI Or 'if such indemnification is pro~hibited by app ia.4ble law.SECTION 121.04 Apgearance as a Witness. Notwithstanding any Other provision of thisArticle XII, the Company may pay or ntelibbutse expenseS incurred by a C overed Person inconnection with his or her appearance as a witness or other participatio'l in a Proceeding at atime when he or she is not a named defendant or respondent ininhe proceeding.SECTION 12.05 Non-aexelusivity of Rights;. The indemnification arid advancement andpayment of expetnses provided by ihis Article XII shall not be: deemed exdlusive of any otherrights to which a Covered Person indemnified pursuant to this Article IX miy have or hereafteracquire under.any jaw (common or statutory), provision of this Agreemeoi, any agreement orotherwise.SECTION 12.06. Co6ntract kights. The rights granted pursuant .to tiis .Article XII shallbe deelned to be contract ights, and no -amendment, modification Or repeal ofi this Article XIishall ;have the effect, of limiting or denying gny sucqh rights with respect to actions taken orarising prior to any such amendment, modificatioti or repeal.25US 354747v.2 SECTION 12.07 Insurance. The COnip.aiy may ptrhase .nd maintain intiratice ora.onther arr.angement, at its. expense, on behalf ot its&if, any Covered PeOfi, any. Mahaget,:emIpoyee or agent of the Comp..apany, or any iPerson who serves ofn. behalf of the Companyas .a partner, mian el, inembe r., officer, direotor, employee or agent of any 6ther entity against.any liability, :eXpenso.or logg, Whethe-r or not. fhe Compaqy would hOWv. the power to Indemify-such Person against such liabilit.y.,d -or, logs -vndetthe ptoVisions of his.Article XII.ECTION 12.08 .C(ause. if this Arti~de XIi. or any portion "of this Agreement-s.all be invalid.ated on any gro..und by -any court of competent jurisdiction, then the Company-shall nevertheless indeotnify and .hold harmless evach Covered Person .ndei nnified pursuant tothig; Atfticle X.I .as to eostsý charges and expenses (in-luding attojney' fee.s), ju.dgme nts, finesand amnotnts paid in .ettlement w.ith respeet -to any aotion, sdut ,or proceed4irig, Whether civil,crimtina!,administrative or intveatigative, to the fullest extent permitted bYy anhyapplicable portionof this Article Xi that shall not have been in.validat6d arid io the.fullest extent 'perrmitted byappiicable law.SECTION,1 2,09 Consultation with.Counrsel. The right to d¢pritication conferred inthis Article XII oin any Covered .Persoon ,shall iol~ude- the :right 'to consut.. With- legal counsel,finahiial advisors and accountaiitg selected 'by such Covered Person, and any iact or :omissionsuffered or taken by such Covered Pergon on behalf of the. Company o0 in frtherandce sof -the.iterests ofthe Company in -good faith 'in reliance upon and in accordaince with 'he advice of suchcouns'eli financial advisors or accoun tatis will be full justificition for.any 'such act or omission, andeja h Person will be folly prot.ed n s9 apting or oirmittin g to at-;! provided that suchCounsel, financial advisors or accountants Were stelec.te'd wit reasonable -are.SECTION 12.10 Other Indeniiifieg.(a) The Compay aXcMowledges and agrees that the obli~gation of theCompany unde.r this Agreement to iodepnr.ify or a-dvAnoqe xpenses 1t9 any Covered Petson for thematters covered thereby shiall be tho primnaty sotrce :of indemn.ifiiafioni and 4a4van.eeitt. of sl..hCovered P.er.son in o thin& theewith and any obligation o. the prt Of shy Covered Personunder .any Ohet Thdemrific-atioh Agreement to indefimify Of advane exxpnses to such CoveredPerson shall be seco.ndary to.the 6ompany.'s obligationi an'd,shall be reduced by -aany amount thatthe :Covqrod Person. may tcotect as lindemi'nification or advancement from thg tCompany. If theCompany fails to infd¢ttify or advance- expenges to ak Cove~red Person as :requited ordonteitplated by this. Agreement, .and anry Pearon makes any paynient to s4u6ch Covered Person inresp.ect of inderftification,. or advancenfent of eXpenstes midet any Other .IndmqjficationAgreement on account of such Unpaid'.Aindetiniry Amounts, 's'ch. other PersOn shall -besubrogated to rights 9f such Covered Person under this Agreement in respect :of su~h UnpaidIndemnity Amounts.(b) The Companiy, -as ah Indemnifying Party from .time to time, agrees that, tothe fullest 'extent permnitted by applicable Law; its obligation to indernnty Covered PetsOflsunder this A greement shial iinclde -ay amouts e lpende'd by any other Pe ftn under .,ny QtherIldenifictj~n Ageetet in rs~pe~t ,of..ind~ni.c-,tio-in or z'dv,.ncement of '-expeanses to :anyCoveted Pe'rion iin eonietfibn 'with any Ptraed.ings to the extent such aniounts expeffded bysuch -other Person are .n account of any Ulpaid fndemnitiy Amounts..26US 35'4747-.-2 Vipher Inde~nnzfiadtib .AkkeeMehI" mepans onde or mnor cetiict Or ricl~es ofhicorpoAtiohi, by4a 1-- lmted' liabilty comnpaqy operAtin ,ag~reemont imtdarership;greeenyt an docum t, aOng nsur.an4 pplidcijd.. nt~nd by aiyMember or. Manager or Am~iite jemf poviding r amtoi -IDie qipgs 1 n0iifctno-and advancemfent q6fg.eqisxses Tor any CoVed Pso for amno~ng ote0h.s heSm atr:that are subjec to indenn fieo a advacement of expWne ude is AIepnin.ýaUnaid indemnity Amaugiii~ rs n arrount. %hat the Compipky fol6 Idenfy ora~dvance to 4. ovq.eriP n asrq dbyAte XII f IhsAgremeFofPý pupse f ihis Atddle M the terms "Compay" s 1 hel icude; n predecessor ofthe Company ..and ei(inciuding anycotituent 6f a consti) absrbel bythe Compaý in a .consoidation .or-' r. $erý 4 t rvice -!on behilf of include service as an Officr, Mger' or .employp .of opanpy wh~ch imposesduties on, or involves serqeby, such Of Mngr -rember or employe wjth tres toan employee -befi.¢t pian its a Or beneficiafies; any excise taxes 6sessed on a personwith respect 'Woan. empl.y.e benefit plan AWll Tbe d6emed to be able .ex ses. andact!on by a persOn with respyec" o an dnnployee bnefit plan which : jsn tea-onabtiybelieves to be in the interetet.fh,'e p~ticipj As and beiieftfiaiies of such .-0)a shall be deemed to.be action .not opposed"tot0e bestin terestsof .the **ARTICLE XIIIEXCULPATIONSECTIONR 13 10 Exd-tri"afti. T1the -fult exetpridb plcbl Law noCovered P46rson shal1 be Ccount a ffe ragh. "setoP 0or~srohr Any~~pn -r tos any' & MMembr 'ot ny kss r hbilty.r iSixi 9T.rn a C.. or gnus ion of suchC'rd esf.rela~ting to te :Com:.p~ unessand 6n.y to te txtentthat,"such : or lossioa st frautdARTICLE XIVMISCELLANEOUSSECTION 14.01 Notices..(a) -All .0sts, claims, demnands and other c uiiuriications under orin conn&ti0n With Ws-Afemnt ibe to o madeor !(i) ny Memiber, atconne ~ -19TAnw s...) givyenupn'such Membde's A4-l.s set forf Aon*"k M&6rs Schedle iand'(ii) .i ompany at thefollwin adrese (d in 'aycs o~~hct dress as ifhe ._dressee myfir -om timebto tme designate in 'writinig to the serdeig):Texasi bCm. petitiv ElctrIc ings C yLLC:1601 'BxYiAn~reet27US 354747v.2 (b) All notices, requests, cla.ims, demands and other comm'nicatioris under orin connection with this Agreement shah :be in writing and shall be-deemed effectivelygiven: (i) upO1i personal delivery of delivery by eoqurier to the. party o be notified, (ii)three Business Days after deposit with .the United States PoSt Off.ce, by registered orcettified mlail, rethrn receipt -reqt ested, postage prepaid and addresged as provided inSection 14.0,1.(a) and (iil) one Biusiness Day lfter receipt. of confirmati6n if such -notice issent by facsimjl,.eSECTION 14.02 No Action for Partition.. No Membre shall, have anV right to. maintainany action for partition with respect to any.property of the Company. "SECTION i4.03 Headings and Sections. The descriptive headings-hthis Agreement areinserted for convenience ontly and are .in no way inrtended to describe, interpret, define, or limitthe scope, extent or intent of this Agreement or any provi.s ion of ths Agr~ement, Uýnless theconte.xt requites otherwise, all references in- this Agreement to Sections, Atticles, Exhibits orSchedules shall be deemed to mean and -refer to Se-ctiong, Articlesa, Exhibits br Schedules f or tothis Agreement.SECTION i4.04 Amendments. This Agreement may not be amended, supplemented,modified or restated nor may any provision herein be waived without the .express unanimouswritten of the Board of Mknagers. In addition, any amendment t9 this §Section 14.04 shal!also require the prior written consent of ,ach Member. Any waiver of a.-riy tetm or rcondition.shallnot be costiu.ed as a waitver of any subsequent breach or a subse. tquent waivdr of the same termor condition, or a .waiver of any othet term .or condition of this Agreement. the failure of anyMember to assert any of their respective rights.,hereunder shall not consttute 1a waiver of any ofsuch rights. All Tights anr remedies e xisting uner this Agreemen t are cumulutative. to, and notexclusive of, any rights or remedi"s otherwise available,SECTION 14.05 Binding Effect. Except as othtwise provided in this Agr.emqnit, eVeryc6venafht, terrih Ad provision. of this Agreemeat shall bd binding upon amd inide to the benefit ofthe Members and their respective distributees, heirs, legal represenftives, executors,administrators, Su.cessors and permitted assigns..,SECTION 14.06 Goverttig Law. T-his Agreefmlent Will be governed by, and construedin aceordane with., the laws of the State of Delaware.SECTION. 14.07 Certificate of..ormation. The Certificate of Formation is incorporatedby reference and hereby made a part of this Agreement. In the event of any conflict between theby.. .. ....... .... ... ..y..ade a A greem ent.tweethehICertificate of Formation and this Agreeamett, the provisins of. this Agreement shall govern -tothe extent not contrary to.law.SECTI 14.08 Severabilit. If any term or pirovis of this Agrem :is hel o beSCION !40 A eeaii¥ f ..nq ter Or.rvi.on of ehi Agrmnt i.hltoellegal, -i ...id or unenffor.eble under the present or future laws effective durig the tern of thisAgreement, such term: or provision will be fully severable, and this Agreement Will be c6nstruedand enforced as if such illegal, invdiid or uhrenforceable term or provision had never .comprised apart of this Agreement, and the all other. terms and provisions of this Agreement willHnevertheless remain in full force and effect and will not be affeeted by the illegal, invalid or28US 354147v.2 unenforceable term or provision or by its severance from this Agreeiment. Upon suchdetermination that any term or provision is invalid, illegal or tmnforeeable, the Members -shallnegotiate in good faith to modify this Agreement so as to effeCt the original intent of theMembers as closely as possible in an acceptable manliet in order that the transactions.contemplated by this Agreement are consummated as originally contemplated to the greatestextent possible.SECTION 14.09 Additional Documents and.Acts. Each Member agrees to execute and.~ ~~~ M,- ' ' .. ......" ., gees to "xt an.'deliver such additional documents and instruments and to perform such additional acts as may bereasonably necessary or appropriate to effectuate, carty out and perform[ all of the terms,provisions and conditions of this Agreement and the transactions contemplated hereby.SECTION 14.10 No Third Party Beneficiaries. Except for the provisions of Article XIIrelating to indemnification, this Agreement shall be binding upon and inure sOlely to the benefitof the Members and their respective successors and assigns, nothing hereit, express dr implied,is internded to or shall confer upori any other Person ariy .legal or equitable righ't, interest, claim orbenefit, of any nature whatsoever, under or on account of this Agreement.29US 354747v.2 IN WITNESS WHEREOF, the Member has caused this Agreement to e executed by itsofficer .or other representatives thereunto diuly authorized, as of the. date fitst above written.MEMBER:ENERGY FPUTURE COhIýPEIT!TVEHOLDINGS COMPANYBy:Name:Title.f rock.M. De yterAssistant Secret arySIGNATU.,R.E PAGE .TOFOURTH AMENDED AND RESTATED LIM [TED LIABILrIY COMPANY AGREEMENT OFTEXAS COM PETITIVE tLEcTRIC HOLDINGS COMPANY LLC Schedule AMEMBERS SCHEDULEName, Address and Facsimile... Number of MemberPercentage ofMembership InterestsOwnedE.nergy Future Competitive Holdings Company1601 Bryan Street,Dallas, TX 75201100%US 354747v.2n EMMHBIT AFORM OF JOINDER TOLIMITED LIABILITY COMPANY AGREEMENTTHIS JOINDER to the Fourth Amended and Restated Limited Liability CompanyAgreemaent of Texas Competitive Electric Holdm'gs Company LLC, a Deiawae'limited liabilitycompany (the "Company"), dated as of August -2011, ;s amended or restated from time totime*, by and among ald. the Member(s) of the Company (the "Agreement"), is made and enteredinto as of by and between the Company and _ _ _ (the"Holder'). Capitalized terms used herein but not otherwise defined shall have the meanings setforth in the Agreement.WHEREAS, on the date hereof, the Holder has acquired Mert betship Interestsfrom .......... and the Agreement and the Company require the Holder, as eth holderof such Me.bership nterests, to become a party to the Agreement, anid the H alder agrees to doso in accordance with the terms hereof.NOW, THEREFORE, in consideration of the mutua covenants coniained herein andother good and valuable consideration, the receipt and sufficiency of which are herebyacknowledged, the parties of this Joinder hereby agtee as follows:i. Agreemnent to be. Bourid. The Holder hereby: (a) acknoNyledges that it hasreceived and reviewed a complete copy of' the Agreement -and (b) agreesthat upon execution of this Joinder, it shall become a party to theAgreement nd .i .shall be fully ,bound by, and subject to., all of thecovenants, terms and conditions of :the Agreement as though an originalparty thereto and shall be deemed, and is hereby admniited as, a Metmberfor all purposes -here6f and entitled to. all the rights incidental thereto.2. Members..Schedule. For purposes of the Members Sch lef the address ofthe HoldeK is as follows:[Name)[Address][Faci mile Number].3. Governing Law. This Agreement and the rights of the partieshereun iaer ShAll be iinterpreted in aecordance with the laws of theState of Delaware, and all rights and all remedies be governed bysuch laws.4. Descriptive Headings. The descriptive headings of this Jilnder are insertedfor convenience only and do not cOngtitute a part of this toinder[ iUS 354747v.2 By;N ame:Title:!. .:US 354747v.2I

Enclosure

10 with TXX-13095Additional Documentation forLuminant Holding Company LLCCertificate of MergerCertificates of Name Changes for Merged CompaniesSecond Amended and Restated LLC Agreement of Luminant Holding Company LLCNote: Luminant Holding Company is not required to be audited and EFH currently does notprepare financials for this entity. --ICorporations SectionP.O.Box 13697Austin, Texas 78711-3697Phil WilsonSecretary of StateOffice of the Secretary of StateCERTIFICATE OF MERGERThe undersigned, as Secretary of State of Texas, hereby certifies that a filing instrument mergingLuminant Energy Finance Company LLCForeign Limited Liability Company (LLC)Delaware, USA[Entity not of Record, Filing Number Not Available]Mustang Resources Portfolio Management Company LLCDomestic Limited Liability Company (LLC)[File Number: 800651331 ]IntoLuminant Energy Investment Company LLCForeign Limited Liability .Company (LLC)Delaware, USA[Entity not of Record, Filing Number Not Available]:has been received in this office and has been found to conform to law.Accordingly, the undersigned, as Secretary of State, and by the virtue of the authority vested in thesecretary by law, hereby issues this certificate evidencing the acceptance and filing of the merger onthe date shown below.Dated: 10/01/2007Effective: 10/01/2007Phone: (512)463-5555Prepared by: Lisa SartinCome visit us on the internet at http://www.sos.state.tx.us/Fax: (512) 463-5709TID: 10343Dial: 7-1-1 for Relay ServicesDocument: 1R7i577cOfln1 Corpo'ratians Sct ionPhlW soP.0.Bok .13`097 S ecretary of StateAustn Texa 7871-3j697Office'i of the Secrtr ofA State,' .. -".... .....:": * ."..".. ii: -... ...: ..:" ::.."."-A: .Jr..... ... ......hi. W ils .onSee eta.r of State61liItivs on. teInernet at hufr//w'I~wsbs.'state~tt us/.Phn:52 463-555 Fa:: (52 463570 ial: 7-Il fo -eaSerVicesPrete by Lsa arinTID: 0343 Documen: 1875577900.1.2 Corporations SectionP.O.Box 13697Ir Austin, Texas 78711-3697Phil WilsonSecretary of StateOffice of the Secretary of StateOctober 01, 2007CT Corporation System701 Brazos, Ste. 360Austin, TX 78701 USARE:Luminant Energy Investment Company LLC (File Number: Not Applicable)It has been our pleasure to approve and place on record the filing instrument Ieffecting a merger. Theappropriate evidence of filing is attached for your files. Payment of the filing fee is acknowledged bythis letter.If we can be of further service at any time, please let us know.Sincerely,Corporations SectionBusiness & Public Filings DivisionEnclosurePhone: (512) 463-5555Prepared by: Lisa SartinCome visit us on the internet at http://www.sos.state.tx.us!Fax: (512) 463-5709TID: 10339Dial: 7-1-1 for Relay ServicesDocument: 187557790012

: " : : *FILE.Dinthe Officeof theSectetaly of state of Texas.:: OCT 0 1 7CERTI.ICATE IOF .. ZOO ,~~~~.. .... O.F" .o ...om ration oon .MUSTANG RXSOURCES PORTFOLO MANAGEMENT LUMNNT ENERGY FANCE COMPANY LLC ILUMINANT ENERGY INVETMENT COMPANY LLCPursuant to Section 10.151 of the Texas Business Organizations Code and !Section 1S-209 of theDelaware Limited Liability Company the undersigned hereby execute the following Certificate ofMerger .1. The names of the entities participating in the merger and their riesjctive jurisdictions offormation are as follows:Name of Entity Type of Entiy stateLuminant Energy Investment Company LLC: limited liability company DelawareCompany LLCLuminant Energy Finance Company LL.: limited liability company Delaware' 2 "ii.f ....ID~n : (tb "Srio, wit its2. i[Ljm mat ,Enerj7ýgyonelnn:.op I f,,i We enti), 0 i( I2name being amended to be Comany L:3. ThIe merger will amend the Certificate of Formation of the StUvivot o change its namie to"Luuinant Holding Company LLC.- The merger will terminate the Certificates of Formation of' the other parties to te merger.4. An Agreement and Plan of Merger (the 'Tlan of Merger") has been approved and executed byeach of the parties to the merger. The executed Plan of Merger Is on file at 1601 Bryan Street,DallasL, Texas 75201, the principal place of business of the Survivor. A copy of the Plan ofMerger will be furnished by the Survivor, on written request and without ct, to any: member ofthe parties to the merger.S. The Plan of Merger was duly authorized by all: action required by the Ilaws unbdr which theparties thereto were formed and by their governing documents. i6. The Survivorwill be responsible for payment of any fees and franchise taxem required by law andwill be obligated to pay such fees and franchise taxes if the same am not th'iely paid..[Remainder of Page Left Bla*k Signatue Page toU Follow].Ii * ..! *.........IStep 26.HlOUST0N2112558.

Iiii (.I.I -ISh.qTNWiýMW, the parties heretoLUMINANT ENERGY INVESTMENTCOMANY LLCBy,.Name:Title: []LUMINANT ENERGY FINANCE COMPANYLLCBy:Name: .I A-thave executed this Certificate of Merger as ofMUSTANG RESOURCES'PORTFOLIOMANAGEMENT COMPANY LWBTe..Name: a rrA. JLTitle:!Step 26HOUSTHMI 12568.2 IDel awarePAGE 1ifhe First StateI, HARRIET SMITH WINDSOR, SECRETARY OF STATE OFi THE STATE OFDELAWARE, DO HEREBY CERTIFY THE ATTACHED IS A TRUE AND CORRECTCOPY OF THE CERTIFICATE OF AMENDMENT OF "TXU ENERGY INVESTMENTCOMPANY LLC", CHANGING ITS NAME FROM "TXU ENERGY INVESTMENTCOMPANY LLC" TO "LUMINANT ENERGY INVESTMENT COMPANY LLC", FILEDIN THIS OFFICE ON THE THIRTY-FIRST DAY OF JULY, A.D. 2007, AT10:34 O'CLOCK P.M.Harriet Smith Windsor, Secretary of StateAUTHENTICATION: 5891194DATE: 08-01-073607353 8100070875989 iC1EINMCATZ 09 AWMZIND1WTOCEARTJCATE OF FORKMATO?OFTXCU E?(UGY DTArL UIMVSIh(ENTROK1GERCOMPA1(V TWO LLWKr is lmwWobyardfidat~1. Thmne of tbo wiie jiabity CoMPMn (mheriaft~ Called*"gmcitW lsbfltyc, 1 y") iv FlC EergRetail nveomatMerga~ miWayTwo LLC-2. The cada of fw dmatio ofthelmtetd libilty my is herby mmdedbysUtrihi cut Axt~ol MIST Gmea and by substimtmg to live of inid Auldo fth following ~wA*1eckOFIRST:- Te us= of the firmited liabili compqn famed hereby isTXU Eziqcg Investmeat Compwy I=~Exoewe-dosi July 24, 2003,1{. 3r.,U174AW13o DALLAS 606M7vhegk*e oil Deaiwarsexe"CAU of StatoDivisla21 of Corporat ionsDeliver d 03:56 Ek 07/24/2003Frza 3-3S PM 7OT2A/2003SRV 030485456 -36073S3 FILE .79.e~awarePAGE I2he Pirst State1, Bk1RRIET SMITH WINDSOR, SECRETARY OF STATE OF THE STATE OFDELAWARE, DO HEREBY CERTIFY THE ATTACHED IS A TRUE AND CORRECTCOPY OF THE CERTIFICATE OF AbENDMENT OF "TXU ENERGY RETAILINVESTDMNT IERLR COMPANY TWO LLC-, CHANGING ITS NIm PRM "TXUENERGY RETAIL IM~STMENT MERGER COMPANY TWO LLCI' TO IATXU ENERGYINVESTMENT CCUPANY LLC", FILED IN THIS OFFI-CE ON T"ETWENTY-FOURTH DAY OF JUMY, A.D. 2003, AT 3:56 O'CLOCK P.M.Harre Sitth VWndsor. Secret"r of StateAUTHENTICATION: 25484843607353 8100030485456DATE: 07-25-03 State of DelawareSecretary of StateDivision of Coi' rtionsDelivered 11:04 07/31/2007F=LED 10:34 PM 07/31/2007SRV 070875989 -3607353 F=LECERTIFICATE OF AMENDMENT OFCERTIFICATE OF FORMATION OFTXU ENERGY INVESTMENT COMPANY LLCTXU Energy Investment Company LLC. a limited liability company organizedand existing under and by virtue of the Delaware Limited Liability Company Act (the"Company"), does hereby certify:I. The present name of the Company is TXU Energy Investment CompanyLLC.2. The original Certificate of Formation was filed with the Secretary of Stateof the State of Delaware on December 24, 2002 (the "Certificate of Formation").3. The Certificate of Amendment to the Certificate of Formation amends andrestates the First Article of the Certificate of Formation so that, as amended, said Articleshall read in its entirety as follows:"FIRST: The name of the limited liability company isLuminant Energy Investment Company LLC (the "Company")."IN WITNESS ,WHEREOF, the undersigned has executed this Certificate ofAmendment this _ day of .! t J[ .." 2007.TXU ENERGY INVESTMENTCOMPANY LLC/Jared S. RichardsonAssistant Secretary andAssistant TreasurerDoc #52 STT F DELAWAREFROM RICHARDS, LAYTON & FINGER#8 (TUE) 12. 24' 02 12:15/ST. 4*34#tEP 2DIViSION OF CORPORATIONSFILED 12:30 PM 12/24/2002* 020796621 -3607353CERTIFICATE OF FOIRMATIONOFTXU ENERGY RETAIL INVESTMENT MERGER COMPANY TWO LLCTh1is Certificate of Formation of TXJ Energy Retail Investment Merger Company TwoLLC (the "I ,CC"), dated as of December , 2002, is being duly executed and -filed by Julian H.Baunmann, Jr., as an authorized person, to form a limited liability company under the DelawareLimited Liability Company Act (6 Del, C § 18-101, ei seq.).FIRST: The name of the limited liability company formed hereby is TXU Energy RetailInvestment Merger Company Two LLC.SECOND! The address of the registered office of the LLC in the State 'of Delaware is c/oDelaware Corporate Management, Inc., Suite 1300, 1105 North Market Street, Wilmington, NewCastle County, Delaware 19801THIRD: The name and address of the registered agent for service of process on the LCCin the State of Delaware are Delaware Corporate Management, inc., Suite :1300, 1105 NorthMarket Street, Wilmington, New Castle Cotnty, Delaware 19801.IN WITNESS WHEREOF, the undersigned has executed this Certificate of Formation asof the date first above written.(88826.002002 DALLAS 25317vl SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANYAGREEMENTOFLUMINANT HOLDING COMPANY LLCThis Second Amended and Restated Limited Liability Company Agreement (this"Agreement") of Luminant Holding Company LLC (f/k/a Luminant Energy InvestmentCompany LLC), a Delaware limited liability company (the "Company"), is entered intoby Texas Competitive Electric Holdings Company LLC, a Delaware limited liabilitycompany as the sole member of the Company (the "Member"), for the purpose ofgoverning the affairs of the Company.ARTICLE ILIMITED LIABILITY COMPANYSection 1. 1 Name. The name of the limited liability company is LuminantHolding Company LLC.Section 1.2 Principal Business Office. The principal business office of theCompany shall be located at 500 N. Akard, Dallas, Texas 75201, or such other locationas may hereafter be determined by the Company.Section 1.3 Registered Office. The address of the registered office of theCompany in the State of Delaware is c/o The Corporation Trust Company, 1209 OrangeStreet, Wilmington, New Castle County, Delaware 19801.Section 1.4 Registered Agent. The name of the registered agent of theCompany for service of process on the Company in the State of Delaware is TheCorporation Trust Company.Section 1.5 Foreign Qualifications. An officer of the Company shall execute,deliver and file any certificates (and any amendments and/or restatements thereof)necessary for the Company to qualify to do business in any foreign jurisdiction in whichthe Company may wish to conduct business.Section 1.6 Purpose. The purpose of the Company is to engage in any lawfulbusiness or activity for which a limited liability company may be organized under theDelaware Limited Liability Company Act (the "Act").Section 1.7 Powers. The Company (i) shall have and exercise all powersnecessary, convenient or incidental to accomplish its purposes as set forth in Section 1.6and (ii) shall have and exercise all of the powers and rights conferred upon limitedliability companies formed pursuant to the Act. Section 1.8 Capital Contributions. The Member has made certain capitalcontributions to the Company, and may make such other capital contributions to theCompany as it may determine appropriate in its sole discretion. The provisions of thisAgreement, including this Section 1.8, are intended solely to benefit the Member and, tothe fullest extent permitted by law, shall not be construed as conferring any benefit uponany creditor of the Company (and no such creditor of the Company shall be a third-partybeneficiary of this Agreement) and the Member shall have no duty or obligation to anycreditor of the Company to make any contribution to the Company or to issue any call forcapital pursuant to this Agreement.Section 1.9 Allocation of Profits and Losses. The Company's profits andlosses shall be allocated to the Member; provided, however, that no allocation of any lossto the Member shall create any obligation on the Member to make any capitalcontribution to the Company to offset such loss (or otherwise), the Member having noobligation to make any such capital contribution, as provided in Section 1.8 above.Section 1.10 Distributions. Distributions in any form, including cash or otherassets, shall be made to the Member at the times and in the aggregate amountsdetermined by the Board of Managers. Notwithstanding any provision to the contrarycontained in this Agreement, the Company shall not be required to make a distribution toany Member on account of its interest in the Company if such distribution would violateSection 18-607 of the Act or any other applicable law.Section 1.11 .Other Business. The Member and any Affiliate of the Membermay engage in or possess, an interest in other busines.s .ventures (unconnected with theCompany) of every kind and description, independently or with others. The Companyshall not have any rights in or to such ihdependent ventures or the income or profitstherefrom by virtue of this Agreement.When used in this Agreement, "Affiliate" means, with. respect to anyindividual, corporation, partnership, joint venture, limited liability company, limitedliability partnership, association, joint-stock company, trust, unincorporated organization,or other organization, whether or not a. legal entity, or any governmental authority("Person"), any other Person directly or indirectly °Controlling or Controlled by or .underdirect or indirect common Control with such Person, and "Control" means the possession,directly or indirectly, or the power to direct or cause the direction, of the management orpolicies of a Person, Whether through the ownership of voting securities or generalpartnership or managing member interests, by contract or otherwise. "Controlling" and"Controlled" have correlative meanings. Without limiting the generality of theforegoing, a Person shall be deemed to Control any other Person in which it owns,directly or indirectly, a majority of the ownership interests.2 ARTICLE IIMANAGEMENTSection 2.1 Board of Managers.(a) In accordance with Section 18-402 of the Act, managementof the Company shall be vested in a Board of Managers. The Board of Managers shallhave the power to do any and all acts necessary, convenient or incidental to or for thefurtherance of the, purposes described herein, including all powers, statutory or otherwise,possessed by managers of a limited liability company under the. laws of the State ofDelaware. The number of managers shall be determined from time to time by theMember or the resolution of the Board of Managers. The Member hereby designates six(6) as the number of Managers and hereby designates David A. Campbell, Frederick M.Goltz, Scott Lebovitz, Michael MacDougall, Richard Meserve and John F. Young as theManagers.(b) Vacancies on the Board of Managers from whatever causeshall be filled by the remaining managers or by the Member. Managers shall serve untilthey resign or are removed. Managers may be removed with or without cause by theMember.(c) The Board of Managers of the Company may holdmeetings, both regular and special, within or outside the State of Delaware. Regularmeetings of the Board of Managers may be held without notice at such times and at suchplaces as shall from time to time be determined by the Board of Managers. Specialmeetings of the Board of Managers may be called by the Chairman of the Board, if any,,or by the President on not less than twenty-four (24) hours notice to each Manager bytelephone, facsiinile, mail, telegram or any other means of communication, and specialmeetings shall be called by thePresident or the Secretary in like manner and with likenotice upon the written request of any one or more of the Managers.(d) At all meetings of the Board of Managers, a majority of theManagers shall constitute a quorum for the transaction. of business and, except asotherwise provided in any other provision of this Agreement, the act of a majority of theManagers present at any meeting at which there is a quorum shall be the act of the Boardof Managers. If a quorum shall not be present at any meeting of the Board of Managers,the Managers present at such meeting may adjourn the meeting from time to. time,without notice other than announcement at the meeting, until a quorum shall be present.Any action required or permitted to be taken at any meeting of the Board of Managers orof any committee thereof may be taken without a meeting if at least a majority of themembers of the Board of Managers or such -committee, as the case may be, consentthereto in writing, and the writing or writings are filed with the minutes of proceedings ofthe Board of Managers or such. committee and a copy of such writing or writings ispromptly furnished to any member. of the Board of Mahagers or such committee, as thecase may be, who did not sign such writing or writings.3 (e) No contract or transaction between the Company (or itssubsidiaries) and one or more of its Managers or officers, or between the Company (or itssubsidiaries) and any other company, corporation, partnership, association, or otherorganization in which one or more of its Managers or officers, are directors, managers,partners or officers (or serve in a similar capacity), or have a financial interest, shall bevoid or voidable solely for this reason, or solely because theManager or officer is presentat or participates in the meeting of the Board of Managers or committee which authorizesthe contract or transaction, or solely because any such Manager's or officer's votes arecounted for such purpose, if:(i) The material facts as to the Manager'.s or officer'srelationship or interest and as to the contract or transaction are disclosed or areknown to the Board of Managers or the committee, and the Board of Managers orcommittee in good faith authorizes the contract or transaction by the affirmativevotes of a majority of the disinterested Managers, even though the disinterestedManagers be less than a quorum; or(ii) ' The material facts as to the Manager's or officer'srelationship or interest and as to the contract or transaction are disclosed or areknown to the Member, and the contract or transaction is specifically approved ingood faith by the Member; or(iii) The contract or transaction is fair as to theCompany as of the time it is authorized, approved or ratified, by the Board ofMembers, a committee or the Member.(f) Interested Managers may be counted in determining thepresence of a quorum at a meeting of the Board of Managers or of a committee whichauthorizes the contract or transaction.(g) The Managers, or any committee designated by the Boardof Managers, may participate in a meeting of the Board of Managers, or of suchcommittee, by means of telephone conference or similar communications equipment, andsuch participation in a meeting shall constitute presence in person at such meeting. If allthe participants are participating by telephone conference or similar communicationsequipment, the meeting shall be deemed to be held at the principal place of business ofthe Company.(h) The Board of Managers may designate one or morecommittees, with each committee to consist of one or more of the Managers of theCompany. The Board of Managers may designate one or more Managers as alternatemembers of any committee, who may replace any absent or disqualified member at anymeeting of such committee. Any such committee, to the extent provided in the resolutionof the Board of Managers, shall have and may exercise all of the powers and authority ofthe Board of Managers in the management of the business and affairs of the Company.Each committee shall have such name as may be determined from time to time byresolution adopted by the Board of Managers. Each committee shall keep regular minutes4 of its meetings and report the same to the Board of Managers when required by the Boardof Managers.Section 2.2 Officers; Delegation. The Company shall have such officers andemployees as are designed within this Agreement or as subsequently designed by theBoard of Managers. The Board of Managers may, from time to time as they deemadvisable, appoint officers and assign titles (including, without limitation, President, VicePresident, Secretary, and Treasurer) to any such person. Unless the Board of Managersdecides otherwise, if the title is one commonly used for officers of a business corporationformed under the Delaware General Corporation Law, the assignment of such title shallconstitute the delegation to such person of the authorities and duties that are normallyassociated with that office. Any delegation pursuant to this Section 2.2 may be revokedat any time by the Member or Board of Managers.Section 2.3 Limited Liability. Except as otherwise expressly provided by theAct, the debts, obligations and liabilities of the Company, whether arising in contract, tortor otherwise, shall be the debts, obligations and liabilities solely of the Company, andneither any Member nor any Manager, officer or employee of the Company shall be.obligated personally for any such debt, obligation or liability of the Company solely byreason of being a Member, Manager, officer or employee of the Company.ARTICLE IIIM[EýMERSSection 3.1. Members. The Member is the sole member of the Company. Themailing address of the Member is: 1601 Bryan St., Dallas, Texas 75201. The Companyhas issued all of the limited liability company interests in the Company to the Member.Additional members may be admitted only by written amendment of this Agreement,executed by the Member.Section 3.2 Assignments. The Member may assign in whole or in part itslimited liability company interests in the Company. If the Member transfers all of itsinterests pursuant to this Section 3.2 the transferee shall be admitted to the Company as amember of the Company upon its execution of an instrument signifying its agreement tobe bound by the terms and conditions of this Agreement, which instrument may be acounterpart signature page to this Agreement. Such admission shall be deemed effectiveimmediately prior to the transfer, and, immediately following such admission, thetransferor Member shall cease to be a member of the Company.Section 3.3 Admission of Additional Members. One or more additionalmembers of the Company may be admitted to the Company with the written consent ofthe Member.Section 3.4 Resignation. A Member may resign from the Company with thewritten consent of all of the Members. If a Member is permitted to resign pursuant to thisSection 3.4, an additional member of the Company shall be admitted to the Company,5 subject to Section 3.3, upon its execution of an instrument signifying its agreement to bebound by the terms and conditions of this Agreement, which instrument may be acounterpart signature page to this Agreement. Such admission shall be deemed effectiveimmediately prior to the resignation, and, immediately following such admission, theresigning Member shall cease to be a member of the Company.ARTICLE IVDISSOLUTIONSection 4.1. Events of Dissolution.(a) The Company shall be dissolved, and its affairs shall bewound up upon the first to occur of the following: (i) the retirement, resignation ordissolution of the last remaining Member or the occurrence of any other event whichterminates the continued membership of the last remaining Member in the Companyunless the business of the Company is continued in a manner permitted by the Act or (ii)the entry of a decree of judicial dissolution under Section 18-802 of the Act.(b) Except to the extent set forth in Section 4.1(a) of thisAgreement, the occurrence of any event that terminates the continued membership of aMember in the Company shall not cause the dissolution of the Company, and, upon theoccurrence of such an event, the business of the Company shall continue withoutdissolution.(c) The bankruptcy (as defined in Section 18-101(1) of theAct) of the Member shall not cause the Member to cease to be a member of the Companyand upon the occurrence of such an event, the business of the Company shall continuewithout dissolution.(d) In the event of dissolution, the Company shall conduct only'such activities as are necessary to wind up its affairs (including the sale of the assets ofthe Company in an orderly manner), and the assets of the Company shall be applied inthe manner, and in the order of priority, set forth in Section 18-804 of the Act.ARTICLE VINDEMNIFICATIONSection 5.1. Right to hzdemnification. Subject to the limitations and conditionsas provided in this Article V, each person (for purposes of this Article V, the term"person" shall include only natural persons) who was or is made a party or is threatenedto be made a party to or is involved in any threatened, pending or completed action orother proceeding, whether civil, criminal, administrative, arbitrative or investigative, orany appeal in such a proceeding or any inquiry or investigation that could lead to such aproceeding (hereafter a "Proceeding"), by reason of the fact that such person, or a person6 of whom he or she is the legal representative, is or was a Manager or officer, or whilesuch Manager or officer is or was serving at the request of the Company as a member,director, manager, officer, partner, venturer, proprietor,. trustee, employee, agent orsimilar functionary of another foreign or domestic corporation, limited liability company,joint venture, partnership, trust, sole proprietorship, employee benefit plan or otherenterprise, shall be indemnified by the Company to the fullest extent permitted byapplicable law, as the same exists or may hereafter be amended against judgments,penalties (including excise and similar taxes and punitive damag6s), fines, settlementsand reasonable expenses (including, without limitation, attorneys', fees) actually incurredby such person in connection with such Proceeding and indemnification under thisArticle V shall continue as to a person who has ceased to serve in the capacity whichinitially entitled such person to indemnity hereunder. It is expressly acknowledged thatthe indemnification provided in this Article V could involve indemnification fornegligence or under theories of strict liability.Section 5.2. Limitation on Indemnification. Subject to applicable law,notwithstanding any language in this Article V to the contrarY, in no event shall anyperson be entitled to indemnification pursuant to this Article V if it is established oradmitted:(a) in a final judgment of a court of competent jurisdiction; or(b) by such person in any affidavit, sworn statement, pleaarrangement or other cooperation with any government or regulatory authority that:(i) the person's acts or omissions that would otherwisebe subject to indemnification under this Article V were committed in bad faithor were the result of active and deliberate dishonesty; or(ii) such person personally gained a profit to which heor she was not legally entitled with an action or omission that would oiherwisebe subject to indemnification pursuant to this Article V.Section 5.3. Advancement of Expenses. Th4 right to indemnification conferredin this Article V shall include the right to be paid or reimbursed by the Company thereasonable expenses incurred by a person of the type entitled to be indemnified abovewho was, is or is threatened to be made a named defendant or respondent in a Proceedingin advance of the final disposition, of the Proceeding, without any determination as tosuch person's ultimate entitlement to indemnification under, upon receipt of a writtenaffirmation by such person of such person's good faith belief that such person has met thestandard of conduct necessary for indemnification under applicable law and this Article Vand a written undertaking by or on behalf of such person to repay all amounts soadvanced if it shall ultimately be determined that such person is not entitled to beindemnified by the Company Under this Article V or if such indemnification is prohibitedby applicable law.7 Section 5.4. Indemnification of Employees and Agents. The Company byadoption of a resolution by the Board of Managers, may indemnify and advance expenses toan employee or agent of tlhe Company to the same extent and subject to the same con-ditions under which it may indemnify and advance expenses to any Manager or officerunder this Article V; and the Company, by adoption of a resolution by the Board ofManagers, may indemnify and advance. expenses to any person who is not or was not aManager, officer, employee or agent of the, Company but who is or was serving at therequest of the Company as a member, manager, director, officer, partner, venturer,proprietor, trustee, employee, agent or similar functionary of another foreign or domesticlimited liability company, partnership, corporation, partnership, joint venture, soleproprietorship, trust, employee benefit plan or other enterprise against any liabilityasserted against such person and incurred by such person in such a capacity or arising outof such person's status as such to the same extent and subject to the same conditions thatthe Company may indemnify and pay any advance expenses to any Manager or officerunder this Article V.Section 5.5. Appearance as a Witness. Notwithstanding any other provision ofthis Article V, the Company may pay or reimburse expenses incurred by a Manager,officer, employee, agent or other person in connection with his or her appearance as aWitness or other participation in a Proceeding at a time when he or she is not a nameddefendant or respondent in the Proceeding.Section 5.6. Non-exclusivity of Rights. The indemnification and advancementand payment of expenses provided by this Article V shall not be deemed exclusive of anyother rights to -which a Manager, officer or other person indemnified pursuant to thisArticle V may have or hereafter acquire under any law (common or statutory), provisionof this Agreement, any agreement or otherwise.Section 5.7. Contract Rights. The rights granted pursuant to this Article Vshall be deemed to be contract rights, and no amendment, modification or repeal of thisArticle V shall have the effect of limiting -or denying any such rights with respect toactions taken or Proceedings arising prior to any such amendment, modification or repeal.Section 5.8. hIsurance. The Company may purchase and maintain insuranceor another arrangement, at its expense, on behalf of itself or any person who is or wasserving as a Manager, officer, employee or agent of the Company, or is or was serving atthe request of the Company as a member, manager, director, officer, partner, venturer,proprietor, trustee, employee, agent or similar functionary of another foreign or domesticlimited liability company, partnership, corporation, joint venture, sole proprietorship,trust, employee benefit plan or other enterprise, against any liability, expense or loss,whether or not the Company would have the power to indemnify such person againstsuch liability, expense or loss under the provisions of this Article V.Section 5.9. Savings Clause. If this Article V or any portion of this Agreementshall be invalidated on any ground by any court of competent jurisdiction, then theCompany shall nevertheless indemnify and hold harmless each Manager, officer or anyother person indemnified pursuant to this Article V as to costs, charges and expenses8 (including attorneys' fees), judgments, fines and amounts paid in settlement with respectto any action, suit or proceeding, whether civil, criminal, administrative or investigative,to the fullest extent permitted by any applicable portion of this Article V that shall nothave been invalidated and to the fullest extent permitted by applicable law.For purposes of this Article V, the terms "Company" shall include anypredecessor of the Company and any constituent entity (including any constituent of aconstituent) absorbed by the Company in a consolidation or merger; the terms "otherenterprise" shall include any corporation, limited liability company, partnership, jointventure, trust or employee benefit plan; service "at the request of the Company" shallinclude service as an officer, Manager, Member or employee of the Company whichimposes duties on, or involves services by, such officer, Manager, Member or employeewith respect to an employee benefit plan, its participants or beneficiaries; any excisetaxes assessed on a person with respect to an employee benefit plan shall be deemed to beindemnifiable expenses; and action by a person with respect to an employee benefit planwhich such person reasonably believes to be in the interest of the participants andbeneficiaries of such plan shall be deemed to be action not opposed to the best interests ofthe Company.ARTICLE VIGENERAL PROVISIONSSection 6.1 Amendment. This Agreement may not be modified, altered,supplemented or amended except by written instrument signed by the Member.Section 6.2 Applicable Law. This Agreement shall be construed in accordancewith and governed by the laws of the state of Delaware.Section 6.3 Benefits of Agreement; No Third-Party Rights. None of theprovisions of this Agreement shall be for the benefit of or enforceable by any creditor ofthe Company or by any creditor of any Member. Nothing in this Agreement shall bedeemed to create any right in any person (other than persons indemnified pursuant toArticle V) not a party hereto, and this Agreement shall not be construed in any respect tobe a contract in whole or in part for the benefit of any third person.Section 6.4 Severability of Provisions. Each provision of this Agreement shallbe considered severable and if for any reason any provision or provisions herein aredetermined to be invalid, unenforceable or illegal under any existing or future law, suchinvalidity, unenforceability or illegality shall not impair the operation of or affect thoseportions of this Agreement which are valid, enforceable and legal.Section 6.5 Entire Agreement. This Agreement constitutes the entireagreement of the Member with respect to subject matter hereof.9 IN WITNESS WHEREOF, the undersigned, intending to be legally boundhereby, has duly executed this Agreement effective as of September 12, 2008.MEMBER:TEXAS COMPETITIVE ELECTRICHOLDINGS COMPANY LLCBy: __ _ _ __ _ _ _risa M. WinstonSecretary10

Enclosure

11 with TXX-13095Additional Documentation forLuminant Generation Company LLCFiling Instruments for conversion and formation of Luminant Generation Company LLCAmended and Restated LLC Agreement of Luminant Generation Company LLCConsolidated Financial Statements for Luminant Generation Company LLC Corporations SectionP.O.Box 13697Austin, Texas 78711-3697Phil WilsonSecretary of StateOffice of the Secretary of StateOctober 08, 2007CT Corporation System701 Brazos, Ste. 360Austin, TX 78701 USARE: Luminant Generation Company LLCFile Number: o008.1 1216It has been our pleasure to approve and place on record the filing instrument effecting a conversion.The appropriate evidence is attached for your files. Payment of the filing fee is acknowledged by thisletter.If we can be of further service at any time, please let us know.Sincerely,Corporations SectionBusiness & Public Filings Division(512) 463-5555EnclosurePhone: (512) 463-5555Prepared by: Lisa SartinCome visit us on the internet at http://www.sos.srate.tx.us/Fax: (512) 463-5709TID: 10337Dial: 7-1-1 for Relay ServicesDocument: 188527620002 Corporations SectionP.O.Box 13697Austin, Texas 787] 1-3697Phi] WilsonSecretary of StateOffice of the Secretary of StateCERTIFICATE OF CONVERSIONThe undersigned, -as Secretary of State of Texas, hereby certifies that a filing instrument forTXU Generation Company LPFile Number: 800025435.Converting it toLuminant Generation Company LLCFile Number: 800881216has been received in this office and has been found to'conform to law. ACCORDINGLY, theundersigned, as Secretary of State, and by virtue of the authority vested in the secretary by law, herebyissues this certificate evidencing the acceptance and filing of the conversion on the date shown below.Dated: 10/08/2007Effective: 10/09/2007 08:30 amPhil WilsonSecretary of StatePhone: (512) 463-5555Prepared by: Lisa SartinCome visit us on the internet at http://www. sos.state. ix. usiFax: (512) 463-5709MTID: 10340Dial: 7- I-I for Relay ServicesDocument: 188527620002 Corporations SectionP.O.Box 13697Austin, Texas 78711-3697Phil WilsonSecretary of StateOffice of the Secretary of StateCERTIFICATE OF FILINGOFLuminant Generation Company LLCFile Number: 800881216The undersigned, as Secretary of State of Texas, hereby certifies that a Certificate of Formation for theabove named Domestic Limited Liability Company (LLC) has been received in this office and has beenfound to conform to the applicable provisions of law.ACCORDINGLY, the undersigned, as Secretary of State, and by virtue of the authority vested in thesecretary by law, hereby issues this certificate evidencing filing effective on the date shown below.The issuance of this certificate does not authorize-the use of a name in this state in violation of the rightsof another under the federal Trademark Act of 1946, the Texas trademark law, the Assumed Business orProfessional Name Act, or the common law.Dated: 10/08/2007Effective: 10/09/2007 08:30 am..Phil WilsonSecretary of StatePhone, (512) 463-5555Prepared by: Lisa SartinCome visit us on the internet at http.'//www.sos.siate.tx.usiFax: (512) 463-5709TID: 10306Dial: 7- I-I for Relay ServicesDocument: 188533600001 Foirm.642* (I~evIO~i66Reunin duplicate to:Sceayof StaecP.O. 13ox 136973Qstsn,1X 78711-369732463-5ý55P.4 1;,463-57091fi ngOFee: 6ee b~atiducosThis spaeereseved forofflcetof afSaed OCetfcteof CQPive' on.~fLimfited Liabfl"t Co .wpany CloaosedlThe name of the converting limited partnerhp is:"rXt PpE!ýon Company LPThe juisdictionof fornation of the lmited partnership is: Tuns *.*Thebdjat ofrmation of the limited part eip is .: Toyeib&6, 20"""The file, umibcr, if any, issued tD the limited pazttcsihip by the soef*sy f state -is:* 80OQ)2435T7* lited partnersUp named above is converting to a limited liability company. The name of theUnited liability company is:Luminat Gemn=aio CMiany LLCTh li"ite liabilit "compy willhefaed under the o s0. The'plan of ..Vd~eptm qoiýfcorn Yioe xW agchcadz dwfe~ft sio w a wwabeeaprZ. Insteadof a hitng fteplan ofconverion; the limited partnesip ceatifics to the followingstatenients:A signed plan of cmversion is on file at the principal place of business of the litd partaership, theconverting entity. The addrs of the principal place of business of the limited partnership is:1601 Bzyan Stret Dallas IX USA 7201Rrw~cr AfctrAdMwsams COAMOY 27 OA signed plan of conversion will be on file after the conversion at the principal place of business ofthe limited liability company, the converied entity. The address of-the principal place of business ofthe limited liability company is:1601Boryw Slt Dallas .T.X USA .75201S*.w. or &-, by 2, , C.A copy of the plan of conversion will be finiished on wriften request without c -by the rientity before the conversion or by the converted entity after tie conversion to any owner or member ofthe.converting or converted ctity.Fonm6t2 4 0 The converted entity is a Texas Bumited liability comrpany. Mw catificate of fration of theTan lmimed liability coupany is attched to this cedificate either as an attachment or exhmbit to thePlan.-0oi as an attachnnt or cdubit to this denificaze of conversion If the pla" has not,cetificate of con.Version..The plan of conversion has been approved as required by the laws of tbe jurisdiction of oromation andthe govemmn documets of the converting entity.P., -RýRVR MiSA. 0 This docanent becomes.effective when dh document is accepted and filed by the secretary of~."0. This'do=cum t becomes at a late date, which is not moe than nety (90) days the date of .gning. Tedcnayodeffecveate s8: .m. CentralrM.IeoOn er9,2007..... a T doum.ent takes effect upin the c ,ocwrae of the fuu.re oVen or'fact. othei ta the.imasage Of time- The 9(P day after the date of .signing in _ _ __ _ _ _ __ _ _ _The fllowing event or fact will. canse ie document to tdk effect in the manner derc'ie below-F .Thr unerigne slgs tWilom' .nt91bjdM to h penalties p m posed by law for the submission of animateriafly Ihise or frariduintt iirstnmme-zDate:aSimla=r =an tide qf ub2: pgrWUA o behalfof hCoaverbug enity 4ia&iii4Fem 642S CERTICATE OF FOIRMATONOF LUMINANT GR TI nON COMPANY LLC(1) The name of the filing entity being formed is L.miýnnt Generation Company LLC (the Companyr).(2) The Company will be a Texas limited liability company.(3) The purpose for which the Company is formed is for the transaction of any and all lawful purposesfor which a Ilmited liability company may be organized under the Texas Business Organizations(4) The period of duration of the Company is perpetuaL or until the earlier dissokion of die Companyin accordance with the provisions of the Company's limited liability company agreement(5) The address of the Company's initial registered office is 350 N. St. Paul Stweet, Suite 2900, Dallas,Texas 75201. The anae of the Company's initial registered agent at such address is CT CorporationSystem.(6) The Company will be managed by manager. The names and addresses of the initial managen e asfollows: David A. Campbell. 1601 Bryan Street, Dallas,.Texas 75201, M.S. Greene, 1601 BryanStreet. Dallas. Texas 75201 and C. John Wilder, 1601 Bryan Street. Dallas, Texas 75201.(7) The Company is being fomned under a plan of conversioti The converting entity (the "ConvetingEntity") is TXU Generation Company LP. a Texas limited partneri*. The Converting Bntity wasformed in the State of Texas on November 6,2001. Tbe address of the Converting Entity is !601Bryan Streer, Dallasý Texas 75201.(8) The formation of the Company wig be effective at 830 a.m. Central Time on October 9. 2007.Executed ths ..I day of 0 r. 2007.LUMINANT GBNERATION COMPANY LLC4wL.~ArS'seep 79&DALLASV42M2 AMENDED AND RESTATEDLIMITED LIABILITY COMPANY AGREEMENTOFLUMINANT GENERATION COMPANY LLCThis Amended and Restated Limited Liability Company Agreement (this "Agreement")of Luminant Generation Company LLC (the "Company"), dated this 15th day of September,2011, is entered into by Luminant Holding Company LLC, a Delaware limited liability company,as the sole member of the Company (the "Member"), for the purpose of governing the affairs ofthe Company.WHEREAS, the Member entered into a Limited Liability Company Agreement for theCompany on October 9, 2007 (the "Original Agreement"); andWHEREAS, this Agreement amends and restates the Original Agreement in all respects,and constitutes the governing instrument of the Company.ARTICLE ILIMITED LIABILITY COMPANYSection 1.1 Name. The name of the limited liability company is Luminant GenerationCompany LLC.Section 1.2 Principal Business Office. The principal business office of the Companyshall be located at 1601 Bryan Street, Dallas, Texas 75201, or such other location as mayhereafter be determined by the Company.Section 1.3 Registered Office. The address of the registered office of the Company inthe State of Texas is c/o CT Corporation System, 50 N. St. Paul Street, Suite 2900, Dallas, Texas75201.Section 1.4 Registered Agent. The name of the registered agent of the Company forservice of process on the Company in the State of Texas is CT Corporation System.Section 1.5 Foreign Qualifications. An officer of the Company shall execute, deliverand file any certificates (and any amendments and/or restatements thereof) necessary for theCompany to qualify to do business in any foreign jurisdiction in which the Company may wishto conduct business.Section 1.6 Purpose. The purpose of the Company is to engage in any lawful businessor activity for which a limited liability company may be organized under the Texas BusinessOrganizations Code, as amended from time to time (the "Code").Section 1.7 Powers. The Company (i) shall have and exercise all powers necessary,convenient or incidental to accomplish its purposes as set forth in Section 1.6 and (ii) shall haveand exercise all of the powers and rights conferred upon limited liability companies formedpursuant to the Code.US 357382v.3 Section 1.8 Capital Contributions. The Member has made certain capital contributionsto the Company, and may make such other capital contributions to the Company as it maydetermine appropriate in its sole discretion. The provisions of this Agreement, including thisSection 1.8, are intended solely to benefit the Member and, to the fullest extent permitted by law,shall not be construed as conferring any benefit upon any creditor of the Company (and no suchcreditor of the Company shall be a third-party beneficiary of this Agreement) and the Membershall have no duty or obligation to any creditor of the Company to make any contribution to theCompany or to issue any call for capital pursuant to this Agreement.Section 1.9 Allocation of Profits and Losses. The Company's profits and losses shallbe allocated to the Member; provided, however, that no allocation of any loss to the Membershall create any obligation on the Member to make any capital contribution to the Company tooffset such loss (or otherwise), the Member having no obligation to make any such capitalcontribution, as provided in Section 1.8 above.Section 1.10 Distributions. Distributions in any form, including cash or other assets,shall be made to the Member at the times and in the aggregate amounts determined by the Boardof Managers. Notwithstanding any provision to the contrary contained in this Agreement, theCompany shall not be required to make a distribution to any Member on account of its interest inthe Company if such distribution would violate the Code or any other applicable law.Section 1.11 Other Business. The Member and any Affiliate of the Member mayengage in or possess an interest in other business ventures (unconnected with the Company) ofevery kind and description, independently or with others. The Company shall not have any rightsin or to such independent ventures or the income or profits therefrom by virtue of thisAgreement.When used in this Agreement, "Affiliate" means, with respect to any individual,corporation, partnership, joint venture, limited liability company, limited liability partnership,association joint-stock company, trust, unincorporated organization, or other organization,whether or not a legal entity, or any governmental authority ("Person"), any other Person directlyor indirectly Controlling or Controlled by or under direct or indirect common Control with suchPerson, and "Control" means the possession, directly or indirectly, or the power to direct orcause the direction, of the management or policies of a Person, whether through the ownership ofvoting securities or general partnership or managing member interests, by contract or otherwise."Controlling" and "Controlled" have correlative meanings. Without limiting the generality of theforegoing, a Person shall be deemed to Control any other Person in which it owns, directly orindirectly, a majority of the ownership interests.ARTICLE IIMANAGEMENTSection 2.1 Board of Managers.(a) Management of the Company shall be vested in a Board of Managers. TheBoard of Managers shall have the power to do any and all acts necessary, convenient or2 incidental to or for the furtherance of the purposes described herein, including all powers,statutory or otherwise, possessed by managers of a limited liability company under the laws ofthe State of Texas. The number of managers shall be determined from time to time by theMember or the resolution of the Board of Managers. The Member hereby designates David A.Campbell and Paul M. Keglevic as the Managers.(b) Vacancies on the Board of Managers from whatever cause shall be filledby the remaining managers or, if there be none, by the Member. Managers shall serve until theyresign or are removed. Managers may be removed with or without cause by the Member.(c) The Board of Managers of the Company may hold meetings, both regularand special, within or outside the State of Texas. Regular meetings of the Board of Managersmay be held without notice at such times and at such places as shall from time to time bedetermined by the Board of Managers. Special meetings of the Board of Managers may be calledby the Chairman of the Board, if any, or by the President on not less than twenty-four (24) hoursnotice to each Manager by telephone, facsimile, mail, telegram or any other means ofcommunication, and special meetings shall be called by the President or the Secretary in likemanner and with like notice upon the written request of any one or more of the Managers.(d) At all meetings of the Board of Managers, a majority of the Managersshall constitute a quorum for the transaction of business and, except as otherwise provided in anyother provision of this Agreement, the act of a majority of the Managers present at any meetingat which there is a quorum shall be the act of the Board of Managers. If a quorum shall not bepresent at any meeting of the Board of Managers, the Managers present at such meeting mayadjourn the meeting from time to time, without notice other than announcement at the meeting,until a quorum shall be present. Any action required or permitted to be taken at any meeting ofthe Board of Managers or of any committee thereof may be taken without a meeting if at least amajority of the members of the Board of Managers or such committee, as the case may be,consent thereto in writing, and the writing or writings are filed with the minutes of proceedingsof the Board of Managers or such committee and a copy of such writing or writings is promptlyfurnished to any member of the Board of Managers or such committee, as the case may be, whodid not sign such writing or writings.(e) No contract or transaction between the Company (or its subsidiaries) andone or more of its Managers or officers, or between the Company (or its subsidiaries) and anyother company, corporation, partnership, association, or other organization in which one or moreof its Managers or officers, are directors, managers, partners or officers (or serve in a similarcapacity), or have a financial interest, shall be void or voidable solely for this reason, or solelybecause the Manager or officer is present at or participates in the meeting of the Board ofManagers or committee which authorizes the contract or transaction, or solely because any suchManager's or officer's votes are counted for such purpose, if-(i) The material facts as to the Manager's or officer's relationship orinterest and as to the contract or transaction are disclosed or are known to the Board ofManagers or the committee, and the Board of Managers or committee in good faithauthorizes the contract or transaction by the affirmative votes of a majority of thedisinterested Managers, even though the disinterested Managers be less than a quorum; or3 (ii) The material facts as to the Manager's or officer's relationship orinterest and as to the contract or transaction are disclosed or are known to the Member,and the contract or transaction is specifically approved in good faith by the Member; or(iii) The contract or transaction is fair as to the Company as of the timeit is authorized, approved or ratified, by the Board of Managers, a committee or theMember.(f) Interested Managers may be counted in determining the presence of aquorum at a meeting of the Board of Managers or of a committee which authorizes the contractor transaction.(g) The Managers, or any committee designated by the Board of Managers,may participate in a meeting of the Board of Managers, or of such committee, by means oftelephone conference or similar communications equipment, and such participation in a meetingshall constitute presence in person at such meeting. If all the participants are participating bytelephone conference or similar communications equipment, the meeting shall be deemed to beheld at the principal place of business of the Company.(h) The Board of Managers may, with the unanimous approval of theManagers, designate one or more committees, with each committee to consist of one or more ofthe Managers of the Company. The Board of Managers may, with the unanimous approval of theManagers, designate one or more Managers as alternate members of any committee, who mayreplace any absent or disqualified member at any meeting of such committee. Any suchcommittee, to the extent provided in the resolution of the Board of Managers, shall have and mayexercise all of the powers and authority of the Board of Managers in the management of thebusiness and affairs of the Company. Each committee shall have such name as may bedetermined from time to time by resolution adopted by the Board of Managers. Each committeeshall keep regular minutes of its meetings and report the same to the Board of Managers whenrequired by the Board of Managers.Section 2.2 Officers; Delegation. The Company shall have such officers andemployees as are designed within this Agreement or as subsequently designed by the Board ofManagers. The Board of Managers may, from time to time as they deem advisable, appointofficers and assign titles (including, without limitation, President, Vice President, Secretary, andTreasurer) to any such person. Unless the Board of Managers decides otherwise, if the title is onecommonly used for officers of a business corporation formed under the Code, the assignment ofsuch title shall constitute the delegation to such person of the authorities and duties that arenormally associated with that office. Any delegation pursuant to this Section 2.2 may be revokedat any time by the Member or Board of Managers.Section 2.3 Limitation of Liability. Except as otherwise expressly provided by theCode, the debts, obligations and liabilities of the Company, whether arising in contract, tort orotherwise, shall be the debts, obligations and liabilities solely of the Company, and no (a)Member or Affiliate of a Member or their respective members, officers, directors, employees,agents, stockholders or partners, (b) Manager, officer, employee or agent of the Company or (c)Person who serves on behalf of the Company as a partner, manager, member, officer, director,4............ .!= employee or agent of any other entity (collectively, with all such Persons that are or have been,at any time from and after the date of formation of the Company, among the Persons listed insubsections (a), (b) or (c), the "Covered Persons") shall be obligated personally for any suchdebt, obligation or liability of the Company solely by reason of being a Covered Person.(a) The failure of the Company to observe any formalities or requirementsrelating to the exercise of its powers or management of the Company or its affairs under' thisAgreement or the Code shall not be grounds for imposing personal liability on any CoveredPerson for liabilities of the Company.(b) Such protections from personal liability shall apply to the fullest extentpermitted by applicable law, as the same exists or may hereafter be amended (but, in the case ofany such amendment, only to the extent that such amendment permits the Company to providegreater or broader indemnification rights than such law permitted the Company to provide priorto such amendment).(c) To the extent that, at law or in equity, a Covered Person or any otherperson has duties (including fiduciary duties) to the Company or to another Member or Manageror to another person that is a party to or is otherwise bound by this Agreement, those duties arehereby eliminated to the fullest extent allowed under Texas law and the Code. All liabilities forbreach of contract and breach of duties (including fiduciary duties) of a Covered Person or anyother person to the Company or to another Member or Manager or any other person that is aparty to or is otherwise bound by this Agreement are hereby eliminated to the fullest extentallowed under Texas law and the Code. The elimination of duties and liabilities set forth in thisSection 2.3(c) shall be deemed to apply from and after the formation of the Company.ARTICLE IllIMEMBERSSection 3.1 Sole Member. The Member is the sole member of the Company. Themailing address of the Member is: 1601 Bryan Street, Dallas, Texas 75201. The Company hasissued all of the limited liability company interests in the Company to the Member. Additionalmembers may be admitted only by written amendment of this Agreement, executed by theMember.Section 3.2 Assignments. The Member may assign in whole or in part its limitedliability company interests in the Company. If the Member transfers all of its interests pursuantto this Section 3.2 the transferee shall be admitted to the Company as a member of the Companyupon its execution of an instrument signifying its agreement to be bound by the terms andconditions of this Agreement, which instrument may be a counterpart signature page to thisAgreement. Such admission shall be deemed effective immediately prior to the transfer, and,immediately following such admission, the transferor Member shall cease to be a member of theCompany.Section 3.3 Admission of Additional Members. One or more additional members of theCompany may be admitted to the Company with the written consent of the Member.5 Section 3.4 Resignation. A Member may resign from the Company with the writtenconsent of all of the Members. If a Member is permitted to resign pursuant to this Section 3.4, anadditional member of the Company shall be admitted to the Company, subject to Section 3.3,upon its execution of an instrument signifying its agreement to be bound by the terms andconditions of this Agreement, which instrument may be a counterpart signature page to thisAgreement. Such admission shall be deemed effective immediately prior to the resignation, and,immediately following such admission, the resigning Member shall cease to be a member of theCompany.ARTICLE IVDISSOLUTIONSection 4.1 Events of Dissolution.(a) The Company shall be dissolved, and its affairs shall be wound up uponthe first to occur of the following: (i) the retirement, resignation or dissolution of the lastremaining Member or the occurrence of any other event which terminates the continuedmembership of the last remaining Member in the Company unless the business of the Companyis continued in a manner permitted by the Code or (ii) the entry of a decree of judicial dissolutionunder the Code.(b) Except to the extent set forth in Section 4.1(a) of this Agreement, theoccurrence of any event that terminates the continued membership of a Member in the Companyshall not cause the dissolution of the Company, and, upon the occurrence of such an event, thebusiness of the Company shall continue without dissolution.(c) The bankruptcy of the Member shall not cause the Member to cease to bea member of the Company and upon the occurrence of such an event, the business of theCompany shall continue without dissolution.(d) In the event of dissolution, the Company shall conduct only such activitiesas are necessary to wind up its affairs (including the sale of the assets of the Company in anorderly manner), and the assets of the Company shall be applied in the manner, and in the orderof priority, set forth in the Code.ARTICLE VINDEMNIFICATIONSection 5.1 Right to Indemnification. Subject to the limitations and conditions asprovided in this Article V, each Covered Person who was or is made a party or is threatened tobe made a party to or is involved in any threatened, pending or completed action or otherproceeding, whether civil, criminal, administrative, arbitrative or investigative, or any appeal insuch a proceeding or any inquiry or investigation that could lead to such a proceeding (hereaftera "Proceeding"), by reason of any actions or omissions or alleged acts or omissions of suchCovered Person relating to the Company, shall be indemnified by the Company to the fullestextent permitted by applicable law, as the same exists or may hereafter be amended against6 judgments, penalties (including excise and similar taxes and punitive damages), fines,settlements and reasonable expenses (including, without limitation, attorneys' fees) (allcollectively the "Indemnification Amounts") actually incurred by such Covered Person at thetime any such Indemnification Amounts are incurred in connection with such Proceeding.Indemnification under this Article V shall continue as to a Covered Person who has ceased toserve in the capacity which initially entitled such Covered Person to indemnity hereunder.Without limiting the generality of the foregoing, it is expressly acknowledged that theindemnification provided in this Article V could involve indemnification for negligence or undertheories of strict liability.Section 5.2 Limitation on Indemnification. Subject to applicable law, notwithstandingany language in this Article V to the contrary, in no event shall any Person be entitled toindemnification pursuant to this Article V if it is established or admitted either (a) in a finaljudgment of a court of competent jurisdiction or (b) by such Person in any affidavit, swornstatement, plea arrangement or other cooperation with any government or regulatory authoritythat the Person's acts or omissions that would otherwise be subject to indemnification under thisArticle V constituted fraud.Section 5.3 Advancement of Expenses. The right to indemnification conferred in thisArticle V shall include the right to be paid or reimbursed by the Company the reasonableexpenses incurred by a Covered Person of the type entitled to be indemnified above who was, isor is threatened to be made a named defendant or respondent in a Proceeding in advance of thefinal disposition of the Proceeding, without any determination as to such Covered Person'sultimate entitlement to indemnification under, upon receipt of a written affirmation by suchCovered Person of such Covered Person's good. faith belief that such Covered Person has met thestandard of conduct necessary for indemnification under applicable law and this Article V and awritten undertaking by or on behalf of such Covered Person to repay all amounts so advanced ifit shall ultimately be determined that such Covered Person is not entitled to be indemnified bythe Company under this Article V or if such indemnification is prohibited by applicable law.Section 5.4 Appearance as a Witness. Notwithstanding any other provision of thisArticle V, the Company may pay or reimburse expenses incurred by- a Covered Person inconnection with his or her appearance as a witness or other participation in a Proceeding at atime when such Covered Person is not a named defendant or respondent in the Proceeding.Section 5.5 Non-exclusivity of Rights. The indemnification and advancement andpayment of expenses provided by this Article V shall not be deemed exclusive of any other rightsto which a Covered Person indemnified pursuant to this Article V may have or hereafter acquireunder any law (common or statutory), provision of this Agreement, any agreement or otherwise.Section 5.6 Contract Rights. The rights granted pursuant to this Article V shall bedeemed to be contract rights, and no amendment, modification or repeal of this Article V shallhave the effect of limiting or denying any such, rights with respect to actions taken orProceedings arising prior to any such amendment, modification or repeal.Section 5.7 Insurance. The Company may purchase and maintain insurance or anotherarrangement, at its expense, on behalf of itself, any Covered Person, any Manager, officer,7 employee or agent of the Company, or any Person who serves on behalf of the Company as apartner, manager, member, officer, director, employee or agent of any other entity against anyliability, expense or loss, whether or not the Company would have the power to indemnify suchPerson against such liability, expense or loss under the provisions of this Article V.Section 5.8 Savings Clause. If this Article V or any portion of this Agreement shall beinvalidated on any ground by any court of competent jurisdiction, then the Company shallnevertheless indemnify and hold harmless each Covered Person indemnified pursuant to thisArticle V as to costs, charges and expenses (including attorneys' fees), judgments, fines andamounts paid in settlement with respect to any action, suit or proceeding, whether civil, criminal,administrative or investigative, to the fullest extent permitted by any applicable portion of thisArticle V that shall not have been invalidated and to the fullest extent permitted by applicablelaw.Section 5.9 Consultation with Counsel. The right to indemnification conferred in thisArticle V on any Covered Person shall include the right to consult with legal counsel, financialadvisors and accountants selected by such Covered Person, and any act or omission suffered ortaken by such Covered Person on behalf of the Company or in furtherance of the interests of theCompany in good faith in reliance upon and in accordance with the advice of such counsel,financial advisors or accountants will be full justification for any such act or omission, and eachsuch Covered Person will be fully protected in so acting or omitting to act; provided that suchcounsel, financial advisors or accountants were selected with reasonable care.Section 5.10 Other Indemnities.(a) The Company acknowledges and agrees that the obligation of theCompany under this Agreement to indemnify or advance expenses to any Covered Person for thematters covered thereby shall be the primary source of indemnification and advancement of suchCovered Person in connection therewith and any obligation on the part of any Covered Personunder any Other Indemnification Agreement to indemnify or advance expenses to such CoveredPerson shall be secondary to the Company's obligation and shall be reduced by any amount thatthe Covered Person may collect as indemnification or advancement from the Company. If theCompany fails to indemnify or advance expenses to a Covered Person as required orcontemplated by this Agreement, and any Person makes any payment to such Covered Person inrespect of indemnification or advancement of expenses under any Other IndemnificationAgreement on account of such Unpaid Indemnity Amounts, such other Person shall besubrogated to the rights of such Covered Person under this Agreement in respect of such UnpaidIndemnity Amounts.(b) The Company, as an indemnifying party from time to time, agrees that, tothe fullest extent permitted by applicable law, its obligation to indemnify Covered Persons underthis Agreement shall include any amounts expended by any other Person under any OtherIndemnification Agreement in respect of indemnification or advancement of expenses to anyCovered Person in connection with any Proceedings to the extent such amounts expended bysuch other Person are on account of any Unpaid Indemnity Amounts.8 "Other Indemnification Agreement' means one or more certificate or articles ofincorporation, by-laws, limited liability company operating agreement, limited partnershipagreement and any other organizational document, and insurance policies maintained by anyMember or Manager or Affiliate thereof providing for, among other things, indemnification ofand advancement of expenses for any Covered Person for, among other things, the same mattersthat are subject to indemnification and advancement of expenses under this Agreement."Unpaid Indemnity Amounts" means any amount that the Company fails to indemnify oradvance to a Covered Person as required by Article V of this Agreement.For purposes of this Article V, the term "Company" shall include any predecessor of theCompany and any constituent entity (including any constituent of a constituent) absorbed by theCompany in a consolidation or merger; the term service "on behalf of the Company" shallinclude service as an officer, Manager, Member or employee of the Company which imposesduties on, or involves services by, such officer, Manager, Member or employee with respect toan employee benefit plan, its participants or beneficiaries; any excise taxes assessed on a Personwith respect to an employee benefit plan shall be deemed to be indemnifiable expenses; andaction by a Person with respect to an employee benefit plan which such Person reasonablybelieves to be in the interest of the participants and beneficiaries of such plan shall be deemed tobe action not opposed to the best interests of the Company.ARTICLE VIEXCULPATIONSection 6.1 Exculpation. To the fullest extent permitted by applicable law, no CoveredPerson shall be liable or accountable in damages or otherwise to the Company or to any Memberfor any loss or liability arising from any act or omission of such Covered Person relating to theCompany unless, and only to the extent that, such act or omission constituted fraud.ARTICLE VIIGENERAL PROVISIONSSection 7.1 Amendment. This Agreement may not be modified, altered, supplementedor amended except by written instrument signed by the Member.Section 7.2 Applicable Law. This Agreement shall be construed in accordance withand governed by the laws of the State of Texas.Section 7.3 Benefits of Agreement; No Third-Party Rights. None of the provisions ofthis Agreement shall be for the benefit of or enforceable by any creditor of the Company or byany creditor of any Member. Nothing in this Agreement shall be deemed to create any right inany Person (other than Covered Persons) not a party hereto, and this Agreement shall not beconstrued in any respect to be a contract in whole or in part for the benefit of any third person.Section 7.4 Severability of Provisions. Each provision of this Agreement shall beconsidered severable and if for any reason any provision or provisions herein are determined to9 be invalid, unenforceable or illegal under any existing or future law, such invalidity,unenforceability or illegality shall not impair the operation of or affect those portions of thisAgreement which are valid, enforceable and legal.Section 7.5 Entire Agreement. This Agreement constitutes the entire agreement of theMember with respect to subject matter hereof.[Remainder of Page Intentionally Left Blank; Signature Page to Follow]10 IN WITNESS WHEREOF, the undersigned, intending to be legally bound hereby, hasduly executed this Agreement effective as of the 15th day of September, 2011.MEMBER:LUMINANT HOLDING COMPANY LLCBy:BettyvAehaAssistant SecretarySIGNATURE PAGE TOAMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OFLUM[NANT GENERATION COMPANY LLC LUMINANT GENERATION COMPANY LLCAN ENERGY FUTURE HOLDINGS CORP. ENTERPRISECONSOLIDATED FINANCIAL STATEMENTSAT AND FOR THE YEAR ENDED DECEMBER 31, 2012ANDINDEPENDENT AUDITORS' REPORT GLOSSARYWhen the following terms and abbreviations appear in the text of this report, they have the meanings indicatedbelow.Adjusted EBITDACPNPCAdjusted EBITDA means EBITDA adjusted to excludenoncash items, unusual items and other adjustments allowableunder certain debt arrangements of TCEH. See the definitionof EBITDA below. Adjusted EBITDA and EBITDA are notrecognized terms under US GAAP and, thus, are non-GAAPfinancial measures. We do not intend for Adjusted EBITDA(or EBITDA) to be an alternative to net income as a measure ofoperating performance or an alternative to cash flows fromoperating activities as a measure of liquidity or an alternative toany other measure of financial performance presented inaccordance with US GAAP. Additionally, we do not intend forAdjusted EBITDA (or EBITDA) to be used as a measure offree cash flow available for management's discretionary use, asthe measure excludes certain cash requirements such as interestpayments, tax payments and other debt service requirements.Because not all companies use identical calculations, ourpresentation of Adjusted EBITDA (and EBITDA) may not becomparable to similarly titled measures of other companies.Comanche Peak Nuclear Power Company LLC, which wasformed by subsidiaries of Generation (holding an 88% equityinterest) and of Mitsubishi Heavy Industries Ltd. (MHI)(holding a 12% equity interest) for the purpose of developingtwo new nuclear generation units and obtaining a combinedoperating license from the NRC for the unitsearnings (net income) before interest expense, income taxes,depreciation and amortizationEnergy Future Competitive Holdings Company, a direct,wholly-owned subsidiary of EFH Corp. and the direct parent ofTCEH, and/or its subsidiaries, depending on contextEnergy Future Holdings Corp., a holding company, and/or itssubsidiaries, depending on context, whose major subsidiariesinclude TCEH and OncorEnergy Future Intermediate Holding Company LLC, a direct,wholly-owned subsidiary of EFH Corp. and the direct parent ofOncor Electric Delivery Holdings Company LLC, which is thedirect parent of OncorUS Environmental Protection AgencyElectric Reliability Council of Texas, Inc., the independentsystem operator and the regional coordinator of variouselectricity systems within TexasEBITDAEFCHEFH Corp.EFIHEPAERCOTi ERISAGAAPGenerationIRSLIBORLuminant EnergyLuminant HoldingMergerEmployee Retirement Income Security Act of 1974, asamendedgenerally accepted accounting principlesLuminant Generation Company LLC, a direct, wholly-owned subsidiary of Luminant Holding that engages inelectricity generation in TexasUS Internal Revenue ServiceLondon Interbank Offered Rate, an interest rate at whichbanks can borrow funds, in marketable size, from otherbanks in the London interbank marketLuminant Energy Company LLC, a direct, wholly-ownedsubsidiary of Luminant Holding that engages in wholesaleenergy sales and purchases as well as commodity riskmanagement and trading activities, all largely in TexasLuminant Holding Company LLC, a direct, wholly-ownedsubsidiary of TCEH and parent of Generation, Mining andLuminant EnergyThe transaction referred to in the Agreement and Plan ofMerger, dated February 25, 2007, under which TexasEnergy Future Holdings Limited Partnership agreed toacquire EFH Corp., which was completed on October 10,2007Luminant Mining Company LLC, a direct, wholly-ownedsubsidiary of Luminant Holding, which primarily mineslignite used to fuel Generation's facilities but also mineslignite owned by Alcoa, Inc. and Sandow Power CompanyLLC used to fuel Sandow Units 4 and 5Moody's Investors Services, Inc. (a credit rating agency)US Nuclear Regulatory CommissionOncor Electric Delivery Company LLC, a direct majority-owned subsidiary of Oncor Electric Delivery HoldingsCompany LLC and an indirect subsidiary of EFH Corp.,and/or its consolidated bankruptcy-remote financingsubsidiary, Oncor Electric Delivery Transition BondCompany LLC, depending on context, that is engaged inregulated electricity transmission and distribution activitiesother postretirement employee benefitsThe purchase method of accounting for a businesscombination as prescribed by US GAAP, whereby the costor "purchase price" of a business combination, includingthe amount paid for the equity and direct transaction costsare allocated to identifiable assets and liabilities (includingintangible assets) based upon their fair values. The excessof the purchase price over the fair values of assets andliabilities is recorded as goodwill.MiningMoody'sNRCOncorOPEBpurchase accountingii S&PSandowTCEHTCEH Demand NotesTCEH FinanceStandard & Poor's Ratings Services, a division of theMcGraw-Hill Companies Inc. (a credit rating agency)Refers to lignite coal-fueled generation facilities SandowUnits 4 and 5 located in Rockdale, Texas and owned bysubsidiaries of Luminant Holding. The assets andoperations relating to Sandow Unit 4 are consolidated intoGeneration's financial statements, while the assets andoperations relating to Sandow Unit 5 are not consolidatedinto Generation's financial statements.Texas Competitive Electric Holdings Company LLC, adirect, wholly-owned subsidiary of EFCH and an indirectsubsidiary of EFH Corp., and/or its subsidiaries, dependingon context, that are engaged in electricity generation andwholesale and retail energy markets activities, and whosemajor subsidiaries include Luminant Holding and TXUEnergy Retail Company LLCRefers to certain loans from TCEH to EFH Corp. in theform of demand notes to finance EFH Corp. debt principaland interest payments and, until April 2011, other generalcorporate purposes of EFH Corp., that are guaranteed on asenior unsecured basis by EFCH and EFIH.TCEH Finance, Inc., a direct, wholly-owned subsidiary ofTCEH, formed for the sole purpose of serving as co-issuerwith TCEH of certain debt securitiesRefers, collectively, to TCEH's and TCEH Finance's10.25% Senior Notes due November 1, 2015 and 10.25%Senior Notes due November 1, 2015, Series B(collectively, TCEH 10.25% Notes) and TCEH's andTCEH Finance's 10.50%/11.25% Senior Toggle Notes dueNovember 1, 2016 (TCEH Toggle Notes).Refers, collectively, to the TCEH Term Loan Facilities,TCEH Revolving Credit Facility, TCEH Letter of CreditFacility and, until it expired on December 31, 2012, TCEHCommodity Collateral Posting Facility. See Note 7 toFinancial Statements for details of these facilities.TCEH's and TCEH Finance's 11.5% Senior Secured Notesdue October 1, 2020Refers, collectively, to TCEH's and TCEH Finance's 15%Senior Secured Second Lien Notes due April 1, 2021 andTCEH's and TCEH Finance's 15% Senior Secured SecondLien Notes due April 1, 2021, Series B.Texas Commission on Environmental QualityUnited States of Americavariable interest entityTCEH Senior NotesTCEH Senior Secured FacilitiesTCEH Senior Secured NotesTCEH Senior Secured Second LienNotesTCEQUSVIEiii INDEPENDENT AUDITORS' REPORTTo the Board of Managers of Luminant Generation Company LLCDallas, TexasWe have audited the accompanying consolidated financial statements of Luminant Generation Company LLC (an indirect whollyowned subsidiary of Energy Future Holdings Corp.) and subsidiaries (the "Company"), which comprise the consolidated balance sheetas of December 31, 2012, and the related statements of consolidated loss, cash flows, and membership interests for the year thenended, and the related notes to the consolidated financial statements.Management's Responsibility for the Consolidated Financial StatementsManagement is responsible for the preparation and fair presentation of these consolidated financial statements in accordance withaccounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenanceof internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from materialmisstatement, whether due to fraud or error.Auditors' ResponsibilityOur responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit inaccordance with auditing standards generally accepted in the United States of America. Those standards require that we plan andperform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from materialmisstatement.An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financialstatements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatementof the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internalcontrol relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design auditprocedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of theCompany's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness ofaccounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating theoverall presentation of the consolidated financial statements.We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.OpinionIn our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position ofLuminant Generation Company LLC and subsidiaries as of December 31, 2012, and the results of their operations and their cash flowsfor the year then ended in accordance with accounting principles generally accepted in the United States of America.Emphasis of MatterLuminant Generation Company LLC and its indirect parent company, Texas Competitive Electric Holdings Company LLC("TCEH"), continue to experience net losses. TCEH has substantial indebtedness and has significant cash interest requirements.Luminant Generation Company LLC and certain of its subsidiaries guarantee a substantial amount of TCEH's indebtedness. TCEH'sability to satisfy its obligations in October 2014, which include maturities of $3.8 billion of TCEH Term Loan Facilities, is dependentupon the completion of one or more actions discussed in Note 1 of the consolidated financial statements.Dallas, TexasMarch 27, 2013iv LUMINANT GENERATION COMPANY LLCSTATEMENT OF CONSOLIDATED LOSS(millions of dollars)Year EndedDecember 31, 2012Operating revenues (Note 14) ............................................................................................. $ 2,072Fuel and purchased power costs ........................................................................................ (852)Net loss from commodity hedging activities (Notes 11 and 14) ......................................... (67)Operating costs ................................................................................................................... (679)Depreciation and amortization ............................................................................................ (901)Selling, general and administrative expenses ..................................................................... (117)Other income (Note 6) ....................................................................................................... 2Other deductions (Note 6) .................................................................................................. (105)Interest income (Note 14) ................................................................................................... 327Interest expense .................................................................................................................. 7)Loss before income taxes .................................................................................................... (337)Income tax benefit (Note 5) ................................................... 118N et loss ............................................................................................................................ (2 19)Net income attributable to noncontrolling interests (Notes 2 and 9) .................................. (19Net loss attributable to Generation ..................................................................................... $ (23_See Notes to Financial Statements.1 LUMINANT GENERATION COMPANY LLCSTATEMENT OF CONSOLIDATED CASH FLOWS(millions of dollars)Year EndedDecember 31, 2012Cash flows -operating activities:N et loss .................................................................................................................................. $ (2 19)Adjustments to reconcile net loss to cash provided by operating activities:Depreciation and amortization ........................................................................................... 1,048Deferred income tax benefit, net ........................................................................................ (144)Unrealized net loss from mark-to-market valuations of commodity positions(Notes 11 and 14) ......................................................................................................... ..... 45Unsettled charges related to pension plan actions (Note 12) ....................................... ..... .95Asset retirement and mining reclamation liability accretion expense (Note 15) ................ 26Asset impairment (Notes 6 and 15) .................................................................................. .5Stock-based compensation expense .............................................................................. .. 3Changes in operating assets and liabilities:Affi liate accounts receivable/payable -net .................................................................. (12)Trade accounts receivable ........................................................................................ .. 6Inventories .................................................................................................................... (4)Trade accounts payable ................................................................................................. (50)M ining reclamation liability (Note 15) ......................................................................... (68)Accrued taxes other than income ................................................................................. (82)Accumulated deferred income taxes ............................................................................ (73)Other -net assets ......................................................................................................... (47)Other -net liabilities ..................................................................................................... (5)Cash provided by operating activities ....................................................................... 524Cash flows -financing activities:Paym ent of incom e tax-related note payable to Oncor (Note 14) ..........................................Settlem ent of reim bursem ent agreem ents w ith Oncor (N ote 14) ...........................................Repaym ents of long-term debt (Note 7) ................................................................................Sale/leaseback of equipm ent ..................................................................................................Contributions from parent (Note 9) .......................................................................................Contributions from noncontrolling interests (Note 9) ............................................................Other -net .............................................................................................................................Cash used in financing activities ...................................................................................Cash flows -investing activities:Advances from parent/affi liates (Note 14) .............................................................................Capital expenditures ..............................................................................................................N uclear fuel purchases ...........................................................................................................Proceeds from sales of nuclear decommissioning trust fund securities (Note 15) .................Investments in nuclear decommissioning trust fund securities (Note 15) ..............................Purchase of right to use certain computer-related assets from affiliate (Notes 3 and 14) ......Other -net .............................................................................................................................Cash used in investing activities ...................................................................................N et change in cash and cash equivalents ..................................................................................Cash and cash equivalents -beginning balance .......................................................................Cash and cash equivalents -ending balance ............................................................................See Notes to Financial Statements.(20)(159)(9)610474(67)219(460)(198)106(122)(18)15(458)(1)22 LUMINANT GENERATION COMPANY LLCCONSOLIDATED BALANCE SHEET(millions of dollars)December 31, 2012ASSETSCurrent assets:C ash and cash equivalents ..................................................................................................... $ 1Accounts receivable from affiliates (Note 14) ........................................................................ 159Advances to parent/affiliates (Note 14) .......................................................................... ....... 25Trade accounts receivable -net ..................................................................................... ....... 21Inventories (N ote 15) .............................................................................................................. 241Commodity derivative contract assets (Note 11) .................................................................. .3Income tax receivable from EFH Corp. (Note 14) ......................................................... ....... 15Other current assets ....................................................................................................... ....... 50T otal current assets ............................................................................................................ 5 15Property, plant and equipment -net (Note 15) ......................................................................... 12,693Advances to parent/affiliates (Note 14) .................................................................................... 4,668G oodw ill (N ote 3) ..................................................................................................................... 1,873Investm ents (N ote 15) ............................................................................................................... 703Identifiable intangible assets -net (Note 3) .............................................................................. 293Other noncurrent assets ........................................................................................................... 22T ota l assets ......................................................................................................................... 20.767LIABILITIES AND MEMBERSHIP INTERESTSCurrent liabilities:Trade accounts payable .......................................................................................................... $ 155Long-term debt due currently (Note 7) .................................................................................. 7Accumulated deferred income taxes (Note 5) ................................................................ ....... 25Mining reclamation liability (Note 15) .................................................................................. 54Commodity derivative contract liabilities (Note 11) ............................................................. 29Other current liabilities .......................................................................................................... 61T otal current liabilities ....................................................................................................... 33 1Commodity derivative contract liabilities (Note 11) ......................................................... ....... 17Long-term debt, less amounts due currently (Note 7) ...................................................... ....... 46Asset retirement and mining reclamation liability, less amounts due currently (Note 15) ........ 425Deferred credit related to unfavorable contracts -net (Note 15) .............................................. 619Accumulated deferred income taxes (Note 5) ........................................................................... 3,690Other noncurrent liabilities and deferred credits (Note 15) ....................................................... 1,450T ota l liab ilities ................................................................................................................... 6,578Commitments and Contingencies (Note 8)Generation membership interests .............................................................................................. 13,381Noncontrolling interests in consolidated affiliates .................................................................... 808Total membership interests (Note 9) ......................................................................................... 14,189Total liabilities and membership interests .........................................................................Consolidated Balance Sheet continued on page 4.3 LUMINANT GENERATION COMPANY LLCCONSOLIDATED BALANCE SHEET (CONTINUED)(millions of dollars)The following asset and liability amounts relate to consolidated VIEs, which are included in the consolidatedbalance sheet presented on page 3. See Note 2 for additional information.December 31, 2012Assets:Current assets:Cash and cash equivalents ...........................................Trade accounts receivable -net ...................................Inventories ...................................................................Comm odity derivative contract assets .........................Other current assets .....................................................Total current assets ..............................................Property, plant and equipm ent -net ................................Advances to parent/affi liates .......................................Investm ents .................................................................Identifiable intangible assets -net ...............................Other noncurrent assets ...............................................Total assets ...........................................................Liabilities:Current liabilities:S I Trade accounts payable ......................................................8 Long-term debt due currently .............................................42 Accumulated deferred income taxes ...................................2 M ining reclamation liability ...............................................5 Accrued taxes other than income ........................................58 Accrued income taxes payable to EFH Corp. (a) ...............Other current liabilities .......................................................Total current liabilities ................................................$ 4459543313129739553378112321737Long-term debt, less amounts due currently .......................Mining reclamation liability, less amounts due currently...Accumulated deferred income taxes ...................................Other noncurrent liabilities and deferred credits .................Total liabilities .....................................................(a) Income taxes payable to EFH Corp. is netted with income taxes receivable from EFH Corp. on the consolidated balance sheet.Noncontrolling interests in consolidated affiliate totaling $808 million are comprised of consolidated VIE netassets totaling $800 million, from above, and net assets totaling $8 million not included above as such amountrepresents affiliate receivables/payables between the VIE and Generation that are eliminated in consolidation.See Notes to Financial Statements.4 LUMINANT GENERATION COMPANY LLCSTATEMENT OF CONSOLIDATED MEMBERSHIP INTERESTS(millions of dollars)Year EndedDecember 31. 2012Membership interests:Capital accounts:Balance at beginning of period ....................................................................................N et lo ss ....................................................................................................................Noncash dividend to parent (Note 9) .......................................................................Equity contribution from parent (Note 9) ................................................................Gain on settlement of reimbursement agreement with Oncor (Note 14) .................Effects of employee stock-based incentive compensation plans .............................Generation membership interests at end of period ........................................................Noncontrolling interests in consolidated affiliates (Notes 2 and 9):Capital accounts:Balance at beginning of period ....................................................................................N et inco m e ...............................................................................................................Investment in consolidated affiliates by noncontrolling interests ............................Effects of employee stock-based incentive compensation plans .............................Noncontrolling interests in subsidiaries at end of period ..............................................Total membership interests at end of period: .....................................................................$ 15,011(238)(1,500)1042213,3817811971808See Notes to Consolidated Financial Statements.5 LUMINANT GENERATION COMPANY LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIESDescription of BusinessLuminant Generation Company LLC ("Generation"), a Texas limited liability company, is an indirect,wholly-owned subsidiary of EFH Corp. engaged in the generation of electricity in Texas utilizing nuclear,lignite/coal and natural gas/oil-fueled generation units. We are a direct, wholly-owned subsidiary of LuminantHolding. Luminant Holding is a direct, wholly-owned subsidiary of TCEH, and TCEH is a direct, wholly-owned subsidiary of EFCH. EFCH is a direct, wholly-owned subsidiary of EFH Corp. Our assets include twonuclear-fueled generation units (Comanche Peak), seven lignite/coal-fueled generation units (Martin Lake,Monticello and Sandow Unit 4) and 22 natural gas/oil-fueled generation units at several locations.References in this report to "we," "our," "us," and "the company" are to Generation and/or itsconsolidated subsidiaries/affiliates as apparent in the context. See "Glossary" for definition of terms andabbreviations.Pursuant to the terms of the TCEH Senior Secured Facilities and TCEH Senior Secured Notes, we(along with certain other subsidiaries of TCEH) provide the following credit support for TCEH's obligationsunder such indebtedness: an unconditional joint and several guarantee that is secured on a first-priority basis bysubstantially all of our current and future tangible and intangible assets. Pursuant to the terms of the TCEHSenior Secured Second Lien Notes, we (along with certain other subsidiaries of TCEH) provide the followingcredit support for TCEH's obligations under such indebtedness: an unconditional joint and several guarantee thatis secured on a second-priority basis by substantially all of our current and future tangible and intangible assets.In addition, pursuant to the terms of the TCEH Senior Secured Facilities, TCEH Senior Secured Notes andTCEH Senior Secured Second Lien Notes, all of the capital stock of TCEH and its subsidiaries (includingGeneration) is pledged as collateral, subject to certain exceptions, to secure TCEH's obligations under suchindebtedness (on a first-priority basis in the case of the TCEH Senior Secured Facilities and TCEH SeniorSecured Notes and on a second-priority basis in the case of the TCEH Senior Secured Second Lien Notes).Under the terms of the TCEH Senior Notes, we (along with certain other subsidiaries of TCEH) provide creditsupport in the form of an unconditional joint and several unsecured guarantee for TCEH's obligations under suchindebtedness. See Liquidity Considerations immediately below and Note 7 for more information.Liquidity ConsiderationsWe and our indirect parent, TCEH, have been and are expected to continue to be adversely affected bythe sustained decline in natural gas prices and its effect on wholesale and retail electricity prices in ERCOT.Further, the remaining natural gas hedges that TCEH entered into when forward market prices of natural gaswere significantly higher than current prices will mature in 2013 and 2014. These market conditions challengethe long-term profitability and operating cash flows of our business and TCEH's ability to support its significantinterest payments and debt maturities, and could adversely impact TCEH's and our ability to obtain additionalliquidity and TCEH's ability to service, refinance and/or extend the maturities of its outstanding debt, much ofwhich is guaranteed by Generation.6 Note 7 provides the details of TCEH's short-term borrowings and long-term debt that we guarantee,including principal amounts and maturity dates, as well as details of recent debt activity, including the three-yearextension of the portion of the TCEH Revolving Credit Facility that would have expired in 2013. At December31, 2012, TCEH had $1.2 billion of cash and cash equivalents and $183 million of available capacity under itsletter of credit facility. Based on the current forecast of cash from operating activities, which reflects currentforward market electricity prices, projected capital expenditures and other cash flows, including the settlement ofthe TCEH Demand Notes by EFH Corp., TCEH expects that it will have sufficient liquidity to meet itsconsolidated (including our) obligations until October 2014, at which time a total of $3.8 billion of the TCEHTerm Loan Facilities matures. TCEH's ability to satisfy this obligation is dependent upon the implementation ofone or more of the actions described immediately below.TCEH continues to consider and evaluate possible transactions and initiatives to address its highlyleveraged balance sheet and significant cash interest requirements and may from time to time enter intodiscussions with its lenders and bondholders with respect to such transactions and initiatives. These transactionsand initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to andextensions of debt obligations and debt for equity exchanges or conversions, including exchanges or conversionsof its debt into equity of EFH Corp., EFCH, TCEH and/or any of their subsidiaries. These actions could result inholders of TCEH debt instruments not recovering the full principal amount of those obligations. See Note 8 fordiscussion of guarantees of mining reclamation obligations.Basis of PresentationOur consolidated financial statements have been prepared in accordance with US GAAP. Allintercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financialstatements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequentevents have been evaluated through March 27, 2013, the date these consolidated financial statements wereissued.We consolidate the assets, liabilities and results of operations of Mining and CPNPC, both of whichqualify as variable interest entities ("VIEs") under consolidations accounting standards. Mining owns, leasesand operates facilities for surface mining and recovery of lignite fuel primarily for our benefit. CPNPC isobtaining licensing for and is developing two new nuclear generation units. We are the primary beneficiary ofthe operations of each of these affiliate entities, and the 12% noncontrolling interest in CPNPC and all of theearnings of Mining are reported as noncontrolling interests in the consolidated financial statements. See Notes 2and 9.Use of EstimatesPreparation of the financial statements requires estimates and assumptions about future events thataffect the reporting of assets and liabilities at the balance sheet date and the reported amounts of revenue andexpense, including fair value measurements. In the event estimates and/or assumptions prove to be differentfrom actual amounts, adjustments are made in subsequent periods to reflect more current information.7 Derivative Instruments and Mark-to-Market AccountingWe enter into contracts and other instruments, including options, swaps and forwards to hedgecommodity price risks. If the contract or instrument meets the definition of a derivative under accountingstandards related to derivative instruments and hedging activities, changes in the fair value of the derivative arerecognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and anoffsetting derivative asset or liability is recorded in the balance sheet. This recognition is referred to as "mark-to-market" accounting. The fair values of our unsettled derivative contracts or instruments under mark-to-market accounting are reported in the balance sheet as commodity derivative contract assets or liabilities. Whenderivative contracts and instruments are settled and realized gains and losses are recorded, the previouslyrecorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 10 and 11 foradditional information regarding fair value measurement and commodity derivative contract assets andliabilities. Under the election criteria of accounting standards related to derivative instruments and hedgingactivities, we may elect the "normal" purchase and sale exemption. A commodity-related derivative contractmay be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered foruse or sale in the normal course of business. If designated as normal, the derivative contract is accounted forunder the accrual method of accounting (not marked-to-market) with no balance sheet or income statementrecognition of the contract until settlement.Revenue RecognitionWe record revenue from electricity sales under the accrual method of accounting. The primary sourceof revenues is sales to Luminant Energy. Annual agreements with Luminant Energy establish the transfer pricesfor the sale of electricity. Revenues recognized in the sale of electricity to Luminant Energy may not beindicative of revenues that would have been recognized had the electricity been sold directly to third parties.Transfer prices covering nuclear and lignite/coal-fueled generation are based on internally-developed,market-based forward wholesale price curves. Separate transfer prices are determined for off-peak, peak andweekend generation. Transfer prices remain fixed for the year for the initial forecasted volume. Any changes inforecasted volumes are priced at an updated modeled price that factors in updated forward wholesale marketprices of electricity.The transfer price covering natural gas-fueled generation represents a cost-based annual fee with noprofit component. Adjustments to the fee are implemented during the period covered by the agreement forstructural changes to the fleet or individual generation units, changes to operating parameters or significantchanges to capital expenditures or operating costs.We operate certain lignite/coal and natural gas-fueled generation units owned by affiliates. Theaffiliates are subsidiaries of Luminant Holding, which directs the operations of the affiliates. We bill our costs tooperate these units with no profit component. As agent of the affiliates, we net the costs incurred with therevenues received for financial statement presentation purposes. See Note 14.We have a contract mining agreement with Alcoa, Inc. and Sandow Power Company LLC, a direct,wholly-owned subsidiary of Luminant Holding, to mine and deliver lignite from the Three Oaks Mine to Alcoa,Inc. and Sandow Power Company LLC. Revenues are recognized when lignite is delivered under the agreement,which includes a fixed management fee. For financial statement presentation, we net the costs incurred relatedto the mining and delivery of lignite with the revenues received. See Note 14.8 Impairment of Long-Lived AssetsWe evaluate long-lived assets (including intangible assets with finite lives) for impairment wheneverindications of impairment exist. The carrying value of such assets is deemed to be impaired if the projectedundiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognizedbased on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily bydiscounted cash flows, supported by available market valuations, if applicable.Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimateduseful lives based on the expected realization of economic effects. See Note 3 for additional information.Goodwill and Intangible AssetsWe evaluate goodwill and intangible assets with indefinite lives for impairment at least annually (atDecember 1). See Note 3 for details of goodwill and intangible assets, including discussion of fair valuedeterminations.Fuel and Purchased Power CostsFuel and purchased power costs includes the lignite or coal consumed in the generation of electricity,the cost of any power purchased to satisfy our requirements and the amortization of finite-lived intangibles (seeNote 3 for additional information). Lignite and coal are recognized as fuel costs based on the tons consumed atweighted average historical prices. The purchase of nuclear fuel is first recorded as a capital expenditure andthen amortized to fuel costs based on the units of production method. Purchased power is generally expensed asincurred if required for contractual requirements and as consumed for auxiliary power purposes. Fuel expensedoes not include natural gas consumed in the operation of the natural gas-fueled plants because we entered into atolling arrangement with Luminant Energy on our natural gas-fueled units and accordingly, we do not take titleto the fuel used in the generation of electricity from these natural gas-fueled units.Major MaintenanceMajor maintenance costs incurred during generation plant outages and the costs of other maintenanceactivities are charged to expense as incurred and reported as operating costs.Defined Benefit Pension Plans and Other Postretirement Employee Benefit PlansWe bear a portion of the costs of the EFH Corp. sponsored pension and OPEB plans offering pensionbenefits based on either a traditional defined benefit formula or a cash balance formula to eligible employees andalso offering certain health care and life insurance benefits to eligible employees and their eligible dependentsupon the retirement of such employees. Costs of pension and OPEB plans are dependent upon numerous factors,assumptions and estimates. Under multiemployer plan accounting, EFH Corp. has elected to not allocateretirement plan assets and liabilities to us. See Note 12 for additional information regarding pension and OPEBplans, including a discussion of amendments to the EFH Corp. pension plan approved in August 2012.Stock-Based Incentive CompensationEFH Corp.'s 2007 Stock Incentive Plan authorizes discretionary grants to directors, officers andqualified managerial employees of EFH Corp. or its affiliates (including Generation) of non-qualified stockoptions, stock appreciation rights, restricted shares, shares of common stock, the opportunity to purchase sharesof common stock and other EFH Corp. stock-based awards. Stock-based compensation expense is recognizedover the vesting period based on the grant-date fair value of those awards. Restricted shares have been (andstock options previously were) granted to certain of our employees under the plan. See Note 13 for informationregarding stock-based incentive compensation.9 Franchise and Revenue-Based TaxesFranchise and excise taxes are assessed to us by state and local government bodies based on revenues orkilowatt hours delivered, as a cost of doing business, and are recorded as an expense.Income TaxesEFH Corp. files a consolidated federal income tax return; however, our income tax expense and relatedbalance sheet amounts are recorded as if we file separate corporate income tax returns. Deferred income taxesare provided for temporary differences between the book and tax basis of assets and liabilities as required underaccounting rules. We report interest and penalties related to uncertain tax positions as current income taxexpense. See Notes 4 and 5.Accounting for ContingenciesOur financial results may be affected by judgments and estimates related to loss contingencies.Accruals for loss contingencies are recorded when management determines it is probable an asset has beenimpaired or a liability has been incurred and that such economic loss can be reasonably estimated. Suchdeterminations are subject to interpretations of current facts and circumstances, forecasts of future events andestimates of the financial impacts of such events. See Note 8 for a discussion of contingencies.Cash and Cash EquivalentsFor purposes of reporting cash and cash equivalents, temporary cash investments purchased with aremaining maturity of three months or less are considered to be cash equivalents.Fair Value of Nonderivative Financial InstrumentsThe carrying amounts of financial assets classified as current assets and the carrying amounts offinancial liabilities classified as current liabilities approximate fair value due to the short maturity of suchbalances, which include cash equivalents, accounts receivable and accounts payable.Property, Plant and EquipmentAs a result of purchase accounting, carrying amounts of property, plant and equipment were adjusted toestimated fair values at the Merger date. Subsequent additions are recorded at cost. The cost of self-constructedproperty additions includes materials, both direct and indirect labor, and applicable overhead, including payroll-related costs.Depreciation of our property, plant and equipment is calculated on a straight-line basis over theestimated service lives on a component asset by asset basis. Estimated depreciable lives are based onmanagement's estimates of the assets' economic useful lives. See Note 15.Asset Retirement ObligationsA liability is initially recorded at fair value for an asset retirement obligation associated with theretirement of tangible long-lived assets in the period in which it is incurred if a fair value is reasonablyestimable. These liabilities primarily relate to nuclear generation plant decommissioning, land reclamationrelated to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plantasbestos removal and disposal costs. The obligation is initially measured at fair value. Over time, the liability isaccreted for the change in present value and the initial capitalized costs are depreciated over the remaining usefullives of the assets. See Note 15.10 InventoriesInventories are reported at the lower of cost (on a weighted average basis) or market unless expected tobe used in the generation of electricity. Also see discussion immediately below regarding environmentalallowances and credits. See Note 15.Environmental Allowances and CreditsWe account for all environmental allowances and credits as identifiable intangible assets with finitelives that are subject to amortization. The recorded values of these intangible assets were originally establishedreflecting fair value determinations at the date of the Merger under purchase accounting. Amortization expenseassociated with these intangible assets is recognized on a unit of production basis as the allowances or credits areconsumed in generation operations. The environmental allowances and credits are assessed for impairmentwhen conditions or events occur that could affect the carrying value of the assets and are evaluated with thegeneration units to the extent they are planned to be consumed in generation operations. See Note 3.Comprehensive LossComprehensive loss is the same as net loss for the year ended December 31, 2012.InvestmentsInvestments in a nuclear decommissioning trust fund are carried at current market value in the balancesheet. Assets related to employee benefit plans represent investments held to satisfy deferred compensationliabilities and are recorded at current market value. See Note 15 for details of investments.Noncontrolling InterestsSee Note 2 for discussion of accounting for noncontrolling interests.2. CONSOLIDATION OF VARIABLE INTEREST ENTITIESA variable interest entity (VIE) is an entity with which we have a relationship or arrangement thatindicates some level of control over the entity or results in economic risks to us. Accounting standards requireconsolidation of a VIE if we have (a) the power to direct the significant activities of the VIE and (b) the right orobligation to absorb profit and loss from the VIE (primary beneficiary). Our VIEs consist of CPNPC in whichwe hold an equity investment and Mining, and both are consolidated in our financial statements. In determiningthe appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision makingprocesses and risks that are passed on to its interest holders. We also examine the nature of any related partyrelationships among the interest holders of the VIE and the nature of any special rights granted to the interestholders of the VIE. We have no material investments accounted for under the equity or cost method.CPNPC was formed by subsidiaries of Generation and Mitsubishi Heavy Industries Ltd. (MHI) for thepurpose of developing two new nuclear generation units at our existing Comanche Peak nuclear-fueledgeneration facility using MHI's US-Advanced Pressurized Water Reactor technology and to obtain a combinedoperating license from the NRC. CPNPC is currently financed through capital contributions from thesubsidiaries of Generation and MI that hold 88% and 12% of CPNPC's equity interests, respectively (seeNote 9). Mining's services agreement with us provides for our reimbursement to Mining for its cost to minelignite for our benefit. We consolidate Mining as primary beneficiary as the result of this services agreement.Generation and Mining are direct, wholly-owned subsidiaries of Luminant Holding and thus undercommon control. In accordance with accounting standards for VIEs, the carrying amounts and classifications ofthe assets and liabilities related to our VIEs are disclosed on the face of our consolidated balance sheet if suchassets or liabilities meet certain criteria of legal separateness from the assets and liabilities of Generationnotwithstanding the fact that Luminant Holding effectively has control over the actions of both Generation andMining.11

3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETSGoodwillThe following table provides details of the goodwill balances at December 31, 2012. None of thegoodwill is being deducted for tax purposes.Goodwill before impairment charges ........................................................ $ 10,794Accumulated impairment charges (a) ....................................................... (8,921)Balance at December 31,2012 .................................................................. $ 1,873(a) Includes $3.650 billion recorded in 2010 and $5.271 billion recorded largely in 2008Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment atleast annually (we have selected a December 1 test date) or whenever events or changes in circumstancesindicate an impairment may exist.Because our analyses indicate that our carrying value exceeds our estimated fair value (enterprise value),we perform the following steps in testing goodwill for impairment: first, we estimate the debt-free enterprisevalue of the business at the testing date (December 1 for annual testing) taking into account future estimated cashflows and current securities values of comparable companies; second, we estimate the fair values of theindividual operating assets and liabilities of the business at that date; third, we calculate "implied" goodwill asthe excess of the estimated enterprise value over the estimated value of the net operating assets; and finally, wecompare the implied goodwill amount to the carrying value of goodwill and, if the carrying amount exceeds theimplied value, we record an impairment charge for the amount the carrying value of goodwill exceeds impliedgoodwill.Changes in circumstances that we monitor closely include trends in natural gas prices. Wholesaleelectricity prices in the ERCOT market, in which we largely operate, have generally moved with natural gasprices as marginal electricity demand is generally supplied by natural gas-fueled generation facilities.Accordingly, declining natural gas prices, which we have experienced since mid-2008, negatively impact ourprofitability and cash flows and reduce the value of our generation assets, which consist largely of lignite/coaland nuclear-fueled facilities. We are significantly exposed to this price risk. This market condition increases therisk of a goodwill impairment.Key inputs into our goodwill impairment testing at December 1, 2012 were as follows." Our carrying value substantially exceeded our estimated enterprise value by approximately 83%." Enterprise value was estimated using a three-fourths weighting of value based on internally developedcash flow projections and a one-fourth weighting of value using implied cash flow multiples based oncurrent securities values of comparable publicly traded companies." The discount rate applied to internally developed cash flow projections was 10%. The discount raterepresents the weighted average cost of capital consistent with the risk inherent in future cash flows,taking into account the capital structure, debt ratings and current debt yields of comparable publiccompanies as well as an estimate of return on equity that reflects historical market returns and currentmarket volatility for the industry.° The cash flow projections assume rising wholesale electricity prices, though the forecasted electricityprices are less than those assumed in the cash flow projections used in the 2011 goodwill impairmenttesting." Enterprise value based on internally developed cash flow projections reflected annual estimatesthrough 2018, with a terminal year value calculated using the Gordon Growth Formula.Changes in the above and other assumptions could materially affect the calculated amount of impliedgoodwill.12 The results of this testing indicated that implied goodwill exceeded recorded goodwill by approximately$300 million. While our estimated enterprise value declined from previous estimates, the estimated fair valuesof our generation assets also declined, thus mitigating the effect on implied goodwill of lower wholesaleelectricity prices, reflecting the sustained decline in natural gas prices, and declines in market values of securitiesof comparable companies.The amount by which implied goodwill exceeded recorded goodwill represents our best estimatepending finalization of the fair value calculations, which is expected in the first quarter 2013.The goodwill impairment analysis involved significant assumptions and judgments. The calculationssupporting the estimates of the enterprise value of our business and the fair values of its operating assets andliabilities utilized models that take into consideration multiple inputs, including commodity prices, discountrates, debt yields, the effects of environmental rules, securities prices of comparable publicly traded companiesand other inputs, assumptions regarding each of which could have a significant effect on valuations. The fairvalue measurements resulting from these models are classified as non-recurring Level 3 measurements consistentwith accounting standards related to the determination of fair value (see Note 10). Because of the volatility ofthese factors, we cannot predict the likelihood of any future impairment.Identifiable Intangible AssetsIdentifiable intangible assets reported in the balance sheet are comprised of the following:December 31, 2012Software and other computer related assets (a) ........Mining development costs .......................................Environmental allowances and credits .....................Favorable lease ........................................................Total identifiable intangible assets ...................GrossCarrying AccumulatedAmount Amortization77 (29)117 (48)425 (278)Net486914729S19M41(2)(a) Refer to Note 14 for a description purchase of the right to use computer-related assets from a subsidiaryof EFH Corp.Amortization expense related to intangible assets (including income statement line item) consisted of:Identifiable Intangible Asset Income Statement LineFavorable fuel contracts ................................. Fuel and purchased power costs ....Software and other computer related assets ... Depreciation and amortization ......Mining development costs ............................. Depreciation and amortization ......Environmental allowances and credits ........... Fuel and purchased power costs...Favorable lease ............................................... O perating costs .............................Total am ortization expense ...............................................................................Useful lives atDecember 31,2012 (weightedaverage inyears)43255Year EndedDecember31, 2012$ 2819112TLAi13 Following is a description of the separately identifiable intangible assets recorded as part of purchaseaccounting for the Merger. The intangible assets were recorded at estimated fair value as of the Merger date,based on observable prices or estimates of fair value using valuation models.Favorable fuel contracts -Favorable fuel contracts intangible asset primarily represents the abovemarket value of fuel contracts for which: (i) we had made the "normal" purchase or sale electionallowed by accounting standards related to derivative instruments and hedging transactions or (ii) thecontracts did not meet the definition of a derivative. The amortization periods of these intangibleassets are based on the terms of the contracts. Unfavorable contracts are reported as deferred creditrelated to unfavorable contracts-net in the balance sheet (see Note 15).Environmental allowances and credits -This intangible asset represents the fair value ofenvironmental allowances and credits, substantially all of which were expected to be used in ourpower generation activities. These credits are amortized utilizing a units-of-production method.Estimated Amortization of Identifiable Intangible Assets -The estimated aggregate amortizationexpense of identifiable intangible assets for each of the next five fiscal years is as follows:EstimatedAmortizationYear Expense2013 .................. $ 482014 .................. $ 452015 .................. $ 342016 .................. $ 2520 17 ...................................... $ 144. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXESAccounting guidance related to uncertain tax positions requires that all tax positions subject touncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorableor unfavorable.EFH Corp. and its subsidiaries file, or have filed income tax returns in US federal, state and foreignjurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of incometax returns filed by EFH Corp. and any of its subsidiaries for the years ending prior to January 1, 2007 arecomplete, but the tax years 1997 to 2006 remain in appeals with the IRS, with closing agreements reached onsuch appeals for tax years 1997 to 2002 currently under review by the IRS Joint Committee. Federal income taxreturns are under examination for tax years 2007 to 2009. Texas franchise and margin tax returns are underexamination or still open for examination for tax years beginning after 2002.The EFH Corp. IRS audit for the years 2003 through 2006 was concluded in June 2011. A significantnumber of proposed adjustments are in appeals with the IRS. The results of the audit did not affectmanagement's assessment of issues for purposes of determining the liability for uncertain tax positions.We classify interest and penalties related to uncertain tax positions as current income tax expense.Amounts recorded related to interest and penalties totaled an expense of $18 million in 2012.Noncurrent liabilities included a total of $147 million in accrued interest at December 31, 2012. Thefederal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferredincome taxes.14 The following table summarizes the changes to the uncertain tax positions, reported in other noncurrentliabilities in the consolidated balance sheet, during the year ended December 31, 2012:Balance at January 1, 2012, excluding interest and penalties ........................................ $ 974Additions based on tax positions related to prior years ............................................... 2Reductions based on tax positions related to prior years ............................................... (4)Additions based on tax positions related to the current year .......................................... 29Reductions based on tax positions related to the current year .......................................Balance at December 31, 2012, excluding interest and penalties ............................L... S 995Of the $995 million balance at December 31, 2012, $948 million represents tax positions for which theuncertainty relates to the timing of recognition in tax returns. The disallowance of such positions would notaffect the effective tax rate, but could accelerate the payment of cash to the taxing authority to an earlier period.With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), shouldEFH Corp. sustain such positions on income tax returns previously filed, our liabilities recorded would bereduced by $47 million, and $9 million (after-tax) of accrued interest would be reversed, resulting in increasednet income and a favorable impact on the effective tax rate.Other than the items discussed above, we do not expect the total amount of liabilities recorded related touncertain tax positions will significantly increase or decrease within the next 12 months.5. INCOME TAXESEFH Corp. files a US federal income tax return that includes the results of Generation.EFH Corp. and its subsidiaries (including Generation) are bound by a Federal and State Income TaxAllocation Agreement, which provides, among other things, that Generation and any other subsidiaries under theagreement is required to make payments to EFH Corp. in an amount calculated to approximate the amount of taxliability such entity would have owed if it filed a separate corporate tax return.The components of our income tax benefit are as follows:Year EndedDecember 31, 2012Current:U S Federal ............................................................................................... $ 22State ........................................................................................................ 4Total current ................................................................................. 26Deferred:U S Federal ............................................................................................... (1 39)S tate .........................................................................................................Total deferred ................................................................................ (144)Total incom e tax benefit ..................................................................15 Reconciliation of income taxes computed at the US federal statutory rate to income tax benefit:Year EndedDecember 31, 2012Loss before incom e taxes .............................................................................Income taxes at the US federal statutory rate of 35% ................................... (118)Lignite depletion allowance ..................................................................... (18)Texas margin tax, net of federal tax benefit .......................................... (1)Interest accrued for uncertain tax positions, net of tax ......................... 12Other, including audit settlements .................................................... ...... 7Incom e tax benefit ........................................................................................ ..(118)Effective tax rate ......................................................................................... 35.0%Deferred income taxes provided for temporary differences based on tax laws in effect at December 31,2012 are as follows:December 31, 2012Total Current NoncurrentDeferred Income Tax Assets:Unfavorable contracts (Note 15) ......................................... $ 221 $ -S 221Net operating loss carryforwards ......................................... 182 -182Employee benefit obligations .............................................. 30 -30O ther .................................................................................... 6 1 -6 1T otal ............................................................................... 494 -494Deferred Income Tax Liabilities:Property, plant and equipment ............................................. 3,274 -3,274Commodity contracts (mark-to-market) ............................... 838 4 834Identifiable intangible assets ................................................ 76 -76O ther ................................................................................... 2 1 2 1 -Total .............................................................................. 4.209 25 4,184Net Deferred Income Tax Liability ........................................... 1 -25 _ 3.690At December 31, 2012, we had no alternative minimum tax credit carryforwards available to offsetfuture tax payments. At December 31, 2012, we had net operating loss (NOL) carryforwards for federal incometax purposes of $520 million that expire in 2032 and 2033. The NOL carryforwards can be used to offset futuretaxable income. We expect to utilize all of our NOL carryforwards prior to their expiration dates.See Note 4 for discussion regarding accounting for uncertain tax positions.16

6. OTHER INCOME AND DEDUCTIONSYear EndedDecember 31, 2012Other incomeProperty dam age claim ..................................................................... $ 2Total other incom e .................................................................... .$2Other deductionsCharges related to pension plan actions (Note 12) ............................ (95)Counterparty contract settlement ....................................................... $ (4)W ater contract expense ...................................................................... (3)Cost associated with retired natural gas-fueled generation units ...... (2)O th er ..................................................................................................Total other deductions ............................................................. .L$ 057. FINANCINGShort- Term BorrowingsShort-term financing is provided by TCEH. Financing is also provided through leases for certainequipment.TCEH Debt Guaranteed by GenerationAs described below, TCEH had cash borrowings totaling $30.853 billion under the TCEH SeniorSecured Facilities, TCEH Senior Secured Notes, TCEH Senior Secured Second Lien Notes and TCEH SeniorNotes at December 31, 2012, for which we are a guarantor. If TCEH fails to make any payment when due onsuch indebtedness, the holders of such indebtedness may seek payment from the guarantors, includingGeneration, on a joint and several basis. If we make any payment under our guarantee, we may be entitled to aclaim for contribution against each of our co-guarantors for their proportionate share of the obligation that wepaid.TCEH Senior Secured Facilities -Borrowings under the TCEH Senior Secured Facilities totaled$22.295 billion at December 31, 2012 and consisted of:* $3.809 billion of TCEH Term Loan Facilities maturing in October 2014 with interest payable at LIBORplus 3.50%;* $15.370 billion of TCEH Term Loan Facilities maturing in October 2017 with interest payable atLIBOR plus 4.50% (see discussion of January 2013 activity below);* $42 million of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2014 withinterest payable at LIBOR plus 3.50%,* $1.020 billion of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2017with interest payable at LIBOR plus 4.50%, and* Amounts borrowed under the TCEH Revolving Credit Facility, which may be reborrowed from time totime until October 2016 and represent the entire amount of commitments under the facility totaling$2.054 billion at December 31, 2012 (see discussion of January 2013 activity below).17 In January 2013, the Credit Agreement governing the TCEH Senior Secured Facilities was amended toextend the maturity date of $645 million of commitments maturing in October 2013 to October 2016, bringingthe maturity date of the entire commitment of $2.054 billion to October 2016. The extended commitments havethe same terms and conditions as the existing commitments expiring in October 2016 under the CreditAgreement. Fees in consideration for the extension were settled through the incurrence of $340 million principalamount of incremental TCEH Term Loan Facilities maturing in October 2017, which we also guarantee. Inconnection with the extension request, TCEH eliminated its ability to draw letters of credit under the TCEHRevolving Credit Facility. At the date of the extension, there were no outstanding letters of credit under theTCEH Revolving Credit Facility.The TCEH Commodity Collateral Posting Facility, under which there were no borrowings in 2012,matured in December 2012.The TCEH Senior Secured Facilities are subject to certain covenants, including a financial maintenancecovenant. The maximum ratios for the secured debt to Adjusted EBITDA financial maintenance covenant are8.00 to 1.00 for test periods through December 31, 2014, and decline over time to 5.50 to 1.00 for the testperiods ending March 31, 2017 and thereafter. In addition, (i) up to $1.5 billion principal amount of TCEHsenior secured first lien notes (including $906 million of the TCEH Senior Secured Notes discussed below), tothe extent the proceeds are used to repay term loans and deposit letter of credit loans under the TCEH SeniorSecured Facilities and (ii) all senior secured second lien debt will be excluded for the purposes of the secureddebt to Adjusted EBITDA financial maintenance covenant.The Credit Agreement governing the TCEH Senior Secured Facilities also contains certain provisionsrelated to TCEH Demand Notes that arise from cash loaned for (i) debt principal and interest payments (P&INote) and (ii) other general corporate purposes of EFH Corp. (SG&A Note), which include TCEH'scommitment:* not to make any further loans to EFH Corp. under the SG&A Note (at December 31, 2012, theoutstanding balance of the SG&A Note was $233 million);* that borrowings outstanding under the P&I Note will not exceed $2.0 billion in aggregate atany time (at December 31, 2012, the outstanding balance of the P&I Note was $465 million),andthat the sum of (i) the outstanding indebtedness (including guarantees) issued by EFH Corp. orany subsidiary of EFH Corp. (including EFIH) secured by a second-priority lien on the equityinterests that EFIH owns in Oncor Electric Delivery Holdings Company LLC, which ownsapproximately 80% of Oncor, (EFIH Second-Priority Debt) and (ii) the aggregate outstandingamount of the SG&A Note and P&I Note will not exceed, at any time, the maximum amountof EFIH Second-Priority Debt permitted by the indenture governing the EFH Corp. 10%Senior Secured Notes due in 2020 as in effect on April 7, 2011.In January 2013, EFH Corp. repaid the remaining balance of the TCEH Demand Notes, which were,and any future TCEH Demand Notes will be, guaranteed by EFCH and EFIH on a senior unsecured basis.Each of the loans described above that matures in 2016 or 2017 includes a "springing maturity"provision pursuant to which (i) in the event that more than $500 million aggregate principal amount of the TCEH10.25% Notes due in 2015 (other than notes held by EFH Corp. or its controlled affiliates at March 31, 2011 tothe extent held at the determination date as defined in the Credit Agreement) or more than $150 millionaggregate principal amount of the TCEH Toggle Notes due in 2016 (other than notes held by EFH Corp. or itscontrolled affiliates at March 31, 2011 to the extent held at the determination date as defined in the CreditAgreement), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notesand (ii) TCEH's total debt to Adjusted EBITDA ratio (as defined in the TCEH Senior Secured Facilities) isgreater than 6.00 to 1.00 at the applicable determination date, then the maturity date of the extended loans willautomatically change to 90 days prior to the maturity date of the applicable notes.18 Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loansto TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH's availableliquidity could be reduced by an amount up to the aggregate amount of such lender's commitments under theTCEH Senior Secured Facilities.The TCEH Senior Secured Facilities are fully and unconditionally guaranteed jointly and severally on asenior secured basis by EFCH, and subject to certain exceptions, each existing and future direct or indirectwholly-owned US subsidiary of TCEH (including Generation). The TCEH Senior Secured Facilities, along withthe TCEH Senior Secured Notes and certain commodity hedging transactions and interest rate swaps, are securedon a first priority basis by (i) substantially all of the current and future assets of TCEH and TCEH's subsidiarieswho are guarantors of such facilities (including Generation) and (ii) pledges of the capital stock of TCEH andcertain current and future direct or indirect subsidiaries of TCEH (including Generation).The TCEH Senior Secured Facilities contain customary negative covenants that, among other things,restrict, subject to certain exceptions, TCEH and its restricted subsidiaries' (including Generation's) ability to:" incur additional debt;" create additional liens;" enter into mergers and consolidations;* sell or otherwise dispose of assets;" make dividends, redemptions or other distributions in respect of capital stock;" make acquisitions, investments, loans and advances, and" pay or modify certain subordinated and other material debt.The TCEH Senior Secured Facilities contain certain customary events of default for senior leveragedacquisition financings, the occurrence of which would allow the lenders to accelerate all outstanding loans andterminate their commitments.TCEH 11.5% Senior Secured Notes -At December 31, 2012, the principal amount of the TCEH11.5% Senior Secured Notes totaled $1.750 billion. The notes mature in October 2020, with interest payable incash quarterly in arrears on January 1, April 1, July 1 and October 1, at a fixed rate of 11.5% per annum. Thenotes are fully and unconditionally guaranteed on a joint and several basis by EFCH and each subsidiary ofTCEH (including Generation) that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors).The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and theguarantees are secured on a first-priority basis by all of the assets and equity interests held by the Guarantors(including Generation), in each case, to the extent such assets and equity interests secure obligations under theTCEH Senior Secured Facilities (the TCEH Collateral), subject to certain exceptions and permitted liens.The notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness ofTCEH, (ii) senior in right of payment to all existing or future unsecured and second-priority secured debt ofTCEH to the extent of the value of the TCEH Collateral and (iii) senior in right of payment to any futuresubordinated debt of TCEH. These notes are effectively subordinated to all secured obligations of TCEH thatare secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing suchobligations.The guarantees of the TCEH Senior Secured Notes by the Guarantors are effectively senior to anyunsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. Theguarantees are effectively subordinated to all debt of the Guarantors secured by assets that are not part of theTCEH Collateral, to the extent of the value of the collateral securing that debt.19 The indenture for the TCEH Senior Secured Notes contains a number of covenants that, among otherthings, restrict, subject to certain exceptions, TCEH's and its restricted subsidiaries' (including Generation's)ability to:" make restricted payments, including certain investments;" incur debt and issue preferred stock;" create liens;" enter into mergers or consolidations;" sell or otherwise dispose of certain assets, and" engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to payprincipal or interest on the notes when due. If certain events of default occur under the indenture, the trustee orthe holders of at least 30% of aggregate principal amount of all outstanding TCEH Senior Secured Notes maydeclare the principal amount on all such notes to be due and payable immediately.Until April 1, 2014, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to35% of the aggregate principal amount of the TCEH Senior Secured Notes from time to time at a redemptionprice of 111.5% of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEHmay redeem the notes at any time prior to April 1, 2016 at a price equal to 100% of their principal amount, plusaccrued interest and the applicable premium as defined in the indenture. TCEH may also redeem the notes, inwhole or in part, at any time on or after April 1, 2016, at specified redemption prices, plus accrued interest.Upon the occurrence of a change of control (as described in the indenture), TCEH must offer to repurchase thenotes at 101% of their principal amount, plus accrued interest.TCEH 15% Senior Secured Second Lien Notes (including Series B) -At December 31, 2012, theprincipal amount of the TCEH 15% Senior Secured Second Lien Notes totaled $1.571 billion. These notesmature in April 2021, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 andOctober 1 at a fixed rate of 15% per annum. The notes are fully and unconditionally guaranteed on a joint andseveral basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH (including Generation) thatguarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by securityinterests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on asecond-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (includingGeneration, collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interestssecure obligations under the TCEH Senior Secured Facilities on a first-priority basis, subject to certainexceptions (including the elimination of the pledge of equity interests of any Subsidiary Guarantor (includingGeneration) to the extent that separate financial statements would be required to be filed with the US Securitiesand Exchange Commission for such Subsidiary Guarantor (including Generation) under Rule 3-16 of RegulationS-X) and permitted liens. The guarantee from EFCH is not secured.The notes are senior obligations of the issuer and rank equally in right of payment with all seniorindebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to theextent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEHCollateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes areeffectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, the TCEH SeniorSecured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on theTCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent ofthe value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other thanthe TCEH Collateral, to the extent of the value of the assets securing such obligations.20 The guarantees of the TCEH Senior Secured Second Lien Notes by the Subsidiary Guarantors(including Generation) are effectively senior to any unsecured debt of the Subsidiary Guarantors to the extent ofthe value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral).These guarantees are effectively subordinated to all debt of the Subsidiary Guarantors (including Generation)secured by the TCEH Collateral on a first-priority basis or that is secured by assets that are not part of the TCEHCollateral, to the extent of the value of the collateral securing that debt. EFCH's guarantee ranks equally with itsunsecured debt (including debt it guarantees on an unsecured basis) and is effectively subordinated to any of itssecured debt to the extent of the value of the collateral securing that debt.The indenture for the TCEH Senior Secured Second Lien Notes contains a number of covenants that,among other things, restrict, subject to certain exceptions, TCEH's and its restricted subsidiaries' (includingGeneration's) ability to:" make restricted payments, including certain investments;" incur debt and issue preferred stock;* create liens;" enter into mergers or consolidations;" sell or otherwise dispose of certain assets, and* engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to payprincipal or interest on the notes when due. In general, all of the series of TCEH Senior Secured Second LienNotes vote together as a single class. As a result, if certain events of default occur under the indenture, thetrustee or the holders of at least 30% of aggregate principal amount of all outstanding TCEH Senior SecuredSecond Lien Notes may declare the principal amount on all such notes to be due and payable immediately.Until October 1, 2013, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to35% of the aggregate principal amount of each series of the TCEH Senior Secured Second Lien Notes from timeto time at a redemption price of 115.00% of the aggregate principal amount of the notes being redeemed, plusaccrued interest. TCEH may redeem each series of the notes at any time prior to October 1, 2015 at a price equalto 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture.TCEH may also redeem each series of the notes, in whole or in part, at any time on or after October 1, 2015, atspecified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as described inthe indenture), TCEH must offer to repurchase each series of the notes at 101% of their principal amount, plusaccrued interest.TCEH 10.25% Senior Notes (including Series B) and 10.50/11.25% Senior Toggle Notes(collectively, the TCEH Senior Notes) -At December 31, 2012, the principal amount of the TCEH SeniorNotes totaled $5.237 billion, including $363 million aggregate principal amount held by EFH Corp. and EFIH,and the notes are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH's directparent, EFCH (which owns 100% of TCEH), and by each subsidiary (including Generation) that guarantees theTCEH Senior Secured Facilities. The TCEH 10.25% Notes mature in November 2015, with interest payable incash semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.25% per annum. The TCEHToggle Notes mature in November 2016, with interest payable semi-annually in arrears on May 1 andNovember 1 at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum forPIK Interest, which option expired with the November 1, 2012 interest payment.TCEH may redeem the TCEH 10.25% Notes and TCEH Toggle Notes, in whole or in part, at any time,at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change ofcontrol of EFCH or TCEH, TCEH must offer to repurchase the TCEH Senior Notes at 101% of their principalamount, plus accrued and unpaid interest, if any.21 The indenture for the TCEH Senior Notes contains a number of covenants that, among other things,restrict, subject to certain exceptions, TCEH's and its restricted subsidiaries' (including Generation's) ability to:" make restricted payments;" incur debt and issue preferred stock;" create liens;" enter into mergers or consolidations;" sell or otherwise dispose of certain assets, and" engage in certain transactions with affiliates.The indenture also contains customary events of default, including, among others, failure to payprincipal or interest on the notes when due. If certain events of default occur and are continuing under theindenture, the trustee or the holders of at least 30% in principal amount of the notes may declare the principalamount on the notes to be due and payable immediately.TCEH Material Cross Default/Acceleration Provisions- Certain of TCEH's financing arrangementscontain provisions that could result in an event of default if there were a failure under other financingarrangements to meet payment terms or to observe other covenants that could or does result in an acceleration ofpayments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions.Generation FinancingOncor Note -In August 2012, we settled, at a discount, a non-interest bearing note payable to Oncorfor which we paid $159 million in cash. See Note 14 for information related to the payment of this note.Long- Term Debt- At December 31, 2012, long-term debt consisted of the following:C apital leases ................................................................. $ 53Less am ount currently due ............................................. .Total long-term debt ...................................................... L1 4Principal payments related to capital leases totaled $9 million in the nine months ended December 31,2012. Our capital leases are related to mining and telecommunication equipment. In 2012, we entered into asale-leaseback transaction for $6 million in mining equipment.8. COMMITMENTS AND CONTINGENCIESContractual Obligation and CommitmentsContractual Commitments -At December 31, 2012, we had noncancellable commitments underenergy-related contracts, leases and other agreements as follows:2013 ................................2014 ................................2015 ................................2016 ................................2017 ................................Thereafter .......................Total .........................Coal purchaseagreements and coaltransportationagreements (a)$ 4323082921234344Nuclear WaterFuel Contracts Rights Contracts Other$ 158 $ 11 $ 112116 12 30167 12 14124 10 16110 8 16645 103 161-132 _ 1 2D4(a) Includes certain coal purchase agreements between third parties and Luminant Energy on our behalf. It is expected thatwe will take physical title to the coal.22 Expenditures under our coal purchase and coal transportation agreements totaled $183 million for theyear ended December 31, 2012.At December 31, 2012, future minimum lease payments under both capital leases and operating leaseswith initial or remaining noncancellable lease terms in excess of one year are as follows:2013 ......................................................................2014 .....................................................................2015 ......................................................................2016 ......................................................................2017 ......................................................................Thereafter .....................................................................Total future minimum lease payments ..............Less am ounts representing interest ...............................Present value of future minimum lease payments .......Less current portion .................................................Long-term capital lease obligation ...............................Capital OperatingLeases LeasesS 9 $ 487 405 365 4334 32-_ 151S 607537546Rent reported as operating costs, fuel and purchased power costs and selling, general and administrativeexpenses totaled $30 million, $16 million, and $4 million, respectively, for the year ended December 31, 2012.Electricity Supply AgreementOur Sandow Unit 4 supplies electricity to Alcoa Inc.'s smelter complex in Rockdale, Texas under along-term sales contract. Under this agreement, Alcoa Inc. is entitled to 398 megawatts of firm electricity and upto 82.57% of the actual electricity generated by the unit.GuaranteesWe have entered into contracts that contain guarantees to unaffiliated parties that could requireperformance or payment under certain conditions, none of which are material.Guarantees of TCEH Debt -See Note 7 regarding guarantees we have provided on the TCEH SeniorSecured Facilities, TCEH Senior Secured Notes, TCEH Senior Secured Second Lien Notes and TCEH SeniorNotes.Guarantees of Mining Reclamation obligations -The Railroad Commission of Texas has rules inplace to assure that parties can meet their mining reclamation obligations, including through self-bonding whenappropriate. If we do not continue to meet the self-bonding requirements as applied by the Railroad Commissionof Texas, TCEH may be required to post cash, letter of credit or other tangible assets as collateral support. SeeNote I for discussion of liquidity considerations..23 Litigation Related to Generation FacilitiesIn September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District ofTexas (Texarkana Division) against EFH Corp. and us for alleged violations of the Clean Air Act (CAA) at ourMartin Lake generation facility. This case is currently scheduled for trial in November 2013. While we areunable to estimate any possible loss or predict the outcome, we believe that the Sierra Club's claims are withoutmerit, and we intend to vigorously defend this litigation. In December 2010 and again in October 2011, theSierra Club informed us that it may sue us for allegedly violating CAA provisions in connection with ourMonticello generation facility. In May 2012, the Sierra Club informed us that it may sue us for allegedlyviolating CAA provisions in connection with our Sandow 4 generation facility. While we cannot predictwhether the Sierra Club will actually file suit regarding Monticello or Sandow 4 or the outcome of any resultingproceedings, we believe we have complied with the requirements of the CAA at all of our generation facilities.See below for discussion of litigation regarding the CSAPR and the Texas State Implementation Plan.Regulatory ReviewsIn June 2008, the EPA issued an initial request for information to us under the EPA's authority underSection 114 of the CAA. The stated purpose of the request is to obtain information necessary to determinecompliance with the CAA, including New Source Review Standards and air permits issued by the TCEQ for theMonticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Reviewenforcement initiative, companies that have received a large and broad request under Section 114, such as therequest we received, have in many instances subsequently received a notice of violation from the EPA, whichhas in some cases progressed to litigation or settlement. In July 2012, the EPA sent us a notice of violationalleging noncompliance with the CAA's New Source Review Standards and the air permits at our Martin Lakegeneration facility. While we cannot predict whether the EPA will initiate enforcement proceedings under thenotice of violation, we believe that we have complied with all requirements of the CAA at all of our generationfacilities. We cannot predict the outcome of any resulting enforcement proceedings or estimate the penalties thatmight be assessed in connection with any such proceedings. In September 2012, we filed a petition for review inthe United States Court of Appeals for the Fifth Circuit (Fifth Circuit Court) seeking judicial review of theEPA's notice of violation. Given recent legal precedent subjecting agency orders like the notice of violation tojudicial review, we filed the petition for review to preserve our ability to challenge the EPA's issuance of thenotice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December 2012, theFifth Circuit Court issued an order that will delay a ruling on the EPA's motion to dismiss until after the case hasbeen fully briefed and oral argument, if any, is held. We cannot predict the outcome of these proceedings,including the financial effects, if any.Cross-State Air Pollution Rule (CSAPR)In July 2011, the EPA issued the CSAPR, compliance with which would have required significantadditional reductions of sulfur dioxide (SO2) and nitrogen oxides (NO.) emissions from our fossil-fueledgeneration units. In September 2011, we filed a petition for review in the US Court of Appeals for the District ofColumbia Circuit (D.C. Circuit Court) challenging the CSAPR as it applies to Texas. If the CSAPR had takeneffect, it would have caused us to, among other actions, idle two lignite/coal-fueled generation units and ceasecertain lignite mining operations by the end of 2011.In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certainaspects of the CSAPR, including increases in the emissions budgets for Texas and Luminant Holding'sgeneration assets as compared to the July 2011 version of the rule. In April 2012, we filed in the D.C. CircuitCourt a petition for review of the Final Revisions on the ground, among others, that the rules do not include allof the budget corrections we requested from the EPA. The parties to the case have agreed that the case should beheld in abeyance pending the conclusion of the CSAPR rehearing proceeding discussed below. In June 2012, theEPA finalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPRissued by the EPA in October 2011, the Final Revisions and the Second Revised Rule finalize emissions budgetsfor Luminant Holding's generation assets that are approximately 6% lower for SO2, 3% higher for annual NO,and 2% higher for seasonal NOR.24 In August 2012, a three judge panel of the D.C. Circuit Court vacated the CSAPR, remanding it to theEPA for further proceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule do notimpose any immediate requirements on us, the State of Texas, or other affected parties. The D.C. Circuit Court'sorder stated that the EPA was expected to continue administering the Clean Air Interstate Rule (the predecessorrule to the CSAPR) pending the EPA's further consideration of the rule. In October 2012, the EPA and certainother parties that supported the CSAPR filed petitions with the D.C. Circuit Court seeking review by the fullcourt of the panel's decision to vacate and remand the CSAPR. In January 2013, the D.C. Circuit Court deniedthese requests for rehearing, concluding the CSAPR rehearing proceeding. The EPA and the other parties haveapproximately 90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predictwhether any such appeals will be filed.State Implementation Plan (SIP)In September 2010, the EPA disapproved a portion of the State Implementation Plan pursuant to whichthe TCEQ implements its program to achieve the requirements of the Clean Air Act. The EPA disapproved theTexas standard permit for pollution control projects. We hold several permits issued pursuant to the TCEQstandard permit conditions for pollution control projects. We challenged the EPA's disapproval by filing alawsuit in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) arguing that the TCEQ's adoptionof the standard permit conditions for pollution control projects was consistent with the Clean Air Act. In March2012, the Fifth Circuit Court vacated the EPA's disapproval of the Texas standard permit for pollution controlprojects and remanded the matter to the EPA for reconsideration. We cannot predict the timing or outcome ofthe EPA's reconsideration, including the financial effects, if any.In November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had beenphasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdownand maintenance activities and replacing that exemption with a more limited affirmative defense that will itselfbe phased out and replaced by TCEQ-issued generation facility-specific permit conditions. We, like many otherelectricity generation facility operators in Texas, have asserted applicability of the exemption or affirmativedefense, and the TCEQ has not objected to that assertion. We have also applied for and received the generationfacility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the FifthCircuit Court arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmativedefense as permits are issued is consistent with the Clean Air Act. In July 2012, the Fifth Circuit Court deniedour challenge and ruled that the EPA's actions were in accordance with the Clean Air Act. In October 2012, theFifth Circuit Court panel withdrew its original opinion and issued a new expanded opinion that again upheld theEPA's disapproval. In November 2012, we filed a petition with the Fifth Circuit Court asking for review by thefull Fifth Circuit Court of the panel's new expanded opinion. Other parties to the proceedings also filed apetition with the Fifth Circuit Court asking the panel to reconsider its decision. We cannot predict the timing oroutcome of this matter, including the financial effects, if any.Other MattersWe are involved in other legal and administrative proceedings in the normal course of business, theultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on ourresults of operations, liquidity or financial condition.Environmental ContingenciesSee discussion above regarding the CSAPR issued by the EPA in July 2011 and revised in February2012 that include provisions which, among other things, place limits on SO2 and NO, emissions produced byelectricity generation plants. The CSAPR provisions and the Mercury and Air Toxics Standard (MATS) issuedby the EPA in December 2011, would require substantial additional capital investment in our lignite/coal-fueledgeneration facilities.We must comply with environmental laws and regulations applicable to the handling and disposal ofhazardous waste. We believe that we are in compliance with current environmental laws and regulations;however, the impact, if any, of changes to existing regulations or the implementation of new regulations is notdeterminable and could materially affect our financial condition, results of operations and liquidity.25 The costs to comply with environmental regulations could be significantly affected by the followingexternal events or conditions:* enactment of state or federal regulations regarding carbon dioxide and other greenhouse gas emissions;* other changes to existing state or federal regulation regarding air quality, water quality, control of toxicsubstances and hazardous and solid wastes, and other environmental matters, including revisions to theClean Air Interstate Rule currently being developed by the EPA as a result of court rulings discussedabove and MATS and* the identification of sites requiring clean-up or the filing of other complaints in which we may beasserted to be a potential responsible party under applicable environmental laws or regulations.Labor ContractsCertain of our personnel are represented by labor unions and covered by collective bargainingagreements with varying expiration dates. In November 2011, three-year labor agreements were reachedcovering bargaining unit personnel engaged in lignite-fueled generation operations (excluding Sandow) andlignite mining operations (excluding Three Oaks). Also in November 2011, a four-year labor agreement wasreached covering bargaining unit personnel engaged in natural gas-fueled generation operations. In October2010, two-year labor agreements were reached covering bargaining unit personnel engaged in the Sandowlignite-fueled generation operations and the Three Oaks lignite mining operations, and although the term of theseagreements have now expired, we are currently negotiating new labor agreements for the Sandow operations andThree Oaks Mine and are operating under the terms of the existing agreements for these two facilities. In August2010, a three-year labor agreement was reached covering bargaining unit personnel engaged in nuclear-fueledgeneration operations. We do not expect any changes in collective bargaining agreements to have a materialeffect on our results of operations, liquidity or financial condition.Nuclear InsuranceNuclear insurance includes liability coverage, property damage, decontamination and prematuredecommissioning coverage and accidental outage and/or extra expense coverage. The liability coverage isgoverned by the Price-Anderson Act (Act), while the property damage, decontamination and prematuredecommissioning coverage are promulgated by the rules and regulations of the NRC. We intend to maintaininsurance against nuclear risks as long as such insurance is available. The company is self-insured to the extentthat losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations,(iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability.Such losses could have a material effect on our financial condition and results of operations and liquidity.With regard to liability coverage, the Act provides financial protection for the public in the event of asignificant nuclear generation plant incident. The Act sets the statutory limit of public liability for a singlenuclear incident at $12.5 billion and requires nuclear generation plant operators to provide financial protectionfor this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claimsexceeding the $12.5 billion limit for a single incident mandated by the Act. As required, the company providesthis financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and propertydamage through a combination of private insurance and industry-wide retrospective payment plans. As the firstlayer of financial protection, the company has $375 million of liability insurance from American NuclearInsurers (ANI), which provides such insurance on behalf of a major stock insurance company pool, NuclearEnergy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).26 Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operatinglicensed reactor in the US is subject to an assessment of up to $117.5 million plus a 3% insurance premium tax,subject to increases for inflation every five years. Assessments are limited to $17.5 million per operatinglicensed reactor per year per incident. The company's maximum potential assessment under the industryretrospective plan would be $235 million (excluding taxes) per incident but no more than $35 million in any oneyear for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375 millionper accident at any nuclear facility. The SFP and liability coverage are not subject to any deductibles.With respect to nuclear decontamination and property damage insurance, the NRC requires that nucleargeneration plant license-holders maintain at least $1.06 billion of such insurance and require the proceeds thereofto be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to andapproved by the NRC before the proceeds can be used for plant repair or restoration or to provide for prematuredecommissioning. The company maintains nuclear decontamination and property damage insurance forComanche Peak in the amount of $2.25 billion (subject to $5 million deductible per accident), above which thecompany is self-insured. This insurance coverage consists of a primary layer of coverage of $500 millionprovided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurancecompany and $1.25 billion of premature decommissioning coverage also provided by NEIL. The EuropeanMutual Association for Nuclear Insurance provides additional insurance limits of $500 million in excess ofNEIL's $1.75 billion coverage.The company maintains Accidental Outage Insurance through NEIL to cover the additional costs ofobtaining replacement electricity from another source if one or both of the units at Comanche Peak are out ofservice for more than twelve weeks as a result of covered direct physical damage. The coverage provides forweekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for eachoutage, respectively, after the initial twelve-week waiting period. The total maximum coverage is $490 millionper unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service atthe same time as a result of the same accident.If NEIL's losses exceeded its reserves for the applicable coverage, potential assessments in the form ofa retrospective premium call could be made up to ten times annual premiums. The company maintains insurancecoverage against these potential retrospective premium calls.Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year timeframe, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recoversfrom other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, anew set of limits and resources would apply.9. MEMBERSHIP INTERESTSNoncash Distributions to ParentIn December 2012 we made a $1.5 billion noncash dividend to our parent, Luminant Holding, insettlement of a portion of our advances to parent (see Note 14).Contribution from parentIn December 2012, our parent, Luminant Holding, made a cash contribution to us in the amount of $104million.Noncontrolling InterestsAs discussed in Note 2, we consolidate CPNPC, which results in a noncontrolling interest component ofequity. Noncontrolling interests also arise from the consolidation of Mining under consolidation accountingstandards also discussed in Note 2. In the year ended December 31, 2012, net income attributable to thenoncontrolling interests was $19 million, and subsidiaries of Mitsubishi Heavy Industries Ltd. made capitalcontributions of $7 million to CPNPC.27

10. FAIR VALUE MEASUREMENTSAccounting standards related to the determination of fair value define fair value as the price that wouldbe received to sell an asset or paid to transfer a liability in an orderly transaction between market participants atthe measurement date. We use a "mid-market" valuation convention (the mid-point price between bid and askprices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fairvalue measurement on a recurring basis. We primarily use the market approach for recurring fair valuemeasurements and use valuation techniques to maximize the use of observable inputs and minimize the use ofunobservable inputs.We categorize our assets and liabilities recorded at fair value based upon the following fair valuehierarchy:" Level I valuations use quoted prices in active markets for identical assets or liabilities that areaccessible at the measurement date. An active market is a market in which transactions for the assetor liability occur with sufficient frequency and volume to provide pricing information on an ongoingbasis. Our Level 1 assets and liabilities include exchange-traded equity securities.* Level 2 valuations use inputs that, in the absence of actively quoted market prices, are observable forthe asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similarassets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities inmarkets that are not active, (c) inputs other than quoted prices that are observable for the asset orliability such as interest rates and yield curves observable at commonly quoted intervals and (d)inputs that are derived principally from or corroborated by observable market data by correlation orother means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similarassets or liabilities that are corroborated by correlations or other mathematical means and othervaluation inputs." Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used tothe extent observable inputs are not available, thereby allowing for situations in which there is little,if any, market activity for the asset or liability at the measurement date. We use the most meaningfulinformation available from the market combined with internally developed valuation methodologiesto develop our best estimate of fair value. For example, our Level 3 assets and liabilities includecertain derivatives whose values are derived from pricing models that utilize multiple inputs to thevaluations, including inputs that are not observable or easily corroborated through other means.Our valuation policies and procedures are developed, maintained and validated by an EFH Corp.centralized risk management group that reports to the EFH Corp. Chief Financial Officer, who also functions asthe Chief Risk Officer. Risk management functions include valuation model validation, risk analytics, riskcontrol, credit risk management and risk reporting.We utilize several different valuation techniques to measure the fair value of assets and liabilities,relying primarily on the market approach of using prices and other market information for identical and/orcomparable assets and liabilities for those items that are measured on a recurring basis. These methods include,among others, the use of broker quotes and statistical relationships between different price curves.In utilizing broker quotes, we attempt to obtain multiple quotes from brokers (generally nonbinding)that are active in the commodity markets in which we participate (and require at least one quote from twobrokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. Thenumber of broker quotes received for certain pricing inputs varies depending on the depth of the trading market,each individual broker's publication policy, recent trading volume trends and various other factors.28 Certain derivatives and financial instruments are valued utilizing option pricing models that take intoconsideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs.Additionally, when there is not a sufficient amount of observable market data, valuation models are developedthat incorporate proprietary views of market factors. Significant unobservable inputs used to develop thevaluation models include volatility curves, correlation curves, illiquid pricing locations and credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forwardprice curves for certain commodities. We believe the development of such curves is consistent with industrypractice; however, the fair value measurements resulting from such curves are classified as Level 3.The significant unobservable inputs and valuation models are developed by employees trained andexperienced in market operations and fair value measurement and validated by the company's risk managementgroup, which also further analyzes any significant changes in Level 3 measurements. Significant changes in theunobservable inputs could result in significant upward or downward changes in the fair value measurement.With respect to amounts presented in the following fair value hierarchy table, the fair valuemeasurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on thelowest level input that is significant to the fair value measurement. Certain assets and liabilities would beclassified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair valuemeasurement in its entirety requires judgment, considering factors specific to the asset or liability beingmeasured.At December 31, 2012, assets and liabilities measured at fair value on a recurring basis consisted of thefollowing:Level I Level 2 Level 3 (a) TotalAssets:Commodity contracts $ -$ -$ 3 $ 3Nuclear decommissioning trust -equitysecurities (b) .......................................... 249 144 -393Nuclear decommissioning trust -debtsecurities (b) .......................................... -261 -261Total assets ........................................... $ __249 S 405 S .J_ __657Liabilities:Commodity contracts ............................... $ -12 $ 34 $ 46Total liabilities ..................................... S --$ 12 3(a) See table below for description of Level 3 assets and liabilities.(b) The nuclear decommissioning trust investment is included in the Investments line in the balance sheet. SeeNote 15.Commodity contracts consist primarily of fuel oil, coal, and uranium derivative instruments entered intofor hedging purposes. See Notes 11 and 14 for further discussion regarding the use of derivative instruments.Nuclear decommissioning trust assets represent securities held for the purpose of funding the futureretirement and decommissioning of the nuclear generation units. These investments include equity, debt andother fixed-income securities consistent with investment rules established by the NRC and the Public UtilityCommission of Texas.There were no significant transfers between Level 1, Level 2 or Level 3 of the fair value hierarchy forthe year ended December 31, 2012.29 The following table presents the fair value of the Level 3 assets and liabilities by major contract type(all related to commodity contracts) and the significant unobservable inputs used in the valuations at December31, 2012:Fair ValueContract Type Valuation Significant Unobservable(a) Assets Liabilities Total Technique Input Range (b)Coal purchases $ -S (34) $ (34) Market Illiquid-price variances $0.00 to $ 1.00Approach (c) between mines (d)Probability of default (e) 5% to 40%Recovery rate (f) 0% to 40%Other 3 -3Total $L 3 $ (34) (a) Coal purchase contracts relate to western (Powder River Basin) coal. Fuel oil purchase contracts relate to ultra-low-sulfur diesel.(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season, and location.(c) While we use the market approach, there is either insufficient market data to consider the valuation liquid or thesignificance of credit reserves or non-performance risk adjustments results in a Level 3 designation.(d) Based on historical range of price variances between mine locations.(e) Estimate of the range of probabilities of default based on past experience and the length of the contract as well asour and counterparty credit ratings.(f Estimate of the default recovery rate based on historical corporate rates.The following table presents the changes in fair value of the Level 3 assets and liabilities (all related tocommodity contracts) for the year ended December 31, 2012.Year EndedDecember 31, 2012B alance at beginning of period ...................................................................................................................... $ 3Total realized and unrealized losses included in net loss .......................................................................... (54)Settlem ents (a) ......................................................................................................................................... 20N et change (b ) ....................................................................................................................................B alance at end of period ................................................................................................................................. $ _ _. lNet change in unrealized losses included in net loss relating to instrumentsheld at end of period ............................................................................................................................ $ (30)(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income.(b) Substantially all changes in values of commodity contracts are reported in the income statement in net loss fromcommodity hedging activities. Activity excludes changes in fair value in the month the position settled as wellas amounts related to positions entered into and settled in the same month.30

11. COMMODITY DERIVATIVE CONTRACT ASSETS AND LIABILITIESWe transact in derivative instruments to manage our price risk associated with fuel oil, coal anduranium. Substantially all of these derivative transactions were entered into with related parties as discussed inNote 14.Our derivative contractual assets and liabilities arise from mark-to-market accounting consistent withaccounting standards related to derivative instruments and hedging activities. The following table provides detailof commodity derivative contract assets and liabilities (with the column totals representing the net positions ofthe contracts) as reported in the balance sheet at December 31, 2012:Commodity CommodityBalance Sheet Presentation contract assets contract liabilities TotalCurrent assets .................................................................. $ 3 $ -$ 3Current liabilities ............................................................ -(29) (29)Noncurrent liabilities ......................................................- 7(. ) (17)Net assets (liabilities) ..................................................... j$ L ---= =There were no derivative positions accounted for as cash flow or fair value hedges in the year ended, orat, December 31, 2012.The pre-tax effect of commodity contracts not under hedge accounting, including realized andunrealized effects, was a $67 million loss for the year ended December 31, 2012 and was reflected in net lossfrom commodity hedging activities.Derivative Volumes -The following table presents the gross notional amounts of derivative volumesat December 31, 2012:Commodity type Notional Volume Unit of MeasureCoal 13 Million tonsDiesel fuel (coal transportation) 4 Million tons of coalFuel oil 17 Million gallonsUranium 441 Thousand poundsCredit Risk-Related Contingent Features of Derivatives -The agreements that govern our derivativeinstrument transactions may contain certain credit risk-related contingent features that could trigger liquidityrequirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certainof these agreements require the posting of collateral if the credit rating of TCEH is downgraded by one or morecredit rating agencies; however, due to TCEH's existing credit ratings being below investment grade,substantially all of such collateral posting requirements are already effective.At December 31, 2012, the fair value of liabilities related to derivative instruments under agreementswith credit risk-related contingent features that were not fully cash collateralized totaled less than $1 million.The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with thecounterparties totaling $3 million at December 31, 2012. Therefore, our derivative instruments were fullycollateralized as of December 31, 2012.Concentrations of Credit Risk Related to Derivatives -At December 31, 2012, we had noconcentrations of credit risk with any unaffiliated counterparties to derivative contracts and both the gross andnet credit risk exposure to affiliated counterparties related to derivative contracts totaled $3 million. All creditexposure was with Luminant Energy, which is under common control of Luminant Holding as discussed in Note14.31 We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. Thesepolicies authorize specific risk mitigation tools including, but not limited to, use of standardized masteragreements that allow for netting of positive and negative exposures associated with a single counterparty.Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margindeposits are also utilized. Prospective material changes in the payment history or financial condition of acounterparty or downgrade of its credit quality result in the reassessment of the credit limit with thatcounterparty. The process can result in the subsequent reduction of the credit limit or a request for additionalfinancial assurances. An event of default by one or more counterparties could subsequently result intermination-related settlement payments that reduce available liquidity if amounts are owed to the counterpartiesrelated to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amountsto us.12. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANSPension PlanWe are a participating employer in the EFH Retirement Plan ("the Plan"), a defined benefit pensionplan sponsored by EFH Corp. The Plan is a qualified pension plan under Section 401(a) of the Internal RevenueCode of 1986, as amended (Code) and is subject to the provisions of ERISA. All benefits are funded by theparticipating employers. The Plan provides benefits to participants under one of two formulas: (i) a CashBalance Formula under which participants earn monthly contribution credits based on their compensation and acombination of their age and years of service, plus monthly interest credits or (ii) a Traditional RetirementFormula based on years of service and the average earnings of the three years of highest earnings. The interestcomponent of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasurybonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. SinceOctober 1, 2007, all new employees, with the exception of employees hired by Oncor, have not been eligible toparticipate in the Plan. It is EFH Corp.'s policy to fund the Plan to the extent deductible under existing federaltax regulations.In August 2012, EFH Corp. approved certain amendments to the Plan. These actions were completed inthe fourth quarter 2012 and the amendments resulted in:* splitting off assets and liabilities under the Plan associated with employees of Oncor and all retireesand terminated vested participants of EFH Corp. and its subsidiaries (including discontinuedbusinesses and Generation) to a new plan sponsored and administered by Oncor ("Oncor Plan");* splitting off assets and liabilities under the Plan associated with active employees of EFH Corp.'scompetitive businesses, other than collective bargaining unit (union) employees, to a TerminatingPlan, freezing benefits and vesting all accrued plan benefits for these participants;" the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilitiesunder the Terminating Plan, and* maintaining assets and liabilities associated with union employees of EFH Corp. competitivebusinesses under the Plan.Settlement of the Terminating Plan obligations and the full funding of the EFH Corp.'s competitiveoperations portion of liabilities (including discontinued businesses and Generation) under the Oncor Planresulted in an aggregate cash contribution by EFH Corp.'s competitive operations of $259 million in the fourthquarter 2012.32 EFH Corp.'s competitive operations recorded charges totaling $285 million in the fourth quarter 2012,including $92 million related to the settlement of the Terminating Plan and $193 million related to thecompetitive business obligations (including discontinued businesses and Generation) that are being assumedunder the Oncor Plan. These amounts represent the previously unrecognized actuarial losses reported in EFHCorp.'s accumulated other comprehensive income (loss). Generation's allocated share of these charges totaled$95 million and is expected to settle with TCEH and EFH Corp. in the first quarter 2013.We also participate in EFH Corp.'s supplemental unfunded retirement plans for certain employeeswhose retirement benefits cannot fully be earned under the qualified Retirement Plan, the information for whichis included below.Other Postretirement Employee Benefit (OPEB) PlanWe also participate with EFH Corp. and certain other affiliated subsidiaries of EFH Corp. to offerOPEB in the form of health care and life insurance to eligible employees and their eligible dependents upon theretirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributionsrequired for such coverage vary based on a formula depending on the retiree's age and years of service. In 2011,we announced a change to the OPEB plan whereby, effective January 1, 2013, Medicare-eligible retirees fromthe competitive business will be subject to a cap on increases in subsidies received under the plan to offsetmedical costs.Pension and OPEB Costs Recognized as ExpenseThe following details net pension and OPEB costs recognized as expense. The pension and OPEBamounts provided represent allocations to us of amounts related to EFH Corp.'s plans.Year-EndedDecember 31,2012Pension costs (a) ......................................................................................................... $ 130O P E B costs ................................................................................................................. ITotal benefit costs recognized as expense ..........................................................(a) As a result of pension plan actions discussed above., $130 million included $95 million recorded byGeneration as a settlement charge.For determining net periodic pension costs, EFH Corp. uses the calculated value method to determinethe market-related value of the assets held in trust. EFH Corp. includes the realized and unrealized gains orlosses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains andlosses for the current year and for each of the preceding three years is included in the market-related value. Eachyear, the market-related value of assets is increased for contributions to the plan and investment income and isdecreased for benefit payments and expenses for that year. For determining net periodic OPEB costs, EFH Corp.uses the fair value of assets held in trust.Regulatory Recovery of Pension and OPEB CostsThe Texas Public Utility Regulatory Act provides for the recovery by Oncor, in its regulated revenuerates, of pension and OPEB costs applicable to services of Oncor's active and retired employees, as well asservices for active and retired personnel engaged in TCEH's (including Generation) activities, related to theirservice prior to the deregulation and disaggregation of EFH Corp.'s electric utility business effective January 1,2002. Accordingly, Oncor and TCEH entered into an agreement whereby Oncor assumed responsibility forapplicable pension and OPEB costs related to those personnel.33 Additional Plan Participation DisclosuresWe have not been allocated any overfunded asset or underfunded liability related to our participation inEFH Corp.'s pension and OPEB plans. However, TCEH is jointly and severally liable for all EFH Corp. pensionand OPEB plan liabilities, and we are subject to certain risks including the following:* Funding/assets contributed by us may be used to provide benefits to employees from otherparticipating entities;" We may be required to bear the unfunded obligations of another participating employer that stopsmaking contributions, and* If we stop participating, we may be required to pay an amount to the plan based on the underfundedstatus of the plan.Our share of contributions to the Plan was 26% for the year ended December 31, 2012. The Plan was atleast 80% funded for those periods as determined under the provisions of ERISA. The Employer IdentificationNumber of the Retirement Plan is 75-26693 10 and the plan number is 002.Assumed Discount RateThe discount rate assumed for pension costs was 5.00% for January through July 2012, 4.15% forAugust through September 2012 and 4.20% for October through December 2012. The discount rate assumed forOPEB costs was 4.95% for the year ended December 31, 2012. The expected rate of return on plan assetsreflected in the 2012 cost amounts is 7.4% and 6.8% for the pension plan assets and OPEB assets, respectively.Thrift PlanOur employees may participate in a qualified savings plan, the EFH Thrift Plan (Thrift Plan). This planis a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and issubject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more thanthe IRS threshold compensation limit used to determine highly compensated employees may contribute, throughpre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages orthe maximum amount permitted under applicable law. Employees who earn more than such threshold maycontribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made inan amount equal to 100% of the first 6% of employee contributions for employees who are not covered by theRetirement Plan or who are covered under the Cash Balance Formula of the Retirement Plan, and 75% of thefirst 6% of employee contributions for employees who are covered under the Traditional Retirement PlanFormula of the Retirement Plan. Employer matching contributions are made in cash and may be allocated byparticipants to any of the plan's investment options. Our contributions to the Thrift Plan totaled $14 million forthe year ended December 31, 2012.34

13. STOCK-BASED COMPENSATIONIn December 2007, EFH Corp. established the 2007 Stock Incentive Plan for Key Employees of EFHCorp. and its Affiliates (2007 SIP). We bear the costs of EFH Corp.'s 2007 SIP for applicable managementpersonnel engaged in our business activities. Incentive awards under the 2007 SIP may be granted to directorsand officers and qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferred shares, shares of common stock, theopportunity to purchase shares of common stock and other awards that are valued in whole or in part byreference to, or are otherwise based on the fair market value of EFH Corp.'s shares of common stock. Expenserecognized related to stock compensation totaled $3 million in the year ended December 31, 2012, whichincluded $2 million related to time-based stock options that were exchanged for restricted stock units in 2011.The remainder relates to restricted stock units discussed below.Restricted Stock UnitsRestricted stock unit activity for our employees in 2012, consisted of grants of 190 thousand units andforfeitures of 170 thousand units. Restricted stock units vest as common stock of EFH Corp, upon the earlier ofSeptember 2014 or a change of control, or on a prorated basis upon certain defined events such as termination ofemployment. Compensation expense per unit is based on the estimated value of EFH Corp. stock at the grantdate, less a marketability discount factor. To determine expense related to units issued in exchange for stockoptions, the unit value is further reduced by the fair value of the options exchanged. For the year endedDecember 31, 2012, $1 million of compensation expense was recognized for restricted stock units, and atDecember 31, 2012, there was approximately $3 million of unrecognized compensation expense related tononvested restricted stock units expected to be recognized through September 2014.14. RELATED-PARTY TRANSACTIONSThe following represent our significant related-party transactions:We operate certain lignite/coal and natural gas-fueled generation units owned by affiliates. Theaffiliates are subsidiaries of Luminant Holding, which directs the operations of the affiliates. We bill our costs tooperate these units with no profit component. As agent of the affiliates, we net the costs incurred with therevenues received for financial statement presentation purposes. For the year ended December 31, 2012, costsbilled totaled $263 million, of which $29 million represented employee-related costs.We have a contract mining agreement to mine and deliver lignite to Sandow Power Company LLC, adirect, wholly-owned subsidiary of Luminant Holding. We net the costs incurred related to the mining anddelivery of lignite with the revenues received. For the year ended December 31, 2012, net revenues related tothis agreement totaled $27 million.Our electricity sales to Luminant Energy totaled $1.855 billion for the year ended December 31, 2012.The revenue recorded reflects transfer prices, based on a capacity charge and an incremental energy payment,under an annual agreement with Luminant Energy. The substantial majority of the accounts receivable fromaffiliates balance of $159 million at December 31, 2012 relates to electricity sales to Luminant Energy.We purchase electricity from Luminant Energy for our internal power requirements. These purchasedpower costs, which are reported in fuel and purchased power costs, totaled $8 million for the year endedDecember 31, 2012. The expense recorded reflects transfer prices, based on a capacity charge and anincremental energy payment, under an annual agreement with Luminant Energy.35 In August 2012, we and Oncor agreed to settle at a discount two agreements related to securitization(transition) bonds issued by Oncor's bankruptcy-remote financing subsidiary in 2003 and 2004 to recovergeneration-related regulatory assets. Under the agreements, we had been reimbursing Oncor as describedimmediately below. Under the settlement, we paid, and Oncor received, $159 million in cash. The settlementwas executed by EFIH acquiring the rights to reimbursement under the agreements from Oncor and then sellingthese rights to us for the same amount. The transaction resulted in a $2 million (after tax) increase inmembership interests for the year ended December 31, 2012 in accordance with accounting rules for relatedparty transactions.Oncor collects transition surcharges from its customers to recover the transition bond paymentobligations. Oncor's incremental income taxes related to the transition surcharges it collects had beenreimbursed by us quarterly under a noninterest bearing note payable to Oncor that was to mature in 2016. Thenote balance at the August 2012 settlement date totaled $159 million. Our payments on the note totaled $20million for the year ended December 31, 2012.Under an interest reimbursement agreement, we had reimbursed Oncor on a monthly basis for interestexpense on the transition bonds. The remaining interest to be paid through 2016 under the agreement totaled $53million at the August 2012 settlement date. Only the monthly accrual of interest under this agreement wasreported as a liability. This interest expense totaled $16 for the year ended December 31, 2012.Advances to parent/affiliates (primarily Luminant Holding) totaled $4.693 billion at December 31,2012. The advances are due upon demand but can be settled as a dividend from us, such as our dividend of $1.5billion in December 2012 (see Note 9), or through receipts of assets other than cash. Of the total advanceamount, $4.668 billion was classified as noncurrent as this amount is not anticipated to settle within the nexttwelve months, and $25 million was classified as current representing amounts that Generation owes to itsparent/affiliates that are anticipated to settle in the next twelve months. The advances to parent/affiliates accrueinterest at a rate based on the weighted average cost of short-term borrowings under the TCEH Revolving CreditFacility plus a weighted average spread of 84 basis points, and such interest is paid monthly. For the year endedDecember 31, 2012, net interest income earned on these advances totaled $326 million. The average dailybalance of the advances totaled $6.169 billion and the weighted average annual interest rate was 5.29% for theyear ended December 31, 2012.A subsidiary of EFH Corp. bills us for information technology, financial, accounting and otheradministrative services at cost. These charges, which are settled in cash and primarily reported in selling,general and administrative expenses, totaled $100 million for the year ended December 31, 2012. Effective in2012, we reimburse a subsidiary of EFH Corp. for an allocated share of computer equipment purchased by thesubsidiary. Amounts we paid in 2012 included existing computer equipment and totaled $18 million, which wasaccounted for as an intangible asset to be amortized over the life of the equipment. Previously the depreciationof such equipment was included in the administrative cost billings.Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nucleargeneration facility is funded by a delivery fee surcharge billed to retail electric providers by Oncor, as collectionagent, and remitted monthly to us for contribution in the trust fund with the intent that the trust fund assets,reported in investments in our balance sheet, will ultimately be sufficient to fund the actual futuredecommissioning liability, reported as other noncurrent liabilities in our balance sheet. The delivery feesurcharges remitted to us totaled $16 million for the year ended December 31, 2012. Income and expensesassociated with the trust fund and the decommissioning liability that we incur are offset by a net change in anoncurrent receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates. AtDecember 31, 2012, the excess of the trust fund balance over the decommissioning liability resulted in a payabletotaling $284 million reported in other noncurrent liabilities and deferred credits in our balance sheet.We lease nine combustion turbines from an affiliate lease trust. The terms of the lease are the same asthey were prior to our affiliate's purchase of the trust from a third party. Our lease expense under the lease trusttotaled $10 million for the year ended December 31, 2012 and is reported as operating costs.36 We purchase diesel fuel for mining and power plant activities and coal for our generation units fromLuminant Energy on an as needed basis. Our diesel fuel cost totaled $48 million and our purchased coal costtotaled $37 million for the year ended December 31, 2012. These expenses are based on transfer prices underagreements with Luminant Energy. Purchases are recorded as inventory then charged to fuel costs as used.We enter into forward contracts and other financial instruments with Luminant Energy to hedge theprice risk of various commodities, which we account for as derivatives, with changes in fair value recorded toearnings. The following table reflects the hedged commodity, the volume hedged, the duration of the underlyingcontracts and the financial statement effects resulting from these contracts.December 31, 2012Financial Statement Line ItemGain (loss) from commodityCommodity derivative contract derivative contractsCurrent Current NoncurrentCommodity Quantity Duration asset liability liability Realized UnrealizedFuel oil (a) 4 million tons 2013 $ 1 $ -$ -$ 20 $ (16)17 millionFuel oil gallons 2013 2 -2Coal (b) 12 million tons 2013-2014 -26 15 (30) (31)Uranium 441 thousandpounds 2013-2015 -3 2 (1) (4Total ...................................................................... $ 3 $ 2 9 17 $ _ ._(a) This fuel oil is used to hedge rail transportation of coal; therefore, it is measured in million tons of coal.(b) Excludes third-party contracts for I million tons of coal for 2013 that resulted in realized losses of $10 million andunrealized mark-to-market gains of $3 million.EFH Corp. files consolidated federal income tax and Texas state margin tax returns that include ourresults; however, under a tax sharing agreement, our federal income tax and Texas margin tax expense andrelated balance sheet amounts, including income taxes receivable from or payable to EFH Corp., are recorded asif we file our own corporate income tax returns. At December 31, 2012, we had income taxes receivable fromEFH Corp. of $15 million. In the year ended December 31, 2012, we'made payments totaling $21 million toEFH Corp. related to income taxes for prior years, and made net payments totaling $13 million to EFH Corp. for2012 estimated income taxes.See Note 7 for discussion of our guarantees of certain TCEH debt, Note 9 for discussion of distributionsto and contributions from our parent, Note 12 for discussion of pension and OPEB costs allocated to us, andNote 13 for discussion of stock-based compensation.37

15. SUPPLEMENTARY FINANCIAL INFORMATIONInventories by Major CategoryDecember 31, 2012M aterial and supplies ................................................................................ $ 151Fuel stock ........................................................................................... ...... 86Natural gas in storage ............................................................................. .4Total inventories ............................................................................... .__ __-- 4InvestmentsThe investments balance consists of the following:December 31, 2012Nuclear plant decommissioning trust ....................................................... $ 654L and ............................................................................................. .......... 4 1Assets related to employee benefit plans, including employee savingsprograms, net of distributions ................................................................. .6O ther ....................................................................................................... .2Total investments .....................................Nuclear Decommissioning Trust -Investments in a trust that will be used to fund the costs todecommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs arebeing recovered from Oncor's customers as a delivery fee surcharge over the life of the plant and deposited inthe trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding change in areceivable/payable that will ultimately be settled through changes in Oncor's delivery fees rates (see Note 14).A summary of investments in the fund follows:December 31, 2012Unrealized Fair marketCost (a) gain Unrealized loss valueDebt securities (b) ............. $ 246 $ 16 $ (1) $ 261Equity securities (c) .......... 245 161 _(I3) 393Total ....................... $ A91 SL177 L )__654(a) Includes realized gains and losses of securities sold.(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overallportfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavilyweighted with municipal bonds. The debt securities had an average coupon rate of 4.38% and an averagematurity of 6 years at December 31, 2012.(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of theS&P 500 Index.Debt securities held at December 31, 2012 mature as follows: $94 million in one to five years, $55million in five to ten years and $112 million after ten years.38 The following table summarizes investments in available-for-sale securities as well as proceeds fromsales of available-for-sale securities and the related realized gains and losses from such sales.Year EndedDecember 31, 2012Realized gains ....................................................................Realized losses ...................................................................Proceeds from sales of securities .......................................Investments in securities ....................................................1(2)$ 106$ (122)Property, Plant and EquipmentDecember 31, 2012Plant and m ine assets (a) ............................................................................ $ 16,554Less accumulated depreciation ............................................................... .. .(4.543)Net of accum ulated depreciation ........................................................ 12,011Construction work in progress ................................................................... 354Nuclear fuel (net of accumulated amortization: $941) ............................... 328Property, plant and equipment -net ...................................................(a) See discussion below regarding the nuclear generation plant decommissioning liability.Depreciation expense totaled $874 million for the year ended December 31, 2012.Assets related to capital leases included above total $58 million at December 31, 2012, net ofaccumulated depreciation.Asset Retirement and Mining Reclamation ObligationsThese liabilities primarily relate to nuclear generation plant decommissioning, land reclamation relatedto lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestosremoval and disposal costs. There is no earnings impact with respect to changes in the nuclear decommissioningliability, as all costs are recoverable through the regulatory process as part of Oncor's delivery fees rates (seeNote 14).The following table summarizes the changes to these obligations, reported as current and noncurrentliabilities in the balance sheet, for the year ended December 31, 2012:Liability at January 1, 2012 .................Additions:Accretion...................................Incremental reclamation costs (a) ......Reductions:Payments ...................................Liability at December 31, 2012.............Less amounts due currently ..............Noncurrent liability at December 3 1,2012Nuclear PlantDecommissioning$ 34820368Mining LandReclamation andOther$ 1272626(68)III(54)Total$ 4754626(68479(54)(a) Reflecting additional land to be reclaimed39 Unfavorable ContractsDeferred credit related to unfavorable contracts-net consists of the following:December 31, 2012GrossCarrying AccumulatedAmount Amortization NetUnfavorable sale contract .................................................. $ 737 $ (123) $ 614U nfavorable lease .............................................................. 11 _ 5Total unfavorable contracts subject to amortization .... L$ 61Unfavorable contracts represent the extent to which contracts were unfavorable to market prices at thedate of the Merger. These are contracts for which: i) we have made the "normal" purchase or sale electionallowed or ii) the contract did not meet the definition of a derivative under accounting standards related toderivative instruments and hedging transactions. Under purchase accounting, we recorded the value at October10, 2007 as a deferred credit. The deferred credits related to unfavorable contracts are amortized on a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of operatingcosts as appropriate. Favorable contracts are recorded as identifiable intangible assets (see Note 3).Amortization of unfavorable contracts totaled $25 million for the year ended December 31, 2012. The estimatedamortization of unfavorable contracts is $25 million for each of the next five fiscal years.Other Noncurrent Liabilities and Deferred CreditsThe balance of other noncurrent liabilities and deferred credits consists of the following:December 31, 2012Uncertain tax positions (including accrued interest) ................... $ 1,138Nuclear decommissioning cost over-recovery (Note 14) ............ 284Retirement plan and other employee benefits ............................ 21O ther ........................................................................................... 7Total other noncurrent liabilities and deferred credits ................Supplemental Cash Flow InformationYear EndedDecember 31, 2012Cash payments (receipts):Interest paid ........................................................................ $ 19Incom e taxes, net ................................................................ $ 34Noncash investing and financing activities:Dividend to parent (Note 9) ................................................ $ 1,500Construction expenditures (a) ............................................. $ 32Contribution related to EFH Corp. stock-basedcom pensation ...................................................................... $ 3(a) Represents end-of-period accruals.40

Enclosure

12 with TXX-13095Standard Practice Procedures Plan (SPPP) Standard Practice Procedures PlanThe following Standard Practice Procedures Plan applies to facilities authorized to use but notpossess classified information.This document outlines the security responsibilities of:Luminant Generation Company LLC (Luminant Power)With its principal office and place of business at:1601 Bryan StreetDallas, Tx 75201Doing business at the address below:Luminant PowerComanche Peak Nuclear Power Plant6322 N. FM 56, PO Box 1002Glen Rose, Texas 76043The provisions of our license with the Nuclear Regulatory Commission (NRC) do not requireour company to receive, store, transmit, or originate classified information within our facility.This company's personnel will, however, have authorized access to classified information atapproved NRC facilities. The NRC security clearances granted our personnel have beenissued by NRC Headquarters.We understand our company will be responsible for ensuring that the following securityrequirements are met:* Initial and Refresher briefings (annually) are conducted and documented as requiredby 10 CFR Part 95, and that the SF-312, Classified Information NondisclosureAgreement Form, is signed and processed prior to any access to classified information.* Termination briefings are conducted and documented in accordance with 10 CFRParts 25 and 95 for all cleared personnel leaving our employment, losing theirclearances, or no longer requiring a clearance. Termination statements are forwardedto NRC Headquarters.* Provisions of the Privacy Act are met when handling and mailing/delivering completedpersonnel security clearance request documents.* Cleared company personnel are apprized of and comply with the personnel clearancereporting requirements.* Foreign national employees are not placed in a position to exercise control or influenceover properly cleared U.S. citizens who have been granted access to NRC classifiedinformation.* Reporting requirements involving foreign ownership, control, or influence conditionsare complied with. Procedures are developed describing internal company processes for performingfunctions to accomplish each of the items above. Applicable company employees willbe familiar and comply with security procedures and be informed of their individualresponsibilities in executing and supporting these procedures.Designated representatives of NRC are required periodically to inspect the procedures,methods, and facilities utilized by the company in complying with the requirements ofthe terms and conditions of 10 CFR Parts 25 and 95. The company shall assist byproviding necessary documentation for review.CERTIFICATIONSI have been designated Facility Security Officer and will be responsible for ensuring the aboverequirements are complied with.Signature and DateKenn TateTyped Name254-897-6644Phone NumberThe management representative undersigned certifies that the Facility Security Officer hasbeen given the resources and management support needed to accomplish the above. A newStandard Practice Procedures Plan will be executed if a new Facility Security Officer isappointed.Certified By (typed name): Rafael FloresTitle: Senior Vice President and Chief Nuclear OfficerSignature and Date: _141/3 }}