CP-201400072, Guarantees of Payment of Deferred Premiums

Guarantees of Payment of Deferred Premiums

ML14052A248
Person / Time
Site:	Comanche Peak
Issue date:	02/06/2014
From:	Flores R, Thomas McCool Luminant Generation Co, Luminant Power
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CP-201400072, TXX-14006
Download: ML14052A248 (100)

Text

I~

Rafael Flores 0

Luminant Power Senior Vice President PB 8ox 1002

& Chief Nuclear Officer 6322 North FM 56 rafael.flores@Luminant.com Glen Rose, TX 76043 Luminant T 254 897 5590 C 817 559 0403 F 254 897 6652 CP-201400072 Ref. # 10 CFR 140.21(e)

Log # TXX-14006 February 6, 2014 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

COMANCHE PEAK NUCLEAR POWER PLANT (CPNPP)

DOCKET NOS. 50-445 AND 50-446 GUARANTEES OF PAYMENT OF DEFERRED PREMIUMS

Dear Sir or Madam:

Pursuant to 10CFR140.21(e), Luminant Generation Company LLC (Luminant Power) hereby submits condensed consolidated financial statements for Energy Future Holdings Corp as of September 30, 2013 (enclosed), to demonstrate the Company's ability to pay deferred premiums under the Secondary Financial Program ($18,963,000). The cash flow for the quarterly period ending September 30, 2013 is found on page 3 and 4 of the report.

This communication contains no licensing basis commitments regarding Comanche Peak Units 1 and 2.

Should you have any questions, please contact Mr. J. Seawright at (254) 897-0140.

Sincerely, Luminant Generation Company LLC Rafael Flores By:

Thomas P. McCool Vice President, Station Support Enclosure - Energy Future Holdings Corp 10Q as of September 30,2013 c- Marc L. Dapas, Region IV B. K. Singal, NRR Resident Inspectors, Comanche Peak A member of the STARS Alliance Callaway

• Comanche Peak

• Diablo Canyon

• Palo Verde

• Wolf Creek

Table of Contents UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q El QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013

-- OR-D TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-12833 Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

Texas 46-2488810 (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)

Indicate 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 Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes El No 0

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data 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 IE No 0 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. 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 [] (Do not check ifa smaller reporting company)

Smaller reporting company 01 Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes 0 No El At October 31, 2013, there were 1,669,861,383 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 holding company, and none of which is publicly traded).

Table of Contents TABLE OF CONTENTS PAGE GLOSSARY PART 1. FINANCIAL INFORMATION Item 1. Financial Statements (Unaudited)

Condensed Statements of Consolidated Income (Loss) -

Three and Nine Months Ended September 30. 2013 and 2012 I Condensed Statements of Consolidated Comprehensive Income (Loss) -

Three and Nine Months Ended September 30.2013 and 2012 I Condensed Statements of Consolidated Cash Flows -

Nine Months Ended September 30. 2013 and 2012 2 Condensed Consolidated Balance Sheets - September 30. 2013 and December 31.2012 Notes to Condensed Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 47 Item 3. Ouantitative and Oualitative Disclosures About Market Risk 75 Item 4. Controls and Procedures PART II. OTHER INFORMATION Item 1. Leeal Proceedings Item IA. Risk Factors Item 4. Mine Safety Disclosures 81 Item 5. Other Information 81 Item 6. Exhibits SIGNATURE 85 Energy Future Holdings Corp.'s (EFH Corp.) annual reports on Form 10-K, quarterly reports on Form I0-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the EFH Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on EFH Corp.'s website shall not be deemed a part of, or incorporated by reference into, this quarterly report on Form 10-Q. The representations and warranties contained in any agreement that we have filed as an exhibit to this quarterly report on Form I0-Q or that we have or may publicly file in the future may contain representations and warranties made by and to the parties thereto at specific dates. Such representations and warranties may be subject to exceptions and 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 quarterly report on Form I0-Q and other Securities and Exchange Commission filings of EFH Corp. and its subsidiaries occasionally 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 reflect the fact that the subsidiaries are consolidated with, 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 parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

Table of Corutents GLOSSARY When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

2012 Form 10-K EFH Corp.'s Annual Report on Form 10-K for the year ended December 31, 2012 Adjusted EBITDA Adjusted EBITDA means EBITDA adjusted to exclude noncash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under US GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form IO-Q (see reconciliations in Exhibits 99(b), 99(c) and 99(d)) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance 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's discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.

CAIR Clean Air Interstate Rule CFTC US Commodity Futures Trading Commission Competitive Electric segment the EFH Corp. business segment that consists principally of TCEH CREZ Competitive Renewable Energy Zone CSAPR the final Cross-State Air Pollution Rule issued by the EPA in July 2011, vacated by the US Court of Appeals for the District of Columbia Circuit in August 2012 and accepted for review by the US Supreme Court in June 2013 (see Note 6 to Financial Statements)

D.C. Circuit Court US Court of Appeals for the District of Columbia Circuit EBITDA earnings (net income) before interest expense, income taxes, depreciation and amortization EFCH Energy Future Competitive Holdings Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context EFH Corp. Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context, whose major subsidiaries include TCEH and Oncor EFIH Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings EFIH Finance EFIH Finance Inc., a direct, wholly owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities EFIt Notes Refers, collectively, to EFIH's and EFIH Finance's 6.875% Senior Secured Notes due August 15, 2017 (EFIH 6.875% Notes), 9.75% Senior Notes due October 15, 2019 (EFIH 9.75% Notes), 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% Notes), 11% 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) and 11.25/12.25% Senior Toggle Notes due December 1, 2018 (EFIH Toggle Notes).

EPA US Environmental Protection Agency ERCOT Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas ERISA Employee Retirement Income Security Act of 1974, as amended Fifth Circuit Court US Court of Appeals for the Fifth Circuit GAAP generally accepted accounting principles GWh gigawatt-hours ICE the IntercontinentalExchange, a commodity exchange ii

Table of Contents IRS US Internal Revenue Service LIBOR London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market Luminant subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas market heat rate Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, 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 wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.

MATS the Mercury and Air Toxics Standard established by the EPA Merger The 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 October 10, 2007.

MMBtu million British thermal units MW megawatts MWh megawatt-hours NERC North American Electric Reliability Corporation NOx nitrogen oxides NRC US Nuclear Regulatory Commission NYMEX the New York Mercantile Exchange, a physical commodity futures exchange Oneor Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities Oncor Holdings Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context Oncor Ring-Fenced Entities Oncor Holdings and its direct and indirect subsidiaries, including Oncor OPEB other postretirement employee benefits PUCT Public Utility Commission of Texas purchase accounting The 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 paid for 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 price over the fair values of assets and liabilities is recorded as goodwill.

Regulated Delivery segment the EFH Corp. business segment that consists primarily of our investment in Oncor REP retail electric provider RCT Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas S&P Standard & Poor's Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)

SEC US Securities and Exchange Commission iii

Table of Contents Securities Act Securities Act of 1933, as amended SG&A selling, general and administrative SO, sulfur dioxide Sponsor Group Refers, 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, an affiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Holdings.

TCEH Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of EFCH 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 Energy TCEH Demand Notes Refers to certain loans from TCEH to EFH Corp. in the form of demand notes to finance EFH Corp. debt principal and interest payments and, until April 2011, other general corporate purposes of EFH Corp., that were guaranteed on a senior unsecured basis by EFCH and EFIH and were settled by EFH Corp. in January 2013.

TCEH Finance TCEH Finance, Inc., a direct, wholly owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities TCEH Senior Notes Refers, 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 November 1, 2016 (TCEH Toggle Notes).

TCEH Senior Secured Facilities Refers, collectively, to the TCEH Term Loan Facilities, TCEH Revolving Credit Facility and TCEH Letter of Credit Facility. See Note 5 to Financial Statements for details of these facilities.

TCEH Senior Secured Notes TCEH's and TCEH Finance's 11.5% Senior Secured Notes due October 1, 2020 TCEH Senior Secured Second Lien Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes due April 1, 2021 Notes and TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.

TCEQ Texas Commission on Environmental Quality Texas Holdings Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group, that owns substantially all of the common stock of EFH Corp.

Texas Holdings Group Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities TXU Energy TXU Energy Retail Company LLC, a direct, wholly owned subsidiary of TCEH that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers US United States of America VIE variable interest entity iv

Table of Contents PART 1. FINANCIAL INFORMATION Item 1. FINANCIAL STATEMENTS ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 (millions of dollars)

Operating revenues 1,893 $ 1,752 $ 4,572 $ 4,358 Fuel, purchased power costs and delivery fees (852) (850) (2,175) (2,153)

Net gain (loss) from commodity hedging and trading activities 58 (3) 29 229 Operating costs (189) (201) (685) (636)

Depreciation and amortization (335) (335) (1,030) (1,015)

Selling, general and administrative expenses (202) (177) (540) (491)

Franchise and revenue-based taxes (18) (19) (51) (55)

Other income (Note 13) 5 6 19 25 Other deductions (Note 13) (36) (42) (40) (54)

Interest income -- 1 1 2 Interest expense and related charges (Note 13) (533) (944) (1,915) (2,746)

Loss before income taxes and equity in earnings of unconsolidated subsidiaries (209) (812) (1,815) (2,536)

Income tax benefit 100 296 925 879 Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2) 114 109 255 249 Net income (loss) $ 5 $ (407) $ (635) $ (1,408)

See Notes to Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 (millions of dollars)

Net income (loss) $ 5 $ (407) $ (635) $ (1,408)

Other comprehensive income (loss), net of tax effects:

Effects related to pension and other retirement benefit obligations (net of tax benefit of $1, $18, $2 and $13) (1) (33) (4) (25)

Cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $I,

$1, $3 and $3) 5 5 Net effects related to Oncor - reported in equity in earnings of unconsolidated subsidiaries (net of tax benefit of -- ,

and $I) 1 1 1 2 Total other comprehensive income (loss) 1 (31) 2 (18)

Comprehensive income (loss) 6 $ (438) $ (633) $ (1,426)

See Notes to Financial Statements.

1

Table of Contents ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)

Nine Months Ended September 30, 2013 2012 (millions of dolhars)

Cash flows - operating activities:

Net loss $ (635) $ (1,408)

Adjustments to reconcile net loss to cash provided by (used in) operating activities:

Depreciation and amortization 1,160 1,161 Deferred income tax benefit, net (612) (887)

Income tax benefit due to audit resolutions (Note 13) (305)

Unrealized net loss from mark-to-market valuations of commodity positions 693 1,290 Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps (Note 13) (903) 12 Interest expense on toggle notes payable in additional principal (Notes 5 and 13) 130 177 Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 13) 175 183 Equity in earnings of unconsolidated subsidiaries (255) (249)

Distributions of earnings from unconsolidated subsidiaries 148 100 Asset impairments (Note 13) 30 31 Bad debt expense (Note 4) 23 20 Accretion expense related primarily to mining reclamation obligations (Note 13) 24 27 Stock-based incentive compensation expense 5 10 Other, net 2 3 Changes in operating assets and liabilities:

Margin deposits, net (197) (321)

Other operating assets and liabilities 248 (51)

Cash provided by (used in) operating activities (269) 98 Cash flows - financing activities:

Issuances of long-term debt (Note 5) 2,000 Repayments/repurchases of long-term debt (Note 5) (94) (31)

Net short-term borrowings under accounts receivable securitization program (Note 4) 90 80 Decrease in other short-term borrowings (Note 5) (385)

Decrease in note payable to unconsolidated subsidiary (Note 11) (20)

Settlement of agreements with unconsolidated affiliate (Note 11) (159)

Saleileaseback of equipment 15 Contributions from noncontrolling interests 3 6 Debt amendment, exchange and issuance costs and discounts, including third-party fees expensed (9) (43)

Other, net (5)

Cash provided by (used in) financing activities (15) 1,463 2

Table of Contents ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)

Nine Months Ended September 30, 2013 2012 (millions of dollars)

Cash flows - investing activities:

Capital expenditures S (372) $ (526)

Nuclear fuel purchases (59) (155)

Proceeds from sales of assets 3 1 Acquisition of combustion turbine trust interest (Note 5) (40) -

Restricted cash investment used to settle TCEH Demand Notes (Note 11) 680 (680)

Other changes in restricted cash (4) 112 Purchases of environmental allowances and credits (13) (19)

Proceeds from sales of nuclear decommissioning trust fund securities 128 56 Investments in nuclear decommissioning trust fund securities (140) (68)

Other, net 4 4 Cash provided by (used in) investing activities 187 (1,275)

Net change in cash and cash equivalents (97) 286 Cash and cash equivalents - beginning balance 1,913 826 Cash and cash equivalents - ending balance $ 1,816 $ 1,112 See Notes to Financial Statements.

3

Table of Contents ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

September 30, December 31, 2013 2012 (miflions of donars)

ASSETS Current assets:

Cash and cash equivalents 1,816 $ 1,913 Restricted cash (Note 13) 4 680 Trade accounts receivable - net (includes $573 and $445 in pledged amounts related to a VIE (Notes 2 and 4)) 808 718 Inventories (Note 13) 400 393 Commodity and other derivative contractual assets (Note 9) 1,056 1,595 Margin deposits related to commodity positions 21 71 Other current assets 64 143 Total current assets 4,169 5,513 Restricted cash (Note 13) 947 947 Receivable from unconsolidated subsidiary (Note 11) 839 825 Investment in unconsolidated subsidiary (Note 2) 5,959 5,850 Other investments (Note 13) 843 767 Property, plant and equipment - net (Note 13) 18,103 18,705 Goodwill (Note 3) 4,952 4,952 Identifiable intangible assets - net (Note 3) 1,697 1,755 Commodity and other derivative contractual assets (Note 9) 159 586 Other noncurrent assets, primarily unamortized debt amendment and issuance costs 1,022 1,070 Total assets 38,690 $ 40,970 LIABILITIES AND EQUITY Current liabilities:

Short-term borrowings (includes $172 and $82 related to a VIE (Notes 2 and 5)) 2,226 $ 2,136 Long-term debt due currently (Note 5) 38 103 Trade accounts payable 368 394 Net payables due to unconsolidated subsidiary (Note 11) 123 19 Commodity and other derivative contractual liabilities (Note 9) 691 1,044 Margin deposits related to commodity positions 353 600 Accumulated deferred income taxes 34 48 Accrued interest 761 571 Other current liabilities 387 353 Total current liabilities 4,981 5,268 Accumulated deferred income taxes 3,489 2,828 Commodity and other derivative contractual liabilities (Note 9) 782 1,556 Long-term debt, less amounts due currently (Note 5) 38,086 37,815 Other noncurrent liabilities and deferred credits (Note 13) 2,903 4,426 Total liabilities 50,241 51,893 Commitments and Contingencies (Note 6)

Equity (Note 7):

EFH Corp. shareholders' equity (11,656) (11,025)

Noncontrolling interests in subsidiaries 105 102 Total equity (11,551) (10,923)

Total liabilities and equity $ 38,690 $ 40,970 See Notes to Financial Statements.

4

Table of Contents ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES Descriptionof Business References in this report to "we," "our," "us" and "the company" are to EFH Corp. and/or its subsidiaries, as apparent in the context. See "Glossary" for defined terms.

EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries.

EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission 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 Holdings, a holding company that holds an approximate 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp.

Oncor Holdings and its subsidiaries (the Oncor Ring-Fenced Entities) are not consolidated in EFH Corp.'s financial statements in accordance with consolidation accounting standards related to variable interest entities (VIEs) (see Note 2).

TCEH operates largely in the ERCOT market, and wholesale electricity prices in that market have generally moved with the price of natural gas.

Wholesale electricity prices have significant implications to TCEH's 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, among other things: the sale in November 2008 of a 19.75% equity interest in Oncor to Texas Transmission Investment LLC (a limited liability company that owns a 19.75% equity interest in Oncor and is not affiliated with EFH Corp., any of EFH Corp.'s subsidiaries or any member of the Sponsor Group); maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor's board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or contractual obligations of any member of the Texas Holdings Group. Moreover, Oncor's operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.

We have two reportable segments: the Competitive Electric segment, consisting largely of TCEH, and the Regulated Delivery segment, consisting largely of our investment in Oncor. See Note 12 for further information concerning reportable business segments.

Liquidity Considerations EFH Corp.'s competitive business has been and is expected to continue to be adversely affected by the 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 gas were significantly higher than current prices will mature in 2013 and 2014. These market conditions challenge the long-term profitability and operating cash flows of EFH Corp.'s competitive businesses and the ability to support their significant interest payments and debt maturities, and could adversely impact their ability to obtain additional liquidity and service, refinance and/or extend the maturities of their outstanding debt.

Note 5 provides the details of debt activity in 2013 and the principal amounts and maturity dates of EFH Corp.'s and its consolidated subsidiaries' short-term borrowings and long-term debt, which includes the maturity of $3.8 billion of the TCEH Term Loan Facilities in October 2014. At September 30, 2013, TCEH has $1.3 billion of cash and cash equivalents and $171 million of available capacity under its letter of credit facility. Based on forward wholesale power prices in ERCOT, which are subject to the effects of changing market conditions, TCEH may not have sufficient liquidity, absent any financing transactions, to meet its obligations within the next twelve months.

5

Table of Contents Discussions with Creditors EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) continue to consider and evaluate possible transactions and initiatives to address their highly ieveraged balance sheets and significant cash interest requirements and have entered 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 and extensions of debt obligations and exchanges or conversions of debt for preferred or cotmnon equity or warrants, including exchanges or conversions of debt of EFH Corp., EFIH, EFCH and TCEH into preferred or common equity or warrants of EFH Corp., EFIH, EFCH, TCEH and/or any of their subsidiaries. These actions could result in holders of EFH Corp., EFIH, EFCH and TCEH debt instruments not recovering the full principal amount of those obligations.

In March and April 2013, we engaged in discussions with certain unaffiliated holders of first lien senior secured claims against EFCH, TCEH and certain of TCEH's subsidiaries (the TCEH Creditors) with respect to proposed changes to our capital structure. No agreement was reached as part of those discussions, and in September and October 2013, we engaged in further discussions with the TCEH Creditors, certain unaffiliated holders of unsecured claims against EFIH and a significant creditor with claims against TCEH, EFCH, EFIH and EFH Corp. (collectively, the Creditors) with respect to our capital structure, including the possibility ofa consensual, prepackaged restructuring transaction. Our objectives in these discussions were to promote a sustainable capital structure and maximize enterprise value of EFH Corp. and its subsidiaries by, among other things, encouraging agreement on a restructuring plan that would minimize time spent in a restructuring through a proactive and organized solution; minimizing any potential adverse tax impacts of a restructuring; maintaining the company in one consolidated group; maintaining focus on operating our businesses, and maintaining the company's high-performing work force.

We and the Creditors discussed a number of proposed changes to EFH Corp.'s capital structure. Certain proposals contemplated that some combination of EFH Corp. and certain of its subsidiaries (including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities) would implement a plan of reorganization by commencing one or more voluntary cases under Chapter 11 of the United States Bankruptcy Code (the Code). Such proposals would have resulted in a prenegotiated restructuring of EFCH's approximately $32.2 billion principal amount of debt, EFH Corp.'s approximately $650 million principal amount of debt and EFIH's approximately $7.6 billion principal amount of debt (each as of September 30, 2013 and excluding debt held by affiliates) and contemplated that after the restructuring EFH Corp. would continue to hold all of the equity interests in EFCH and EFIH; EFCH would continue to hold all of the equity interests in TCEH; and EFIH would continue to hold all of the equity interests in Oncor Holdings. Another proposal contemplated that EFIH (excluding Oncor Holdings and its subsidiaries) would implement a plan of reorganization by commencing a stand-alone voluntary case under the Code. Such proposal contemplated that after the restructuring certain creditors of EFIH would own a substantial majority of, and certain creditors of EFH Corp. and the equity holders of EFH Corp. would collectively own a minority of, the equity interests in EFIH. The confirmation of any plans of reorganization in such cases would be subject to applicable regulatory approvals. We and the Creditors have not reached agreement on the temis of any change in our capital structure.

We are not currently engaged in ongoing negotiations with the principals of any of the Creditors. Although the Creditors are not currently engaged in ongoing negotiations with us, certain of the Creditors have directed their advisors to continue to work with us and our advisors to explore further whether the parties can reach an agreement on the terms ofa consensual restructuring. We will continue to consider and evaluate a range of future changes to our capital structure, in addition to the proposed changes described above, which may include filing a voluntary case under Chapter I I of the Code for some or all of EFH Corp. and its subsidiaries (excluding the Oncor Ring-Fenced Entities).

Basis of Presentation The condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in our 2012 Form 10-K. Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Note 2). Adjustments (consisting of nonnal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. 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 the financing activities section of the statement of cash flows. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in our 2012 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

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Table of Contents Use of Estimates Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.

2. VARIABLE INTEREST ENTITIES A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. Accounting standards require consolidation of a VIE if we have (a) the power to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (primary beneficiary). 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 party relationships among 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. The maximum exposure to loss from our interests in VIEs does not exceed our carrying value.

Oncor Holdings, an indirect wholly owned subsidiary of EFH Corp. that holds an approximate 80% interest in Oncor, is not consolidated in EFH Corp.'s financial statements, and instead is accounted for as an equity method investment, because the structural and operational ring-fencing measures discussed in Note 1 prevent us from having power to direct the significant activities of Oncor Holdings or Oncor. In accordance with accounting standards, we account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, based on our level of influence over its activities. See below for additional information about our equity method investment in Oncor Holdings. There are no other material investments accounted for under the equity or cost method.

Consolidated VIEs See discussion in Note 4 regarding the VIE related to our accounts receivable securitization program that is consolidated under the accounting standards.

We also consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existing Comanche Peak nuclear-fueled generation facility using MHI's US-Advanced Pressurized Water Reactor technology and to obtain a combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries of TCEH 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:

September 30, December 31, September 30, Assts; 2013 2012 Uabmlifirs: 2013 December 31, 2012 Cash and cash equivalents $ 37 $ 43 Short-term borrowings $ 172 $ 82 Accounts receivable 573 445 Trade accounts payable 1 1 Property, plant and equipment 138 134 Other current liabilities 13 7 Other assets, including $3 million and $12 million of current assets 12 16 Total assets $ 760 $ 638 Total liabilities $ 186 $ 90 The assets of our consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of our consolidated VIEs do not have recourse to our assets to settle the obligations of the VIE.

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Table of Contents Non-Consolidationof Oncor andOncor Holdings Our investment in unconsolidated subsidiary as presented in the balance sheet totaled $5.959 billion and $5.850 billion at September 30, 2013 and December 31, 2012, respectively, and consists almost entirely of our interest in Oncor Holdings, which we account for under the equity method as described above. Oncor provides services, principally electricity distribution, to TCEH's retail operations, and the related revenues represented 28% and 29% of Oncor Holdings' consolidated operating revenues for the nine months ended September 30, 2013 and 2012, respectively.

See Note 11 for discussion of Oncor Holdings' and Oncor's transactions with EFH Corp. and its other subsidiaries.

Distributionsfrom Oncor Holdings - Oncor Holdings' distributions of earnings to us totaled $148 million and $100 million for the nine months ended September 30, 2013 and 2012, respectively. Distributions may not be paid except to the extent Oncor maintains a required regulatory capital structure as discussed below. At September 30, 2013, $187 million was eligible to be distributed to Oncor's members after taking into account the regulatory capital structure limit, of which approximately 80% relates to our ownership interest in Oncor. The boards of directors of each of Oncor and Oncor Holdings can withhold distributions to the extent the applicable board determines in good faith that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings.

Oncor's distributions are limited by its regulatory capital structure, which is required to be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. At September 30, 2013, Oncor's regulatory capitalization ratio was 58.7% debt and 41.3% equity. The PUCT has the authority to determine what types of debt and equity are included in a utility's debt-to-equity ratio. For purposes ofthis ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes bonds issued by Oncor Electric Delivery Transition Bond Company LLC, which were issued in 2003 and 2004 to recover specific generation-related regulatory assets and other qualified costs. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization).

See Note 11 for discussion of a tax sharing agreement with Oncor Holdings.

Oncor Holdings FinancialStatements - Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the three and nine months ended September 30, 2013 and 2012 are presented below:

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Operating revenues $ 966 $ 925 $ 2,640 $ 2,536 Operation and maintenance expenses (315) (292) (919) (873)

Depreciation and amortization (207) (201) (608) (577)

Taxes other than income taxes (112) (113) (315) (313)

Other income 4 6 14 20 Other deductions (2) (l) (11) (4)

Interest income 3 2 24 Interest expense and related charges (94) (96) (283) (279)

Income before income taxes 240 231 520 534 Income tax expense (97) (95) (199) (221)

Net income 143 136 321 313 Net income attributable to noncontrolling interests (29) (27) (66) (64)

Net income attributable to Oncor Holdings $ 114 $ 109 $ 255 $ 249 8

Table of Contents Assets and liabilities of Oncor Holdings at September 30, 2013 and December 31, 2012 are presented below:

September 30, December 31, 2013 2012 ASSETS Current assets:

Cash and cash equivalents $ 17 $ 45 Restricted cash 61 55 Trade accounts receivable - net 404 338 Trade accounts and other receivables from affiliates 158 53 Inventories 67 73 Accumulated deferred income taxes 35 26 Prepayments and other current assets 82 82 Total current assets 824 672 Restricted cash 16 16 Other investments 85 83 Property, plant and equipment-- net 11,794 11,318 Goodwill 4,064 4,064 Regulatory assets - net 1,512 1,788 Other noncurrent assets 70 78 Total assets $ 18,365 $ 18,019 LIABILITIES Current liabilities:

Short-term borrowings $ 860 $ 735 Long-term debt due currently 129 125 Trade accounts payable - nonaffiliates 100 121 Income taxes payable to EFH Corp. 35 34 Accrued taxes other than income 134 153 Accrued interest 65 95 Other current liabilities 111 110 Total current liabilities 1,434 1,373 Accumulated deferred income taxes 1,881 1,736 Investment tax credits 22 24 Long-term debt, less amounts due currently 5,422 5,400 Other noncurrent liabilities and deferred credits 1,931 1,999 Total liabilities $ 10,690 $ 10,532

3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS Goodwill The following table provides information regarding our goodwill balance, all of which relates to the Competitive Electric segment and arose in connection with accounting for the Merger. There were no changes to the goodwill balance for the three and nine months ended September 30, 2013. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges $ 18,342 Accumulated impairment charges (13,390)

Balance at September 30, 2013 and December 31, 2012 $ 4,952 In the first quarter 2013, we finalized the fair value calculations supporting the $1.2 billion noncash goodwill impairment charge related to the Competitive Electric segment that was recorded in the fourth quarter 2012. No additional impairment was recorded.

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Table of Contents We have determined that in consideration of our most recent forecasts of wholesale power prices in ERCOT, the likelihood of a goodwill impairment has increased. We have initiated an evaluation of goodwill as of September 30, 2013, which will be completed in the fourth quarter 2013 and could result in a noncash goodwill impairment charge in that period.

Identifiable IntangibleAssets Identifiable intangible assets, including amounts that arose in connection with accounting for the Merger, are comprised of the following:

September 30, 2013 December 31, 2012 Gross Gross Carrying Accumulated Carrying Accumulated Identifiable Intangible Asset Amount Amortization Net Amount Amortization Net Retail customer relationship $ 463 $ 396 $ 67 $ 463 $ 378 $ 85 Favorable purchase and sales contracts 551 333 218 552 314 238 Capitalized in-service software 357 193 164 356 174 182 Environmental allowances and credits 598 407 191 594 393 201 Mining development costs 196 105 91 163 82 81 Total identifiable intangible assets subject to amortization $ 2,165 $ 1,434 731 $ 2,128 $ 1,341 787 Retail trade name (not subject to amortization) 955 955 Mineral interests (not currently subject to amortization) 11 13 Total identifiable intangible assets $ 1,697 $ 1,755 Amortization expense related to identifiable intangible assets (including income statement line item) consisted of:

Three Months Ended Nine Months Ended September 30, September 30, Identifiable Intangible Asset Income Statement Line Segment 2013 2012 2013 2012 Retail customer relationship Depreciation and amortization Competitive Electric $ 6 $ 8 $ 18 $ 25 Favorable purchase and sales Operating revenues/fuel, Competitive Electric contracts purchased power costs and delivery fees 6 5 19 20 Capitalized in-service software Depreciation and amortization Competitive Electric and Corporate and Other 10 10 31 29 Environmental allowances and Fuel, purchased power costs and Competitive Electric credits delivery fees 5 6 11 15 Mining development costs Depreciation and amortization Competitive Electric 8 7 23 20 Total amortization expense $ 35 $ 36 $ 102 $ 109 EstimatedAmortization of IdentifiableIntangibleAssets - The estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as follows:

Year Estimated Amortization Expense 2013 $ 138 2014 $ 125 2015 $ 115 2016 $ 95 2017 $ 75 10

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4. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM On October 29, 2013, we terminated the Accounts Receivable Securitization Program, described in the following paragraphs, and repaid all outstanding obligations under the program. In connection with the termination of the program, TXU Energy repurchased $491 million in accounts receivable from TXU Energy Receivables Company LLC (TXU Energy Receivables Company) for an aggregate purchase price of $474 million, TXU Energy Receivables Company paid TXU Energy $11 million, constituting repayment in full of its outstanding obligations under its subordinated note with TXU Energy, and TXU Energy Receivables Company repaid all of its borrowings from a financial institution providing the financing for the program totaling $126 million.

Under the Accounts Receivable Securitization Program, TXU Energy (originator) sold all of its trade accounts receivable to TXU Energy Receivables Company, which was 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 borrowed funds from a financial institution using the accounts receivable as collateral.

The trade accounts receivable amounts under the program are reported in the financial statements as pledged balances, and the related funding amounts are reported as short-term borrowings.

The maximum funding amount available under the program at September 30, 2013 was $200 million, which approximated the expected usage and applied only to receivables related to non-executory retail sales contracts. Program funding increased to $172 million at September 30, 2013 from $82 million at December 31, 2012. Because TCEH's credit ratings were lower than Ba3/BB-, under the terms of the program available funding was reduced by the amount of customer deposits held by the originator, which totaled $33 million at September 30, 2013.

TXU Energy Receivables Company issued a subordinated note payable to the originator in an amount equal to the difference between the face amount of the accounts receivable purchased, less a discount, and cash paid to the originator. Because the subordinated note was limited to 25% of the uncollected accounts receivable purchased, and the amount of borrowings was limited by terms of the financing agreement, any additional funding to purchase the receivables was sourced from cash on hand, which totaled $37 million at September 30, 2013, and/or capital contributions from TCEH. Under the program, the subordinated note issued by TXU Energy Receivables Company was subordinated to the security interests of the financial institution. The balance of the subordinated note payable, which was eliminated in consolidation, totaled $93 million and $97 million at September 30, 2013 and December 31, 2012, respectively.

All new trade receivables under the program generated by the originator were continuously purchased by TXU Energy Receivables Company with the proceeds from collections of receivables previously purchased and, as necessary, increased borrowings or funding sources as described immediately above.

Changes in the amount of borrowings by TXU Energy Receivables Company reflected seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes.

The discount from face amount on the purchase of receivables from the originator principally funded program fees paid to the financial institution. The program fees consisted primarily of interest costs on the underlying financing and are reported as interest expense and related charges. The discount also funded a servicing fee, which is reported as SG&A expense, paid by TXU Energy Receivables Company to TXU Energy, which provided recordkeeping services and was the collection agent under the program.

Program fee amounts were as follows:

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Program fees $ 3 $ 2 $ 6 $ 6 Program fees as a percentage of average funding (annualized) 5.1% 4.9% 5.8% 6.2%

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Table of Contents Activities of TXU Energy Receivables Company and its predecessor, TXU Receivables Company, were as follows:

Nine Months Ended September 30, 2013 2012 Cash collections on accounts receivable $ 3,200 $ 3,501 Face amount of new receivables purchased (a) (3,328) (3,571)

Discount from face amount of purchased receivables 29 8 Program fees paid to financial institution (6) (6)

Servicing fees paid for recordkeeping and collection services -- (2)

Decrease in subordinated notes payable (4) (10)

Increase in cash held 17 -

Other - net 2 Cash flows provided to originator under the program $ (90) $ (80)

(a) Net of allowance for uncollectible accounts.

TradeAccounts Receivable September 30, December 31, 2013 2012 Wholesale and retail trade accounts receivable $ 825 $ 727 Allowance for uncollectible accounts (17) (9)

Trade accounts receivable - reported in balance sheet, including $573 and $445 in pledged retail receivables $ 808 $ 718 Gross trade accounts receivable at September 30, 2013 and December 31, 2012 included unbilled revenues of $272 million and $260 million, respectively.

Allowancefor UncollectibleAccounts Receivable Nine Months Ended September 30, 2013 2012 Allowance for uncollectible accounts receivable at beginning of period $ 9 $ 27 Increase for bad debt expense 23 20 Decrease for account write-offs (15) (32)

Allowance for uncollectible accounts receivable at end of period $ 17 $ 15 12

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5. SHORT-TERM BORROWINGS AND LONG-TERM DEBT Short-Term Borrowinas At September 30, 2013, outstanding short-term borrowings totaled $2.226 billion, which included $2.054 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.68%, excluding customary fees, and $172 million under the accounts receivable securitization program. On October 29, 2013, we terminated the accounts receivable securitization program and repaid all outstanding obligations under the program (see Note 4).

At December 31, 2012, outstanding short-term borrowings totaled $2.136 billion, which included $2.054 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.40%, excluding customary fees, and $82 million under the accounts receivable securitization program.

Credit Facilities Credit facilities and related cash borrowings at September 30, 2013 are presented below. Available letter of credit capacity totaled $171 million at September 30, 2013 as discussed below. The facilities are all senior secured facilities of TCEH.

September 30, 2013 Maturity Facility Letters of Cash Faculty Date Limit Credit Borrowings Availability TCEH 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 September 30, 2013, borrowings under the facility bear interest at LIBOR plus 4.50%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 1.00% of the average daily unused portion of the facility. In January 2013, commitments previously 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 transactions that are not secured by a first-lien interest in the assets of TCEH. The borrowings under this facility have been recorded by TCEH as restricted cash that supports issuances of letters of credit and are classified as long-term debt. At September 30, 2013, the restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009 related to an office building financing. At September 30, 2013, the restricted cash supports $776 million in letters of credit outstanding, leaving $171 million in available letter of credit capacity.

Amendment and Extension of TCEH Revolving CreditFacility - In January 2013, the Credit Agreement governing the TCEH Senior Secured Facilities was amended to extend the maturity date of the $645 million of commitments maturing in October 2013 to October 2016, bringing the maturity date of all commitments under the TCEH Revolving Credit Facility totaling $2.054 billion to October 2016. The extended commitments have the same terms and conditions as the existing commitments expiring in October 2016 under the Credit Agreement. Fees in consideration for the extension were settled through the incurrence of $340 million principal amount of incremental term loans under the TCEH Term Loan Facilities maturing in October 2017. In connection with the extension request, TCEH eliminated its ability to draw letters of credit under the TCEH Revolving Credit Facility. At the date of the extension, there were no outstanding letters of credit under the TCEH Revolving Credit Facility.

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Table of Contents Long-Term Debt At September 30, 2013 and December 31, 2012, long-term debt consisted of the following:

September 30, December 31, 2013 2012 EFH Cori. (parent entity) 9.75% Fixed Senior Notes due October 15, 2019 $ 2 $ 115 10% Fixed Senior Notes due January 15, 2020 3 1,061 10.875% Fixed Senior Notes due November 1, 2017 (a) 33 64 11.25 / 12.00% Senior Toggle Notes due November 1, 2017 (a) 27 60 5.55% Fixed Series P Senior Notes due November 15, 2014 (a) 90 92 6.50% Fixed Series Q Senior Notes due November 15, 2024 (a) 201 230 6.55% Fixed Series R Senior Notes due November 15, 2034 (a) 291 291 8.82% Building Financing due semiannually through February 11, 2022 (b) 46 53 Unamortized fair value premium related to Building Financing (b)(c) 9 11 Unamortized fair value discount (c) (123) (137)

Total EFH Corp. 579 1,840 EFIH 6.875% Fixed Senior Secured First Lien Notes due August 15, 2017 503 503 10% Fixed Senior Secured First Lien Notes due December 1, 2020 3,482 2,180 11% Fixed Senior Secured Second Lien Notes due October 1, 2021 406 406 11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022 1,750 1,750 11.25 / 12.25% Senior Toggle Notes due December 1, 2018 1,476 1,304 9.75% Fixed Senior Notes due October 15, 2019 2 141 Unamortized premium 303 351 Unamortized discount (149) (131)

Total EFIH 7,773 6,504 9ele 9.58% Fixed Notes due in annual installments through December 4,2019 (d) 35 35 8.254% Fixed Notes due in quarterly installments through December 31, 2021 (d) 35 39 1.065% Floating Rate Junior Subordinated Debentures, Series D due January 30,2037(e) 1 1 8.175% Fixed Junior Subordinated Debentures, Series Edue January 30, 2037 8 8 Unamortized fair value discount (c) (6) (7)

Total EFCH 73 76 TQEH Senior Secured Facilities:

3.710% TCEH Term Loan Facilities maturing October 10, 2014 (eXf) 3,809 3,809 3.679% TCEH Letter of Credit Facility maturing October 10, 2014 (e) 42 42 4.709/ TCEH Term Loan Facilities maturing October 10, 2017 (a)(e)(f) 15,691 15,351 4.679% TCEH Letter of Credit Facility maturing October 10, 2017 (e) 1,020 1,020 11.5% Fixed Senior Secured Notes due October 1, 2020 1,750 1,750 15% Fixed Senior Secured Second Lien Notes due April 1, 2021 336 336 15% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B 1,235 1,235 10.25% Fixed Senior Notes due November 1, 2015 (a) 1,833 1,833 10.25% Fixed Senior Notes due November 1, 2015, Series B (a) 1,292 1,292 10.50 / 11.25% Senior Toggle Notes due November 1, 2016 1,749 1,749 14

Table of Contents September 30, December 31, 2013 2012 Pollution Control Revenue Bonds:

Brazos River Authority:

5.40% Fixed Series 1994A due May 1, 2029 $ 39 $ 39 7.70% Fixed Series 1999A due April 1, 2033 111 111 6.75% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (g) 16 7.70% Fixed Series 1999C due March 1, 2032 50 50 8.25% Fixed Series 2001A due October 1, 2030 71 71 8.25% Fixed Series 200ID-1 due May 1, 2033 171 171 0.089% Floating Series 2001D-2 due May 1, 2033 (h) 97 97 0.2100/a Floating Taxable Series 20011 due December 1, 2036 (i) 62 62 0.089% Floating Series 2002A due May 1, 2037 (h) 45 45 6.75% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (g) 44 6.30% Fixed Series 2003B due July 1, 2032 39 39 6.75% Fixed Series 2003C due October 1, 2038 52 52 5.40% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (g) 31 31 5.00% Fixed Series 2006 due March 1, 2041 100 100 Sabine River Authority of Texas:

6.45% Fixed Series 2000A due June 1,2021 51 51 5.20% Fixed Series 2001C due May 1, 2028 70 70 5.80% Fixed Series 2003A due July 1, 2022 12 12 6.15% Fixed Series 2003B due August 1, 2022 45 45 Trinity River Authority of Texas:

6.25% Fixed Series 2000A due May 1,2028 14 14 Unamortized fair value discount related to pollution control revenue bonds (c) (107) (112)

Other:

7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017 36 -

7.46% Fixed Secured Facility Bonds with amortizing payments through January 2015 4 12 7% Fixed Senior Notes due March 15, 2013 -- 5 Capital leases 56 64 Other 3 3 Unamortized discount (110) (10)

Unamortized fair value discount (c) -- (1)

Total TCEH 29,699 29,498 Total EFH Corp. consolidated 38,124 37,918 Less amount due currently (38) (103)

Total long-term debt $ 38,086 $ 37,815 (a) Excludes the following debt held by EFIH or EFH Corp. (parent entity) and eliminated in consolidation:

September 30, December 31, 2013 2012 EFH Corp. 10.875% Fixed Senior Notes due November 1, 2017 $ 1,685 EFH Corp. 11.25 / 12.00% Senior Toggle Notes due November 1, 2017 3,441 EFH Corp. 5.55% Fixed Series P Senior Notes due November 15, 2014 281 279 EFH Corp. 6.50%/o Fixed Series Q Senior Notes due November 15, 2024 545 516 EFH Corp. 6.55% Fixed Series R Senior Notes due November 15, 2034 456 456 TCEH 4.709% Term Loan Facilities maturing October 10, 2017 19 19 TCEH 10.25% Fixed Senior Notes due November 1, 2015 213 213 TCEH 10.25% Fixed Senior Notes due November 1, 2015, Series B 150 150 Total $ 1,664 $ 6,759 15

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 a letter 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 September 30, 2013.

(f) Interest rate swapped to fixed on $18.140 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 mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.

(h) Interest rates in effect at September 30, 2013. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(i) Interest rate in effect at September 30, 2013. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

Debt Amounts Due Currently Amounts due currently (within twelve months) at September 30, 2013 total $38 million and consist of scheduled installment payments on capital leases and debt securities.

Debt Related Activity in 2013 Principal amounts of long-term debt issued in the nine months ended September 30, 2013 totaled $1.731 billion and consisted of $340 million principal amount of incremental term loans under the TCEH Term Loan Facilities discussed in "Amendment and Extension of TCEH Revolving Credit Facility" above and $1.302 billion of EFIH 10% Notes and $89 million of EFIH Toggle Notes issued in exchanges discussed below.

Repayments of long-term debt in the nine months ended September 30, 2013 totaled $94 million and consisted of $86 million of payments of principal at scheduled maturity or mandatory tender and remarketing dates (including $60 million of pollution control revenue bond and $17 million of fixed secured facility bond payments) and $8 million of contractual payments under capital leases.

In April 2013, TCEH acquired for $40 million in cash the owner participant interest in a trust established to lease six natural gas-fueled combustion turbines to TCEH. The interest in the trust was held by an unaffiliated party. The trust was consolidated in the second quarter 2013. No gain or loss was recognized on the transaction. The estimated fair value of the combustion turbine assets of $83 million approximated the total of the estimated fair value of the debt assumed and cash paid. In recording the combustion turbine assets, the fair value was reduced by the remaining deferred lease liability and the unamortized lease valuation reserve established in accounting for the Merger, which were reversed and totaled $18 million. At June 30, 2013, the principal amount of the trust's debt totaled $45 million and is payable in semiannual installments through January 1, 2017.

EFIHDebt Exchanges andDistributionsInvolving EFH Corp. Debt - In exchanges in January 2013, EFIH and EFIH Finance issued $1.302 billion principal amount of EFIH 10% Senior Secured Notes due 2020 (New EFIH 10% Notes) in exchange for $1.310 billion total principal amount of EFH Corp. and EFIH 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) $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 9.75% Senior Secured Notes due 2019 (EFIH 9.75% Notes). The New EFIH 10% Notes have terms and conditions substantially 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 EFH Corp. 9.75% Notes and EFH Corp. 10% Notes and EFIH received the requisite consents from holders of the EFIH 9.75% Notes 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 EFIH 9.75% Notes, (ii) made EFCH and EFIH unrestricted subsidiaries under the EFH Corp. 9.75% Notes and EFH Corp. 10% Notes, thereby eliminating EFCH's unsecured and EFIH's secured guarantees of the notes, (iii) eliminated substantially all of the restrictive covenants in the indentures and (iv) eliminated certain events of default, modified covenants regarding mergers and consolidations and modified or eliminated certain other provisions in these indentures.

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Table of Contents In additional exchanges in January 2013, EFH and EFFH Finance issued $89 million principal amount of additional 11.25/12.25% Toggle Notes due 2018 (EFIH Toggle Notes) in exchange 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 principal amount of EFH Corp. 11.25%/12.00% Senior Toggle Notes due 2017 (EFH Corp. Toggle Notes), (iii) $2 million principal amount of EFH Corp. 5.55% Series P Notes due 2014 (EFH Corp. 5.55% Notes) and (iv) $29 million principal amount of EFH Corp. 6.50% Series Q Notes due 2024 (EFH Corp. 6.50% Notes). The additional EFIH Toggle Notes have the same terms and conditions as the existing EFIH Toggle Notes discussed below.

In the first quarter 2013, EFIH distributed $6.360 billion principal amount of EFH Corp. debt that it previously received in debt exchanges, including

$1.235 billion received in January 2013, as a dividend to EFH Corp., which cancelled the notes, leaving $1.361 billion principal amount of affiliate debt still held by EFIH. The dividend included $1.715 billion principal amount of EFH Corp. 10.875% Notes, $3.474 billion principal amount of EFH Corp. Toggle Notes, $1.058 billion principal amount of EFH Corp. 10% Notes and $113 million principal amount of EFH Corp. 9.75% Notes.

Accounting and Income Tay Effects of the Januar, 2013 Debt Exchanges - In consideration of the circumstances and terms of the exchanges, accounting rules require that the net loss on the exchanges, which totaled $21 million, be deferred and amortized to interest expense over the life of the debt issued. The deferred loss is reported as debt discount associated with the EFIH 10% Notes and EFIH Toggle Notes. For federal income tax purposes, the transactions resulted in cancellation of debt income of $11 million that was offset by operating losses.

Information Regarding Other Significant OutstandingDebt TCEH Senior Secured Facilities- Borrowings tinder the TCEH Senior Secured Facilities totaled $22.616 billion a t September 30, 2013 and consisted of:

$3.809 billion of TCEH Term Loan Facilities maturing in October 2014 with interest payable at LIBOR plus 3.50%;

• $15.691 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 payable at 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 payable at 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 October 2016 and represent the entire amount of commitments under the facility totaling $2.054 billion at September 30, 2013. See "Credit Facilities" above for discussion regarding the maturity date extension of $645 million in commitments from 2013 to 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 notes held by EFH Corp. or its controlled affiliates at March 3 I, 2011 to the extent held at the determination date as defined in the Credit Agreement) or more than $150 million aggregate principal amount of the TCEH Toggle Notes due in 2016 (other than notes held by EFH Corp. or its controlled affiliates at March 31, 2011 to the extent held at the determination date as defined in the Credit Agreement), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (ii) TCEH's total debt to Adjusted EBITDA ratio (as defined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at the applicable determination date, then the maturity date of the extended loans will automatically change to 90 days prior to the maturity date of the applicable notes.

Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH's available liquidity could be reduced by an amount up to the aggregate amount of such lender's commitments tinder the TCEH Senior Secured Facilities.

The TCEH Senior Secured Facilities are fully and unconditionally guaranteed jointly and severally on a senior secured basis by 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 transactions and the interest rate swaps described under "TCEH Interest Rate Swap Transactions" below, are secured on a first-priority basis by (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.

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Table of Contents TCEH 11.5% Senior Secured Notes - At September 30, 2013, the principal amount of the TCEH 11.5% Senior Secured Notes 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 joint and several basis 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 secured on a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent such assets and equity interests secure obligations under the TCEH 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 of TCEH, (ii) senior in right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of the TCEH Collateral and (iii) senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

TCEH 15% Senior Secured Second Lien Notes (including Series B) - At September 30, 2013, the principal amount of the TCEH 15% Senior Secured Second Lien Notes totaled $1.571 billion. These notes mature in April 2021, with interest payable in 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 and unconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent 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 extent that separate financial statements would be required to be filed with the SEC for such Subsidiary Guarantor under Rule 3-16 of Regulation 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 subordinated debt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured 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 extent of the value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

TCEH 10.25% Senior Notes (includingSeries B) and 10.50/11.25% Senior Toggle Notes (collectively, the TCEH Senior Notes) - At September 30, 2013, the principal amount of the TCEH Senior Notes totaled $4.874 billion, excluding $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 direct parent, EFCH (which owns 100% of TCEH), and by each subsidiary that guarantees the 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 November 2016, with interest payable semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.50% per annum.

EFIH6.875% Senior Secured Notes - At September 30, 2013, the principal amount of the EFIH 6.875% Notes totaled $503 million. These notes mature in August 2017, with interest payable in cash semiannually in arrears on February 15 and August 15 at a fixed rate of 6.875% per annum. The EFIH 6.875% Notes are secured on a first-priority basis by EFIH's pledge of its 100% ownership of the membership interests in Oncor Holdings (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 indebtedness of EFIH and are senior in right of payment to any future subordinated indebtedness of EFIH. The EFIH 6.875% Notes are effectively senior to all second lien and unsecured indebtedness of EFIH, to the extent of the value of the EFIH Collateral, and are effectively subordinated to 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 holders of the EFIH 6.875% Notes vote as a separate class from the holders of the EFIH 10% Notes.

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Table Of Contents The EFIH 6.875% Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH 6.875% Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH 6.875% Notes. Because the exchange offer has not yet been completed, the annual interest rate on the EFIH 6.875% Notes increased by 2 5 basis points (to 7.125%) on August 15, 2013 and will increase by an additional 25 basis points (to 7.375%) on November 15, 2013. The interest rate on the EFIH 6.875% Notes will remain at that level until completion of the exchange offer, at which time the interest rate on the notes will revert to 6.875%.

EFIH10% Senior Secured Notes - At September 30, 2013, the principal amount of the EFIH 10% Notes totaled $3.482 billion. The notes mature in December 2020, with interest payable in cash semiannually in arrears on June 1 and December 1 at a fixed rate of 10% per annum. The notes are secured by the EFIH Collateral on an equal and ratable basis with the EFIH 6.875% Notes.

The EFIH 10% Notes are senior obligations of EFIH and rank equally in right of payment with all existing and future senior indebtedness of EFIH, including the EFH 6.875% Notes. The EFIH 10% Notes have substantially the same terms, covenants and events of default as the EFIH 6.875% Notes. The holders of the EFIH 10% Notes vote as a separate class from the holders of the EFIH 6.875% Notes.

15FIH 11% Senior Secured Second Lien Notes - At September 30, 2013, the principal amount of the EFIH 11% Notes totaled $406 million. The notes mature in October 2021, with interest payable in cash semiannually in arrears on May 15 and November 15 at a fixed rate of 11% per annum. The EFIH 11% Notes are secured on a second-priority basis by the EFIH Collateral on 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 senior indebtedness of EFIH and are effectively senior in right of payment to all existing or future unsecured debt of EFIH to the extent of the value of the EFIH Collateral. The notes have substantially the same terms, covenants and events of default as the EFIF 11.75% Notes discussed below, and the holders of the EFIH 11% Notes will generally vote as a single class with the holders of the EFIH 11.75% Notes.

EFIH 11. 75% Senior Secured Second Lien Notes - At September 30, 2013, the principal amount of the EFIH 11.75% Notes totaled $1.750 billion. These notes mature in March 2022, with interest payable in cash semiannually in arrears on March 1 and September 1 at a fixed rate of 11.75% per annum. The EFIH 11.75% Notes are secured on a second-priority basis by the EFIH Collateral on an equal and ratable basis with the EFIH 11% Notes. The EFIH 11.75% Notes have substantially the same covenants as the EFIH 11% Notes, and the holders of the EFIH 11.75% Notes will generally vote as a single class with the holders of the EFIH 11% Notes.

The EFH 11.75% Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreed to 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 exchange freely tradable notes for the EFIH 11.75% Notes. Because the exchange offer has not yet been completed, the annual interest rate on the EFIH 11.75% Notes increased by 2 5 basis points (to 12.00%) on February 5, 2013 and by an additional 25 basis points (to 12.25%) on May 6, 2013. The interest rate on the EFIH 11.75% Notes will remain at that level until completion of the exchange offer, at which time the interest rate on the notes will revert to 11.75%.

EFIH 11.25/12.25% Senior Toggle Notes - At September 30, 2013, the principal amount of the EFIH Toggle Notes totaled $1.476 billion. These notes mature in December 2018, with interest payable semiannually in arrears on June 1 and December 1 at a fixed rate of 11.25% per annum for cash interest and 12.25% per annum for PIK Interest. For any interest period until June 1,2016, EFIH may elect to pay interest on the Toggle Notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFIH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once EFIH makes a PIK election, which it did effective with the June 1, 2013 interest payment, the election is valid for each succeeding interest payment period until EFIH revokes the election.

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Table of Contents The EFIH Toggle Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH Toggle Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH Toggle Notes. If an exchange offer for the notes is not completed within 365 days after the date (December 5, 2012) the initial EFIH Toggle notes were issued (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter, the annual interest 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.

EFH Corp. 10.875% SeniorNotes and 11.25/12.00% Senior Toggle Notes - At September 30, 2013, the collective principal amount of these notes totaled $60 million. The notes are fully and unconditionally guaranteed on a joint and 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 1 and November 1 at a fixed rate for the 10.875% Notes of 10.875% per annum and at a fixed rate for the Toggle Notes of 11.25% per annum.

Fair Value of Long-Term Debt At September 30, 2013 and December 31, 2012, the estimated fair value of our long-term debt (excluding capital leases) totaled $23.625 billion and

$25.890 billion, respectively, and the carrying amount totaled $38.068 billion and $37.854 billion, respectively. At September 30, 2013 and December 31, 2012, the estimated fair value of our short-term borrowings under the TCEH Revolving Credit Facilities totaled $1.371 billion and $1.500 billion, respectively, and the carrying amount totaled $2.054 billion. We determine fair value in accordance with accounting standards as discussed in Note 8, and at September 30,2013, our debt fair value represents Level 2 valuations. We obtain security pricing from a vendor who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.

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 September 30, 2013, TCEH has entered into the following series of interest rate swap transactions that effectively fix the interest rates at between 5.5% and 9.3%.

Fixed Rates Expiration Dates Notional Amount 5.5% - 9.3% October 2013 through October 2014 $ 18.140 billion (a) 6.8% 9.0% October 2015 through October 2017 $ 12.600 billion (b)

(a) Swaps related to an aggregate $1.6 billion principal amount of debt expired in 2013. Per the terms of the transactions, the notional amount of swaps entered into in 2011 grew by $1.280 billion 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 achieved through the interest rate swaps.

Basis swaps in effect at September 30, 2013 totaled $11.967 billion notional amount. The basis swaps relate 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 lenders under the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes.

The interest rate swaps have resulted in net gains (losses) reported in interest expense and related charges as follows:

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Realized net loss $ (160) $ (168) $ (466) $ (505)

Unrealized net gain (loss) 413 (20) 899 (16)

Total $ 253 $ (188) $ 433 $ (521) 20

Table of Contents The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.167 billion and $2.065 billion at September 30, 2013 and December 31, 2012, respectively, of which $57 million and $65 million (both pretax), respectively, were reported in accumulated other comprehensive income. See Note 8.

6. COMMITMENTS AND CONTINGENCIES Guarantees We have entered into contracts that contain guarantees to unaffiliated parties that could require 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 Atmos Energy Corporation (Atmos) in October 2004, EFH Corp. agreed to indemnify Atmos, until October 1, 2014, for up to $500 million for 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 maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.

See Note 5 for discussion of guarantees and security for certain of our debt.

Letters of Credit At September 30, 2013, TCEH had outstanding letters of credit under its credit facilities totaling $776 million as follows:

• $353 million to support risk management and trading margin requirements in the normal course of business, including over-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 $204 million (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

• $150 million for miscellaneous credit support requirements.

Litigation Aurelius Capital Master, Ltd. and ACP Master, Ltd. (Aurelius) filed a lawsuit in March 2013, amended in May 2013, in the United States District Court for the Northern District of Texas (Dallas Division) against EFCH as a nominal defendant and each of the current directors and a former director of EFCH. In the lawsuit, Aurelius, as a creditor under the TCEH Senior Secured Facilities and certain TCEH secured bonds, both of which are guaranteed by EFCH, filed a derivative claim against EFCH and its directors. Aurelius alleges that the directors of EFCH breached their fiduciary duties to EFCH and its creditors, including Aurelius, by permitting TCEH to make certain loans "without collecting fair and reasonably equivalent value." The lawsuit seeks recovery for the benefit of EFCH. EFCH and the directors have filed a motion to dismiss this lawsuit, which has been fully briefed and is pending before the district court. We cannot predict the outcome of this proceeding, including the financial effects, if any.

LitigationRelated to Generation Facilities - In November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak Grove Management 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 the Travis County, Texas District Court.

Plaintiffs sought a reversal of the TCEQ's order and a remand back to the TCEQ for further proceedings. The district court affirmed the TCEQ's issuance of the TPDES permit to Oak Grove. In December 2012, plaintiffs appealed the district court's decision to the Third Court of Appeals in Austin, Texas. The case has been fully briefed, but the Court has not issued a decision and no date for oral argument has been scheduled. While we cannot predict the timing or outcome of this proceeding, we believe the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.

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Table of Contents In September 2010, the Sierra Club filed a lawsuit in the United States District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC (a wholly owned subsidiary of TCEH) for alleged violations of the Clean Air Act (CAA) at Luminant's Martin Lake generation facility. In May 2012, the Sierra Club filed a lawsuit in the US District Court for the Western District of Texas (Waco Division) against EFH Corp. and Luminant Generation Company LLC for alleged violations of the CAA at Luminant's Big Brown generation facility. The Big Brown case is currently scheduled for trial in February 2014. The Martin Lake case does not have a trial date. While we are unable to estimate any possible loss or predict 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 for allegedly violating CAA provisions in connection with Luminant's Monticello generation facility. In May 2012, the Sierra Club informed 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 any resulting proceedings, we believe we have complied with the requirements of the CAA at all of our generation facilities.

Litigation Related to EPA Reviews - In June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of the CAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, we received an additional information request from the EPA under Section 114 related to the Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to the Sandow 4 generation facility. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement.

In July 2012, the EPA sent us a notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our Martin Lake and Big Brown generation facilities. In September 2012, we filed a petition for review in the United States Court of Appeals for the Fifth Circuit (Fifth Circuit Court) seeking judicial review of the EPA's notice of violation. Given recent legal precedent subjecting agency orders like the notice of violation to judicial review, we filed the petition for review to preserve our ability to challenge the EPA's issuance of the notice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December 2012, the Fifth Circuit Court issued an order that will delay a ruling on the EPA's motion to dismiss until after the case has been fully briefed and oral argument, if any, is held.

In July 2013, the EPA sent us a second notice of violation alleging noncompliance with the CAA's New Source Review Standards at our Martin Lake and Big Brown generation facilities. In July 2013, we filed a petition for review in the Fifth Circuit Court seeking judicial review of the EPA's July 2013 notice of violation. In September 2013, the Fifth Circuit Court consolidated the petitions for review of the July 2012 and July 2013 notices of violation and established a briefing schedule for the consolidated cases.

In August 2013, the United States Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant Generation Company LLC and Big Brown Power Company LLC in federal district court in Dallas, alleging violations of the CAA at our Big Brown and Martin Lake generation facilities. In September 2013, we filed a motion to stay this lawsuit pending the outcome of the Fifth Circuit Court's review of the July 2012 and July 2013 notices of violation. We believe that we have complied with all requirements of the CAA and intend to vigorously defend these allegations.

We cannot predict the outcome of these proceedings, including the financial effects, if any.

Cross-StateAir Pollution Rule (CSAPR)

In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of sulfur dioxide (SO 2) and nitrogen oxides (NOJ)emissions from our fossil-fueled generation units. In September 2011, we filed a petition for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) challenging the CSAPR as it applies to Texas. If the CSAPR had taken effect, it would have caused us to, among other actions, idle two lignite/coal-fueled generation units and cease certain lignite mining operations by the end of 2011.

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Table of Contents 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, that the rules do not include all of the budget corrections we requested from the EPA.

The parties to the case agreed that the case should be held in abeyance pending the conclusion of the CSAPR rehearing proceeding discussed below. In June 2012. the EPA finalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPR issued by the EPA in October 2011, the Final Revisions and the Second Revised Rule finalize emissions budgets for our generation assets that are approximately 6% lower for SO, 3% higher for annual NO, and 2% higher for seasonal NO,.

In August 2012, the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for further proceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule do not impose any immediate requirements on us, the State of Texas, or other affected parties. The D.C. Circuit Court's order stated that the EPA was expected to continue administering the CAIR (the predecessor rule to the CSAPR) pending the EPA's further consideration of the rule. In October 2012, the EPA and certain other parties that supported the CSAPR filed petitions with the D.C. Circuit Court seeking review by the full court of the panel's decision to vacate and remand the CSAPR. In January 2013, the D.C. Circuit Court denied these requests for rehearing, concluding the CSAPR rehearing proceeding. In March 2013, the EPA and certain other parties that supported the CSAPR submitted petitions to the US Supreme Court seeking its review of the D.C. Circuit Court decision. In June 2013, the US Supreme Court granted review of the D.C. Circuit Court's decision. The court is scheduled to hear oral arguments in the case in December 2013. We cannot predict the outcome of the review by the US Supreme Court.

State Implementation Plait (SIP)

In September 2010, the EPA disapproved a portion of the SIP pursuant to which the TCEQ implements its program to achieve the requirements of the CAA. The EPA disapproved the Texas standard permit for pollution control projects (PCP). We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. We challenged the EPA's disapproval by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ'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 remanded the matter to the EPA for expedited reconsideration. In September 2013, the State of Texas filed a motion with the Fifth Circuit Court requesting that the Court amend and enforce its judgment in this case by requiring the EPA to satisfy the Court's judgment by taking action on the pending SIP revision regarding Texas' PCP standard permit no later than December 31, 2013. 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 replacing that exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generation facility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicability of the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and received the generation facility-specific permit amendments. We challenged the EPA's disapproval of Texas' affirmative defense for planned maintenance, startup and shutdown by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issued is consistent with the CAA. In July 2012, the Fifth Circuit Court denied our challenge and ruled that the EPA's actions were in accordance with the CAA. In October 2012, the Fifth Circuit Court panel withdrew its opinion and issued a second, expanded opinion that again upheld the EPA's disapproval. In November 2012, we filed a petition with the Fifth Circuit Court asking for review by the full Fifth Circuit Court of the panel's second opinion. Other parties to the proceedings also filed a petition with the Fifth Circuit Court asking the panel to reconsider its decision. In March 2013, the Fifth Circuit Court panel withdrew its second opinion and issued a third opinion that again upheld the EPA's actions. In April 2013, the Fifth Circuit Court also denied our November 2012 petition for rehearing of the panel's second opinion and denied the request by other parties for the panel to reconsider its second decision. Following the issuance of the mandate, we filed amotion to recall the mandate, which was denied in a single-judge order. In June 2013, we submitted a petition to the US Supreme Court seeking its review of the Fifth Circuit Court's decision to uphold EPA's disapproval of Texas' affirmative defense for planned maintenance, startup and shutdown. In October 2013, the US Supreme Court denied our petition for review of that portion of the Fifth Circuit Court's decision. The decision is not anticipated to have a material effect on our results of operations, liquidity or financial condition.

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Table of Contents Other Matters We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

7. EQUITY DividendRestrictions EFH Corp. has not declared or paid any dividends since the Merger.

The indenture governing the EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes includes covenants that, among other things and subject to certain exceptions, restrict our ability to pay-dividends or make other distributions in respect of our common stock. Accordingly, our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or on a pro forma basis, after giving effect to such distribution, EFH Corp.'s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, "consolidated leverage ratio" is defined as the ratio of consolidated total debt (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. EFH Corp.'s consolidated leverage ratio was 12.3 to 1.0 at September 30, 2013.

The indentures governing the EFIH Notes generally restrict EFIH from making any cash distribution to EF1 Corp. for the ultimate purpose of making a cash dividend on our coimnon 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's Adjusted EBITDA on a consolidated basis (including Oncor's Adjusted EBITDA). EFIH's consolidated leverage ratio was 7.7 to 1.0 at September 30, 2013. In addition, the EFfH Notes generally restrict EFIH's ability to make distributions or loans to EFH Corp., unless such distributions or loans are expressly permitted wider the indentures governing the EFIH Notes.

The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such distribution, TCEH's consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. At September 30, 2013, the ratio was 10.6 to 1.0.

In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and TCEH Senior Secured Second Lien Notes generally restrict TCEH's ability to make distributions or loans to any of its parent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and the indentures governing such notes.

Under applicable law, we are also prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent.

NoncontrollingInterests As discussed in Note 2, we consolidate a joint venture formed in 2009 for the purpose of developing two new nuclear generation units, which results in a noncontrolling interests component of equity. Net loss attributable to the noncontrolling interests was immaterial for the nine months ended September 30, 2013 and 2012.

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Table of Contents Equity The following table presents the changes to equity for the nine months ended September 30, 2013:

EFH Corp. Shareholders' Equity Accumulated Other Additional Paid-in Retained Earnings Comprehensive Income Noncontrolling Common Stock (a) Capital (Deficit) (Loss) Interests Total Equity Balance at December 31, 2012 $ 2 $ 7,959 $ (18,939) $ (47) $ 102 $ (10,923)

Net loss - - (635) - - (635)

Effects of stock-based incentive compensation plans - 5 - - - 5 Repurchases of stock - (5) - - - (5)

Change in unrecognized losses related to pension and OPEB plans (Note 10) - - - (4) - (4)

Net effects of cash flow hedges - - - 5 - 5 Net effects related to Oncor - - - 1 -I Investment by noncontrolling interests ... 3 3 Other - 2 - - - 2 Balanceat September 30,2013 $ 2 $ 7,961 $ (19,574) $ (45) $ 105 $ (11,551)

(a) Authorized shares totaled 2,000,000,000 at September 30, 2013. Outstanding shares totaled 1,669,861,383 and 1,680,539,245 at September 30, 2013 and December 31, 2012, respectively.

The following table presents the changes to equity for the nine months ended September 30, 2012:

EFH Corp. Shareholders' Equity Accumulated Other Additional Paid-in Retained Earnings Comprehensive Income Common Stock (a) Capital (Deficit) (Loss) Noncontrolling Interests Total Equity Balance at December 31, 2011 $ 2 $ 7,947 $ (15,579) $ (222) $ 95 $ (7,757)

Net loss - - (1,408) - - (1,408)

Effects of stock-based incentive compensation plans -11 - -- - 11 Change in unrecognized losses related to pension and OPEB plans - - - (25) - (25)

Net effects of cash flow hedges - - - 5 - 5 Net effects related to Oncor - - - 2 - 2 Investment by noncontrolling interests - - - - 6 6 Balance at September 30, 2012 $ 2 $ 7,958 $ (16,987) $ (240) $ 101 $ (9,166)

(a) Authorized shares totaled 2,000,000,000 at September 30, 2012. Outstanding shares totaled 1,680,539,245 and 1,679,539,245 at September 30, 2012 and December 31, 2011, respectively.

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Table of Contents Accumulated Other ComprehensiveIncome (Loss)

The following table presents the changes to accumulated other comprehensive income (loss) for the nine months ended September 30, 2013. There was no other comprehensive income (loss) before reclassification for the period.

Pension and Other Dedesignated Cash Flow Postretirement Employee Accumulated Other Hedges - Interest Rate Benefit Liabilities Comprehensive Income Swaps (Note 9) Adjustments (Note 10) (Loss)

Balance at December 31, 2012 $ (64) $ 17 $ (47)

Amounts reclassified from accumulated other comprehensive income (loss) and reported in:

Operating costs (4) (4)

Depreciation and amortization 2 2 Selling, general and administrative expenses (2) (2)

Interest expense and related charges 6 6 Equity in earnings of unconsolidated subsidiaries 2 (1) 1 Income tax benefit (expense) (3) 2 (1)

Total amount reclassified from accumulated other comprehensive income (loss) during the period 7 (5) 2 Balance at September 30, 2013 $ (57) $ 12 $ (45) 26

Table of Contents

8. FAIR VALUE MEASUREMENTS Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an 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 value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the 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 the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level I assets and liabilities include exchange-traded commodity contracts. For example, some of our derivatives are NYMEX or ICE futures and swaps 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 quoted prices that are observable for the asset or liability 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 or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available.

Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the 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 meaningful infonnation available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means. See further discussion below.

Our valuation policies and procedures are developed, maintained and validated by a centralized risk management group that reports to the Chief Financial Officer, who also functions as the Chief Risk Officer. Risk management functions include commodity price reporting and validation, 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 the market approach of using prices and other market information for identical and/or comparable 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 non-binding) that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number 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. In addition, for valuation of interest rate swaps, we use generally accepted interest rate swap valuation models utilizing month-end interest rate curves.

Probable loss of default by either us or our counterparties is considered in determining the fair value of derivative assets and liabilities. These non-performance risk adjustments take into consideration credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 9 for additional information regarding credit risk associated with our derivatives). We utilize published credit ratings, default rate factors and bond trading values in calculating these fair value measurement adjustments.

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Table of Contents Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including, but not limited to, commodity prices, volatility factors, discount rates and other market based factors. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significant unobservable inputs used to develop the valuation 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 forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; 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 and experienced in market operations and fair value measurement and validated by the company's risk management group, which also further analyzes any significant changes in Level 3 measurements.

Significant changes in the unobservable 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 tables, the fair value measurement of an asset or liability (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 fair value measurement. Certain assets and liabilities would be classified 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 value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

Assets and liabilities measured at fair value consisted of the following:

September 30, 2013 Level 1 Level 2 Level 3 (a) Reclassification (b) Total Assets:

Commodity contracts $ 140 $ 941 $ 48 $ 2 $ 1,131 Interest rate swaps - 84 - - 84 Nuclear decommissioning trust -

equity securities (c) 299 172 471 Nuclear decommissioning trust -

debt securities (c) - 266 - 266 Total assets $ 439 $ 1,463 $ 48 $ 2 $ 1,952 Liabilities:

Commodity contracts $ 129 $ 26 $ 52 $ 2 $ 209 Interest rate swaps - 97 1,167 - 1,264 Total liabilities $ 129 $ 123 $ 1,219 $ 2 $ 1,473 December 31, 2012 Level 1 Level 2 Level 3 (a) Total Assets:

Commodity contracts $ 180 $ 1,784 $ 83 $ 2,047 Interest rate swaps - 134 - 134 Nuclear decommissioning trust - equity securities (c) 249 144 - 393 Nuclear decommissioning trust - debt securities (c) - 261 - 261 Total assets $ 429 $ 2,323 $ 83 $ 2,835 Liabilities:

Commodity contracts $ 208 $ 121 $ 54 $ 383 Interest rate swaps - 2,217 - 2,217 Total liabilities $ 208 $ 2,338 $ 54 $ 2,600 (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 vice versa, 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 13.

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Table of Contents Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated "normal" purchases or sales. See Note 9 for 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 debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 5 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

There were no significant transfers between Level I and Level 2 of the fair value hierarchy for the three and nine months ended September 30, 2013 and 2012. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfers between Level 2 and Level 3.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at September 30, 2013 and December 31, 2012:

September 30, 2013 Fair Value Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b)

Electricity purchases and sales $ 5 $ (2) $ 3 Valuation Model Illiquid pricing locations (c) $30 to $45/ MWhI Hourly price curve shape (d) $20 to $70/ MWh Electricity spread Option Pricing options (19) (19) Model Gas to power correlation (e) 45% to 100%

Power volatility (f) 10%/o to 30%

Electricity congestion revenue Market Approach Illiquid price differences between rights 37 (5) 32 (g) settlement points (h) $0.00 to $30.00 Market Approach Illiquid price variances between Coal purchases 1 (12) (11) (g) mines (i) $0.00 to $1.00 Probability of default (I) 00/. to 400/%

Recovery rate (k) 0% to 4O*/o Nonperformance risk adjustment Interest rate swaps (1,167) (1,167) Valuation Model (1) 30% to 35%

Other 5 (14) (9)

Total $ 48 $ (1,219) $ (1,171) 29

Table of Contents December 31, 2012 Fair Value Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b)

Electricity purchases and sales $ 5 $ (9) $ (4) Valuation Model Illiquid pricing locations (c) $20 to $40/ MWh Hourly price curve shape (d) $20 to $50! MWh Electricity spread Option Pricing options 34 (10) 24 Model Gas to power correlation (e) 20% to 90%

Power volatility (f) 20% to 40%

Electricity congestion Market Approach Illiquid price differences between revenue rights 41 (2) 39 (g) settlement points (h) $0.00 to $0.50 Market Approach Illiquid price variances between Coal purchases - (32) (32) (g) mines (i) $0.00 to $1.00 Probability of default () 5% to 40%/o Recovery rate (k) 0% to 400%

Other 3 (1) 2 Total $ 83 $ (54) $ 29 (a) Electricity purchase and sales contracts include wind generation agreements and hedging positions in the ERCOT west region as well as power contracts, the valuations of which include unobservable inputs related to the hourly shaping of the price curve. Electricity spread option contracts consist of physical electricity call options. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. Coal purchase contracts relate to western (Powder River Basin) coal. Interest rate swaps are held by TCEH to hedge exposure to its variable rate debt.

(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 relevant to 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 significance of 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 and the ERCOT West Hub.

(i) Based on the historical range of price variances between mine locations.

(j) Estimate of the range of probabilities of default based on past experience and the length of the contract as well as our and counterparties' credit ratings.

(k) Estimate of the default recovery rate based on historical corporate rates.

(1) Estimate of nonperformance risk adjustment based on TCEH senior secured bond trading values. See discussion immediately below regarding transfers into Level 3.

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Table of Contents The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and nine months ended September 30, 2013 and 2012. Transfers into Level 3 during 2013 as noted below reflect a nonperformance risk adjustment in the valuation of the TCEH interest rate swaps, which are secured by a first-lien interest in the same assets of TCEH (on a pari passu basis) with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes (see Note 5). At September 30, 2013, the estimated fair value of these interest rate swaps totaled $1.5 18 billion before consideration of nonperformance risk adjustment and $1.167 billion after consideration of such adjustment. The amount of the nonperformance risk adjustment was after consideration of derivative assets related to contracts with the same counterparties that are also secured by a first-lien interest in the assets of TCEH, and a master netting agreement is in place that provides for netting and setoff of amounts related to these contracts.

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Net asset balance at beginning of period $ 88 $ 12 $ 29 $ 53 Total unrealized valuation gains (losses) (24) 12 (41) (5)

Purchases, issuances and settlements (a):

Purchases 6 17 66 30 Issuances (4) (6) (15)

Settlements (62) (56) (45) (34)

Transfers into Level 3 (b) (1,179) 3 (1,178) (42)

Transfers out of Level 3 (b) - - 4 (3)

Net change (c) (1,259) (28) (1,200) (69)

Net liability balance at end of period $ (1,171) $ (16) $ (1,171) $ (16)

Unrealized valuation gains (losses) relating to instruments held at end of period $ 254 $ 15 $ 280 $ (22)

(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances 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 each quarter, which is when the assessments are performed. All Level 3 transfers during the periods 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 (loss) from commodity hedging and trading activities. Changes in values of interest rate swaps are reported in the income statement in interest expense and related charges. Activity excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.

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Table of Contents

9. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES Strategic Use of Derivatives We transact in derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage electricity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a natural gas hedging program and the hedging of interest costs on our long-term debt.

See Note 8 for a discussion of the fair value of all derivatives.

NaturalGas Hedging Program - TCEH has a natural gas hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales 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 sold forward natural gas through 2014. These transactions are intended to hedge a portion of electricity price exposure related to expected lignite/coal- and nuclear-fueled generation for this period. Unrealized gains and losses arising from changes in the fair value of the instruments under the program as well as realized gains and losses upon settlement of the instruments are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

InterestRate Swap Transactions- Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs.

Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in the income statement in interest expense and related charges. See Note 5 for additional information about interest rate swap agreements.

Other Commodity Hedging and TradingActivity - TCEH also enters into derivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.

FinancialStatement Effects of Derivatives Substantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported in the balance sheets at September 30, 2013 and December 31, 2012:

September 30, 2013 Derivative assets Derivative liabilities Commodity contracts Interest rate swaps Commodity contracts Interest rate swaps Total Current assets $ 972 $ 84 $ - $ - $ 1,056 Noncurrent assets 159 - - - 159 Current liabilities (2) - (204) (485) (691)

Noncurrent liabilities - - (3) (779) (782)

Net assets (liabilities) $ 1,129 $ 84 $ (207) $ (1,264) $ (258)

December 31, 2012 Derivative assets Derivative liabilities Commodity contracts Interest rate swaps Commodity contracts Interest rate swaps Total Current assets $ 1,461 $ 134 $ - $ - $ 1,595 Noncurrent assets 586 - 586 Current liabilities - (366) (678) (1,044)

Noncurrent liabilities - (17) (1,539) (1,556)

Net assets (liabilities) $ 2,047 $ 134 $ (383) $ (2,217) $ (419) 32

Table of Contents At September 30, 2013 and December 31, 2012, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealized effects:

Three Months Ended September 30, Nine Months Ended September 30, Derivative (income statement presentation) 2013 2012 2013 2012 Commodity contracts (Net gain loss) from commodity hedging and trading activities) (a) $ 98 $ (95) $ 54 $ 130 Interest rate swaps (Interest expense and related charges) (b) 253 (188) 433 (520)

Net gain (loss) $ 351 $ (283) $ 487 $ (390)

(a) Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.

(b) Includes unrealized mark-to-market net gain (loss) as well as the net realized effect on interest paid/accrued, both reported in "Interest Expense and Related Charges" (see Note 13).

The following table presents the pretax effect (all losses) on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges. There were no amounts recognized in OCI for the three and nine months ended September 30, 2013 and 2012.

Three Months Ended September 30, Nine Months Ended September 30, Derivative type (income statement presentation of loss reclassified from accumulated OCI into income) 2013 2012 2013 2012 Interest rate swaps (Interest expense and related charges) $ (1) $ (1) $ (6) $ (6)

Interest rate swaps (Depreciation and amortization) (1) (1) (2) (2)

Total $ (2) $ (2) $ (8) $ (8)

Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedge) at September 30, 2013 and December 31, 2012 totaled $38 million and $43 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps previously accounted for as cash flow hedges. We expect that $2 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at September 30, 2013 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

BalanceSheet Presentationof Derivatives Consistent with elections under US GAAP to present amounts on a gross basis, we report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements we have with counterparties. This presentation can result in 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. Margin deposits received from counterparties are either used for working capital or other corporate purposes or are deposited in a separate restricted cash account. At September 30, 2013 and December 31, 2012, essentially all margin deposits held were unrestricted.

We maintain standardized master netting agreements with certain counterparties that allow for the netting of positive and negative exposures. Generally, we utilize the International Swaps and Derivatives Association (ISDA) standardized contract for financial transactions, the Edison Electric Institute standardized contract for physical power transactions and the North American Energy Standards Board (NAESB) standardized contract for physical natural gas transactions. These contain credit enhancements that allow for the right to offset assets and liabilities with other financial instruments and collateral received in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.

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Table of Contents Certain entities are counterparties to both our natural gas hedge program positions and our interest rate swaps and have entered into master agreements that provide for netting and setoff of amounts related to these positions.

The following tables reconcile our derivative assets and liabilities as presented in the consolidated balance sheet to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:

September 30, 2013 Amounts Presented In Offsetting Financial Financial Collateral Balance Sheet Instruments (a) (Received) Pledged (b) Net Amounts (c)

Derivative assets:

Commodity contracts $ 1,131 $ (613) $ (351) $ 167 Interest rate swaps 84 (8 4 ) -- - -

Total derivative assets 1,215 (697) (351) 167 Derivative liabilities:

Commodity contracts (209) 180 11 (18)

Interest rate swaps (1,264) 517 --_ (747)

Total derivative liabilities (1,473) 697 11 (765)

Net amounts $ (258) $ $ (340) $ (598)

December 31, 2012 Amounts Presented In Offsetting Financial Financial Collateral Balance Sheet Instruments (a) (Received) Pledged (b) Net Amounts Derivative assets:

Commodity contracts $ 2,047 $ (1,263) $ (597) $ 187 Interest rate swaps 134 (134)

Total derivative assets 2,181 (1,397) (597) 187 Derivative liabilities:

Commodity contracts (383) 319 29 (35)

Interest rate swaps (2,217) 1,078 - (1,139)

Total derivative liabilities (2,600) 1,397 29 (1,174)

Net amounts $ (419) $ - $ (568) $ (987)

(a) Offsetting financial instruments with respect to commodity contracts include amounts related to interest rate swaps and vice versa. 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 $1.2 billion (before nonperformance risk adjustment) related to counterparties with positions that are secured by a first-lien interest in the same assets of TCEH (on a pari passu basis) with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes.

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I Table of Contents Derivative Volumes The following table presents the gross notional amounts of derivative volumes at September 30, 2013 and December 31, 2012:

September 30, 2013 December 31, 2012 Derivative type Notional Volume Unit of Measure Interest rate swaps:

Floating/fixed (a) $ 32,440 $ 32,760 Million US dollars Basis $ 11,967 $ 11,967 Million US dollars Natural gas:

Natural gas forward sales and purchases (b) 452 875 Million MMBtu Locational basis swaps 337 495 Million MMBtu All other 2,021 1,549 Million MMBtu Electricity 21,663 76,767 GWh Congestion Revenue Rights (c) 82,156 111,185 GWh Coal 11 13 Million US tons Fuel oil 28 47 Million gallons Uranium 575 441 Thousand pounds (a) Includes notional amount of interest rate swaps with maturity dates through October 2014 as well as notional amount of swaps effective 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 hedging program. The net amount of these transactions was approximately 210 million MMBtu and 360 million MMBtu at September 30, 2013 and December 31, 2012, respectively.

(c) Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT.

CreditRisk-Related Contingent Featuresof Derivatives The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that 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 are already effective.

At September 30, 2013 and December 31, 2012, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $40 million and $58 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $9 million and $12 million at September 30, 2013 and December 31, 2012, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, at September 30, 2013 and December 31, 2012, the remaining liquidity requirements would have totaled $8 million and none, respectively.

In addition, certain derivative agreements that are collateralized primarily with liens on certain of our assets include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. At September 30, 2013 and December 31, 2012, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.289 billion and $2.299 billion, respectively, before consideration of the amount of assets subject to the liens. No cash collateral or letters of credit were posted with these counterparties at September 30, 2013 and December 31, 2012 to reduce the liquidity exposure. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered at September 30, 2013 and December 31, 2012, the remaining related liquidity requirement after reduction for derivative assets under netting arrangements but before consideration of the amount of assets subject to the liens would have totaled $1.102 billion and $1.141 billion, respectively. See Note 5 for a description of other obligations that are supported by liens on certain of our assets.

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Table of Contents As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $1.329 billion and $2.357 billion at September 30, 2013 and December 31,2012, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable and 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 amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

Concentrationsof CreditRisk Related to Derivatives We have concentrations of credit risk with the counterparties to our derivative contracts. At September 30, 2013, total credit risk exposure to all counterparties related to derivative contracts totaled $1.352 billion (including associated accounts receivable). The net exposure to those counterparties totaled

$276 million at September 30, 2013 after taking into effect netting arrangements., setoff provisions and collateral. At September 30, 2013, the credit risk exposure to the banking and financial sector represented 88% of the total credit risk exposure and 59% of the net exposure, a significant amount of which is related to the natural gas 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 tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral 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 authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements 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 margin deposits are also utilized. Prospective material changes in the payment history or financial condition 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 of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

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10. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS Net pension and OPEB costs related to plans sponsored by EFH Corp. for the three and nine months ended September 30, 2013 and 2012 are comprised of the following:

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Components of net pension costs:

Service cost $ 2 $ 13 $ 6 $ 36 Interest cost 3 38 9 118 Expected return on assets (2) (42) (5) (122)

Amortization of net loss 2 30 6 84 Pension costs 5 39 16 116 Components of net OPEB costs:

Service cost 3 3 8 7 Interest cost 10 11 31 33 Expected return on assets (3)

(3) (9) (9)

Amortization of transition obligation - 1 Amortization of prior service cost (8) (8) (23) (24)

Amortization of net loss 7 4 22 11 OPEB costs 9 7 29 19 Total benefit costs 14 46 45 135 Less amounts expensed by Oncor (6) (8) (19) (26)

Less amounts deferred principally as a regulatory asset or property by Oncor (6) (21) (18) (64)

Net amounts recognized as expense by EFH Corp. and consolidated subsidiaries $ 2 $ 17 $ 8 $ 45 The decrease in pension costs in 2013 reflects the implementation of certain amendments to EFH Corp.'s pension plan completed in the fourth quarter 2012 that resulted in:

" splitting off assets and liabilities under the plan associated with employees of Oncor and all retirees and terminated vested participants of EFH Corp.

and its subsidiaries (including discontinued businesses) to a new plan sponsored and administered by Oncor (the Oncor Plan) and

" the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities associated with active employees of EFH Corp.'s competitive businesses other than collective bargaining unit employees.

The discount rates reflected in net pension and OPEB costs for 2013 are 4.30% and 4.10%, respectively. The expected rates of return on pension and OPEB plan assets reflected in the 2013 cost amounts are 5.4% and 6.7%, respectively.

Cash contributions in the first nine months of 2013 related to the pension plans totaled $7 million, essentially all of which was funded by Oncor, and

$13 million related to the OPEB plan, of which $9 million was funded by Oncor. Additional contributions expected in 2013 total less than $1 million for the pension plans, including amounts related to nonqualified plans, and $5 million for the OPEB plan, of which approximately $3 million is expected to be funded by Oncor.

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11. RELATED PARTY TRANSACTIONS The following represent our significant related-party transactions.

We pay an annual management fee under the terms of a management agreement with the Sponsor Group, reported in SG&A expense, totaling $10 million and $9 million for the three months ended September 30, 2013 and 2012, respectively, and $29 million and $28 million for the nine months ended September 30, 2013 and 2012, 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 each member of the Sponsor Group have from time to time engaged in commercial banking transactions with us and/or provided financial 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 related to debt exchanges totaled

$2 million, described as follows: (i) Goldman acted as a dealer manager for the offers by EFIH and EFIH Finance to exchange new EFIH 10% Notes for EFH Corp. 9.75% Notes, EFH Corp. 10% Notes and EFIH 9.75% Notes (collectively, the Old Notes) and as a solicitation agent in the solicitation of consents by EFH Corp. and EFIH and EFIH Finance to amendments to the Old Notes and indentures governing the Old Notes and (ii)

Goldman acted as 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 5 for further discussion of these exchange offers.

In the nine months ended September 30, 2012, fees paid to Goldman related to debt issuances totaled $10 million, described as follows: (i) Goldman acted as a joint book-running manager and initial purchaser in the February 2012 issuance of $1.15 billion principal amount of EFIH 11.750%

Notes; (ii) Goldman acted as joint book-running manager and initial purchaser in the August 2012 issuance of $600 million principal amount of 11.750% Notes and $250 million principal amount of EFIH 6.875% Notes. A broker-dealer affiliate of KKR served as a co-manager and initial purchaser and an affiliate of TPG served as an advisor in both of these transactions, for which they each received a total of $3 million.

• Affiliates of GS Capital Partners are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

• Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issued by us in open market transactions or through loan syndications.

TCEH made loans to EFH Corp. in the form of demand notes (TCEH Demand Notes) that were pledged as collateral under the TCEH Senior Secured Facilities for (i) debt principal and interest payments and (ii) other general corporate purposes (SG&A Note) for EFH Corp. The TCEH Demand Notes totaled $698 million at December 31, 2012, including $233 million in the SG&A Note, and are eliminated in consolidation in these condensed consolidated financial statements. EFH Corp. settled the balance of the TCEH Demand Notes in January 2013 using $680 million of the proceeds from debt issued by EFIH in 2012 that had been held as restricted cash (see Note 13).

As part of EFH Corp.'s liability management program, EFH Corp. and EFIH have purchased, or received in exchanges, certain debt securities of EFH Corp. and TCEH, which they have held. Principal and interest payments received by EFH Corp. and EFIH on these investments have been used, in part, to service their outstanding debt. These investments are eliminated in consolidation in these consolidated financial statements. At September 30, 2013, EFIH held $1.282 billion principal amount of EFH Corp. debt and $79 million principal amount of TCEH debt. At September 30, 2013, EFH Corp. held $303 million principal amount of TCEH debt. In the first quarter 2013, EFIH distributed as a dividend to EFH Corp. $6.360 billion principal amount of EFH Corp. debt previously received by EFIH in debt exchanges; EFH Corp. cancelled the debt instruments (see Note 5).

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Table of Contents TCEH's retail operations pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services, reported in fuel, purchased power costs and delivery fees, totaled $273 million and $281 million for the three months ended September 30, 2013 and 2012, respectively, and $728 million and $746 million for the nine months ended September 30, 2013 and 2012, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at September 30, 2013 and December 31, 2012 reflect amounts due currently to Oncor totaling $158 million and $53 million, respectively (included in net payables due to unconsolidated subsidiary), largely related to these electricity delivery fees. Also see discussion below regarding receivables from Oncor under a tax sharing agreement.

• In August 2012, TCEH 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 recover generation-related regulatory assets. Under the agreements, TCEH had been reimbursing Oncor as described immediately below. Under the settlement, TCEH paid, and Oncor received, $159 million in cash.

Oncor collects transition surcharges from its customers to recover the transition bond payment obligations. Oncor's incremental income taxes related to the transition surcharges it collects had been reimbursed by TCEH quarterly under a noninterest bearing note payable to Oncor that was to mature in 2016. TCEH's payments on the note prior to the August 2012 settlement totaled zero and $20 million for the three and nine months ended September 30, 2012, respectively.

Under an interest reimbursement agreement, TCEH had reimbursed Oncor on a monthly basis for interest expense on the transition bonds. Only the monthly accrual of interest under this agreement was reported as a liability. This interest expense prior to the August 2012 settlement totaled $2 million and $16 million for the three and nine months ended September 30, 2012, respectively.

• Oncor pays EFH Corp. subsidiaries for financial and other administrative services and shared facilities at cost. Such amounts reduced reported SG&A expense by $8 million and $10 million for the three months ended September 30, 2013 and 2012, respectively, and $24 million and $27 million for the nine months ended September 30, 2013 and 2012, respectively.

Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to TCEH for contribution 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 our balance sheet. The delivery fee surcharges remitted to TCEH totaled $5 million for both the three months ended September 30, 2013 and 2012 and $12 million for both the nine months ended September 30, 2013 and 2012. Income and expenses associated with the trust fund and the decommissioning liability incurred by TCEH are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates. At September 30, 2013 and December 31,2012, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $352 million and $284 million, respectively, reported in noncurrent liabilities.

We file a consolidated federal income tax return that includes Oncor Holdings' results. Oncor is not a member of our consolidated tax group, but our consolidated federal income tax retum includes our portion of Oncor's results due to our equity 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 Texas margin tax expense and related balance sheet amounts, including our income taxes receivable from or payable to Oncor Holdings and Oncor, are recorded as if Oncor Holdings and Oncor file their own corporate income tax returns.

At September 30, 2013, our current amount receivable from Oncor Holdings related to federal and state income taxes (included in net payables due to unconsolidated subsidiary) totaled $35 million, which includes $28 million from Oncor. At December 31, 2012, our current amount receivable totaled $34 million, which included $22 million from Oncor.

For the nine months ended September 30, 2013, EFH Corp. received net federal and state income tax payments from Oncor Holdings and Oncor totaling $24 million and $60 million, respectively. The 2013 net payment included $33 million from Oncor related to the 1997 through 2002 IRS appeals settlement and a $10 million refund paid to Oncor related to the filing of amended Texas franchise tax returns for 1997 through 2001. For the nine months ended September 30, 2012, EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $24 million and $3 million, respectively, net of $21 million in federal income tax refunds paid to Oncor Holdings.

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• Pursuant to the existing tax sharing agreement between EFH Corp. and TCEH, in September 2013, TCEH made a federal income tax payment of $84 million to EFH Corp related to the 1997 through 2002 IRS appeals settlement.

Certain transmission and distribution utilities in Texas have requirements in place to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at September 30, 2013 and December 31, 2012, TCEH had posted letters of credit in the amount of $10 million and $11 million, respectively, for the benefit of Oncor.

As a result of the pension plan actions discussed in Note 10, in December 2012, Oncor became the sponsor of a new pension plan (the Oncor Plan),

the participants in which consist of all of Oncor's active employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Oncor had previously contractually agreed to assume responsibility for pension and OPEB liabilities that are recoverable by Oncor under regulatory rate-setting provisions. As part of the pension plan actions, EFH Corp. fully funded the nonrecoverable pension liabilities under the Oncor Plan. After the pension plan actions, participants remaining in the EFH Corp. pension plan consist of active employees under collective bargaining agreements (union employees). Oncor continues to be responsible for the recoverable portion of pension obligations to these union employees. EFH Corp. is the sponsor of the OPEB plan and remains liable for the majority of the OPEB plan obligations. Accordingly, EFH Corp.'s balance sheet reflects unfunded pension and OPEB liabilities related to plans that it sponsors, including recoverable and nonrecoverable amounts, but also reflects a receivable from Oncor for that portion of the unfunded liabilities for which Oncor is contractually responsible, substantially all of which is expected to be recovered in Oncor's rates. At September 30, 2013 and December 31, 2012, the receivable amounts totaled $839 million and $825 million, respectively, classified as noncurrent. Under ERISA, EFH Corp. and Oncor remain jointly and severally liable for the funding of the EFH Corp. and Oncor pension 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 outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit 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.

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12. SEGMENT INFORMATION Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, 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 electricity transmission 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 Delivery segment, as an equity method investment. See Note 11 for discussion of material transactions with Oncor, including payment to Oncor of electricity delivery fees, which are based on rates regulated by the PUCT.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued businesses, general corporate expenses and interest and other expenses related to EFH Corp., EFIH and EFCH.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 above and in Note 1 to Financial Statements in our 2012 Form 10-K. We evaluate performance based on net income (loss). We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices or regulated rates.

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Operating revenues (all Competitive Electric) $ 1,893 $ 1,752 $ 4,572 $ 4,358 Equity in earnings of unconsolidated subsidiaries (net of tax) -

Regulated Delivery (net of noncontrolling interest of $29, $27,

$66 and $64) $ 114 $ 109 $ 255 $ 249 Net income (loss):

Competitive Electric $ 18 $ (393) $ (768) $ (1,319)

Regulated Delivery 114 109 255 249 Corporate and Other (127) (123) (122) (338)

Consolidated $ 5 $ (407) $ (635) $ (1,408) 41

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13. SUPPLEMENTARY FINANCIAL INFORMATION Other Income and Deductions Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Other income:

Office space rental income (a) $ 3 $ 3 $ 9 $ 9 Consent fee related to novation ofhedge positions between counterparties (b) 6 Insurance/litigation settlements (b) 2 2 All other 2 3 8 8 Total other income $ 5 $ 6 $ 19 $ 25 Other deductions:

Impairment of remaining equipment from cancelled generation development program (b) $ 27 $ $ 27 $

Impairment of mineral interests (b) 24 24 Impairment of computer software assets (a) 7 7 Other asset impairments (b) 3 3 Counterparty contract settlement (b) 4 4 Ongoing employee retirement benefit expense related to discontinued businesses (a) 4 (1) 10 All other 6 3 11 9 Total other deductions $ 36 $ 42 $ 40 $ 54 (a) Reported in Corporate and Other.

(b) Reported in Competitive Electric segment.

Interest Expense andRelated Charges Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Interest paid/accrued (including net amounts settled/accrued under interest rate swaps) $ 851 $ 812 $ 2,532 $ 2,405 Interest payable with additional toggle notes (Note 5) 45 61 130 177 Unrealized mark-to-market net (gain) loss on interest rate swaps (a) (414) 21 (903) 12 Amortization of interest rate swap losses at dedesignation of hedge accounting 2 2 6 7 Amortization of fair value debt discounts resulting from purchase accounting 5 11 15 33 Amortization of debt issuance, amendment and extension costs and discounts 49 48 154 143 Capitalized interest (5) (11) (19) (31)

Total interest expense and related charges $ 533 $ 944 $ 1,915 $ 2,746 (a) Three months ended September 30, 2013 and 2012 amounts include net gains totaling $413 million and net losses totaling $20 million, respectively, related to TCEH swaps (see Note 5) and net gains totaling $1 million and net losses totaling $1 million, respectively, related to EFH Corp. swaps substantially closed through offsetting positions. Nine months ended September 30, 2013 and 2012 amounts include net gains totaling $899 million and net losses totaling $16 million, respectively, related to TCEH swaps and net gains totaling $4 million for both periods related to EFH Corp. swaps substantially closed through offsetting positions.

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Table of Contents Restricted Cash September 30, 2013 December 31, 2012 Current Assets Noncurrent Assets Current Assets Noncurrent Assets Amounts in escrow to settle TCEH Demand Notes (Note 11) $ - $ - $ 680 $ -

Amounts related to TCEH's Letter of Credit Facility (Note 5) 947 - 947 Other 4 $ $

Total restricted cash $ 4 $ 947 $ 680 $ 947 Inventories by Major Category September 30, December 31, 2013 2012 Materials and supplies $ 216 $ 201 Fuel stock 155 168 Natural gas in storage 29 24 Total inventories $ 400 $ 393 OtherInvestments September 30, December 31, 2013 2012 Nuclear plant decommissioning trust $ 737 $ 654 Assets related to employee benefit plans, including employee savings programs, net of distributions 63 70 Land 40 41 Miscellaneous other 3 2 Total other investments $ 843 $ 767 43

Table of Contents Nuclear Decommissioning Trust - Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as a delivery fee surcharge over the life of the plant and deposited by TCEH in the trust fund. Income and expense associated with the trust fund and the decommissioning liability are offset by a corresponding change in a receivable/payable (currently a payable reported in noncurrent liabilities) that will ultimately be settled through changes in Oncor's delivery fees rates (see Note 11). A summary of investments in the find follows:

September 30, 2013 Fair market Cost (a) Unrealized gain Unrealized loss value Debt securities (b) $ 261 $ 9 $ (4) $ 266 Equity securities (c) 252 227 (8) 471 Total $ 513 $ 236 $ (12) $ 737 December 31, 2012 Fair market Cost (a) Unrealized gain Unrealized loss value Debt securities (b) $ 246 $ 16 $ (1) $ 261 Equity securities (c) 245 161 (13) 393 Total $ 491 $ 177 $ (14) $ 654 (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 rating of AA or above as graded by S&P or Aa2 by Moody's Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.97% and 4.38% at September 30, 2013 and December 31,2012, respectively, and an average maturity of 6 years at both September 30, 2013 and December 31, 2012.

(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 September 30, 2013 mature as follows: $103 million in one to five years, $58 million in five to ten years and $105 million after ten years.

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Realized gains $ 1 $ -- $ 2 $ 1 Realized losses $ (3) $ (1) $ (3) $ (2)

Proceeds from sales of securities $ 23 $ 25 $ 128 $ 56 Investments in securities $ (28) $ (30) $ (140) $ (68)

Property,Plantand Equipment At September 30, 2013 and December 31, 2012, property, plant and equipment of $18.1 billion and $18.7 billion, respectively, is stated net of accumulated depreciation and amortization of $7.8 billion and $6.9 billion, respectively.

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Table of Contents Asset Retirement and Mining Reclamation Obligations These 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 no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of Oncor's delivery fees.

The following table summarizes the changes to these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in the balance sheet, for the nine months ended September 30, 2013:

Nuclear Plant Mining Land Decommissioning Reclamation Other Total Liability at December 31, 2012 $ 368 $ 135 $ 33 $ 536 Additions:

Accretion 17 23 1 41 Reductions:

Payments - (72) (1) (73)

Liability at September 30, 2013 385 86 33 504 Less amounts due currently - (60) - (60)

Noncurrent liability at September 30, 2013 385 $ 26 $ 33 $ 444 Other NoncurrentLiabilitiesand Deferred Credits The balance of other noncurrent liabilities and deferred credits consists of the following:

September 30, December 31, 2013 2012 Uncertain tax positions (including accrued interest) $ 427 $ 2,005 Retirement plan and other employee benefits (a) 1,050 1,035 Asset retirement and mining reclamation obligations 444 452 Unfavorable purchase and sales contracts 596 620 Nuclear decommissioning cost over-recovery (Note 11) 352 284 Other 34 30 Total other noncurrent liabilities and deferred credits 2,903 $ 4,426 (a) Includes $839 million and $825 million at September 30, 2013 and December 31, 2012, respectively, representing pension and OPEB liabilities related to Oncor (see Note 11).

Liabilityfor Uncertain Tax Positions- In May 2013, we received approval from the Joint Committee on Taxation of the IRS appeals settlement of all issues arising from the 1997 through 2002 IRS audit, which includes all tax issues related to EFH Corp.'s discontinued Europe operations. The settlement also affected federal and state returns for periods subsequent to 2002. In the second quarter 2013, we reduced the liability for uncertain tax positions to reflect the effects of the settlement, resulting in a $524 million reclassification to the accumulated deferred income tax liability and the recording of a $183 million income tax benefit. Other effects included the recording of a $19 million noncurrent federal income tax liability, an $8 million current federal income tax liability, a $15 million current state income tax liability and a $33 million federal income tax receivable from Oncor under the tax sharing agreement (see Note 11). In the third quarter 2013, we recorded an additional $38 million tax benefit, with an offset to accumulated deferred income tax liability, related to the settlement. The total income tax benefit of $221 million reflected a $204 million income tax benefit recorded in Corporate and Other activities and a $17 million income tax benefit reported in the Competitive Electric segment results.

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Table of Contents In March 2013, EFH Corp. and the IRS agreed on terms to resolve disputed adjustments related to the IRS audit for the years 2003 through 2006, which was concluded in June 2011. The IRS proposed a significant number of adjustments to the originally filed returns for such years. The adjustments relate to one significant accounting method issue and other less significant issues. In the first quarter 2013, we reduced the liability for uncertain tax positions to reflect the terms of the agreement, resulting in a $701 million reclassification to the accumulated deferred income tax liability and a net adjustment of $143 million

($84 million after tax), largely representing a reversal of accrued interest and reported as an increase in income tax benefit. Any cash income tax liability related to this agreement is expected to be immaterial. The $84 million income tax benefit reflected a $62 million income tax benefit recorded in the Competitive Electric segment results and a $22 million income tax benefit recorded in Corporate and Other activities.

The March 2013 settlement and May 2013 IRS appeals settlement resulted in the expected elimination of all net operating loss carryforwards generated through 2013, as well as elimination of remaining alternative minimum tax credit carryforwards.

UnfavorablePurchaseand Sales Contracts- The amortization of unfavorable purchase and sales contracts totaled $6 million for both the three months ended September 30, 2013 and 2012 and $19 million and $20 million for the nine months ended September 30, 2013 and 2012, 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 Amount 2013 $ 25 2014 $ 24 2015 $ 23 2016 $ 23 2017 $ 23 Supplemental Cash Flow Information Nine Months Ended September 30, 2013 2012 Cash payments (receipts) related to:

Interest paid (a) $ 2,391 $ 2,150 Capitalized interest (19) (31)

Interest paid (net of capitalized interest) (a) $ 2,372 $ 2,119 Income taxes $ 65 $ 67 Noncash investing and financing activities:

Principal amount of toggle notes issued in lieu of cash interest (Note 5) $ 83 $ 114 Construction expenditures (b) $ 65 $ 55 Debt exchange and extension transactions (Note 5) $ (326) $

Debt assumed related to acquisition of combustion turbine trust interest $ (45) $

(a) Net of amounts received under interest rate swap agreements.

(b) Represents end-of-period accruals.

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Table of Contents Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2013 and 2012 should be read in conjunction with our condensed consolidated financial 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 otherwise indicated.

Business EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries.

EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission 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 Holdings, a holding company that holds an approximately 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp.

Various "ring-fencing" measures have been taken to enhance the credit quality of Oncor. See Notes I and 2 to Financial Statements for a discussion of the reporting of our investment in Oncor (and Oncor Holdings) as an equity method investment and a description of the "ring-fencing" measures implemented with respect to Oncor. These measures were put in place to further enhance Oncor's credit quality and mitigate Oncor's exposure to the Texas Holdings Group with the intent to minimize the risk that a court would order any of the assets and liabilities of the Oncor Ring-Fenced Entities to be substantively consolidated with those of any member of the Texas Holdings Group in the event any such member were to become a debtor in a bankruptcy case. We believe, as several major credit rating agencies have acknowledged, that the likelihood of such substantive consolidation of the Oncor Ring-Fenced Entities' assets and liabilities is remote in consideration of the ring-fencing measures and applicable law.

OperatingSegments Our operations are aligned into two reportable businesses: Competitive Electric and Regulated Delivery. The Competitive Electric segment consists largely of TCEH. The Regulated Delivery segment consists largely of our investment in Oncor.

See Note 12 to Financial Statements for further information regarding reportable business segments.

Significant Activiides and Events andItems Influencing FuturePerformance See Note I to Financial Statements for discussion of TCEH liquidity and description of our discussions with creditors.

Income Tax Matters - See Note 13 to Financial Statements for discussion of the agreement we reached with the IRS Appeals in March 2013 that resolved disputed adjustments from the IRS audit for the years 2003 through 2006 and the approval we received from the Joint Committee on Taxation of the IRS appeals settlement in May 2013 that resolved all issues from the IRS audit for the years 1997 through 2002. See "Financial Condition - Income Tax Matters" for discussion of the private letter ruling we received from the IRS in April 2013 and our subsequent consummation of internal corporate transactions involving EFH Corp. and EFCH that resulted in the elimination of an excess loss account and a deferred intercompany gain.

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Table of Contents NaturalGas Hedging Programand Other Hedging Activities - Because wholesale electricity prices in ERCOT have generally moved with natural gas prices, TCEH has a natural gas hedging program designed to mitigate the effect of natural gas price changes on future electricity revenues. Under the program, we have entered into market transactions involving natural gas-related financial instruments, and at September 30, 2013, have effectively sold forward approximately 210 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 25,000 GWh at an assumed 8.5 market heat rate) at weighted average annual hedge prices as shown in the table below; at December 31, 2012, March 31, 2013 and June 30, 2013, the comparable hedge volumes totaled approximately 360 million MMBtu, 310 million MMBtu and 270 million MMBtu, respectively. Volumes and hedge values associated with the hedging program are inclusive of offsetting purchases entered into to take into account new wholesale and retail electricity sales contracts and avoid over-hedging. This activity results in both commodity contract asset and liability balances pending the maturity and settlement of the offsetting transactions.

Taking together forward wholesale and retail electricity sales with the natural gas positions in the hedging program, we have effectively hedged an estimated 96% and 78% of the price exposure, 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). The natural gas positions were entered into with the continuing expectation that wholesale electricity prices in ERCOT will generally move with prices of natural gas, which we expect to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOT market. If the relationship changes in the future, the cash flows targeted under the natural gas hedging program may not be achieved.

TCEH has entered into related put and call transactions (referred to as collars), primarily for 2014, that result in hedge prices that fall within a range.

These transactions represented 71% (in MMbtu) of the positions in the hedging program at September 30, 2013, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu.

We currently have no natural gas positions in the hedging program that mature after 2014. The following table summarizes the positions in the program at September 30, 2013:

Balance Measure 2013 (a) 2014 Total Natural gas hedge volumes (b) mm MMBtu -65 -146 -211 Weighted average hedge price (c) $iMMBtu -6.89 -7.80 -

Average market price (d) $/MMBtu -3.60 -3.86 -

Realization of hedge gains (e) $ billions -0.2 -0.6 -0.8 (a) Balance of 2013 is from October 1, 2013 through December 31, 2013.

(b) Where collars are reflected, the volumes are based on the delta equivalent short position of approximately 150 million MMBtu in 2014.

(c) Weighted average hedge prices are based on prices of positions in the natural gas hedging program (excluding offsetting purchases 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 September 30, 2013.

Changes in the fair value of the instruments in the hedging program are recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the hedging program at September 30, 2013, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $210 million in pretax unrealized mark-to-market gains or losses.

The hedging program has resulted in reported net gains (losses) as follows:

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Realized net gain $ 276 $ 440 $ 756 $ 1,459 Unrealized net loss including reversals of previously recorded amounts related to positions settled (258) (539) (739) (1,244)

Total $ 18 $ (99) $ 17 $ 215 48

Table of Contents The cumulative unrealized mark-to-market net gain related to positions in the natural gas hedging program totaled $845 million and $1.584 billion at September 30, 2013 and December 31, 2012, respectively. The decline was driven by settlement of maturing positions.

Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in the future. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices 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 hedging program reflects the sustained decline in forward market natural gas prices as presented in the table below. Forward natural gas prices have generally trended downward over the past several years. While the hedging program is designed to mitigate the effect on earnings of low wholesale electricity prices, depressed forward natural gas prices are challenging to our liquidity and the long-term profitability of EFH Corp.'s competitive businesses. Specifically, low natural gas prices and their effect in ERCOT on wholesale electricity prices could have a material impact on our liquidity and TCEH's overall profitability for periods in which TCEH does not have significant hedge positions. See Note 1 to Financial Statements.

Forward Market Prices for Calendar Year (SIMMBtu) (a)

Date 2013 (b) 2014 2015 2016 December 31, 2008 $ 7.15 $ 7.15 $ 7.21 $ 7.30 December 31, 2009 $ 6.67 $ 6.84 $ 7.05 $ 7.24 December 31, 2010 $ 5.33 $ 5.49 $ 5.64 $ 5.79 December 31, 2011 $ 3.94 $ 4.34 $ 4.60 $ 4.85 March 31, 2012 $ 3.47 $ 3.96 $ 4.26 $ 4.51 June 30, 2012 $ 3.58 $ 3.95 $ 4.13 $ 4.29 September 30, 2012 $ 3.84 $ 4.18 $ 4.37 $ 4.55 December 31, 2012 $ 3.54 $ 4.03 $ 4.23 $ 4.42 March 31, 2013 $ 4.12 $ 4.23 $ 4.30 $ 4.38 June 30, 2013 $ 3.64 $ 3.91 $ 4.14 $ 4.33 September 30, 2013 $ 3.60 $ 3.86 $ 4.06 $ 4.17 (a) Based on NYMEX Henry Hub prices.

(b) For March 31, 2013, June 30, 2013 and September 30, 2013, natural gas prices for 2013 represent the average of forward prices for April through December, July through December and October through December, respectively.

The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas prices, market heat rates and diesel fuel prices on realized pretax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH's unhedged position and forward prices at September 30, 2013, which for natural gas reflects estimates of electricity generation less amounts hedged through the natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling basis, generally twelve-months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

Balance 2013 (a) 2014 2015

$1.00/MMBtu change in natural gas price (b) $ -3 $~115 $-475

0. l/MMBtu/MWh change in market heat rate (c) $ - $-20 $-30

$ -I $ ~15 $ -45

$1.00/gallon change in diesel fuel price (a) Balance of 2013 is from November 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 being on 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 gas position is assumed to be generated). Excludes the impact of economic backdown.

(c) Based on Houston Ship Channel natural gas prices at September 30, 2013.

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Table of Contents TCEH InterestRate Swap Transactions- TCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, as of September 30, 2013, TCEH has entered into the following series of interest rate swap transactions that effectively fix the interest rates at between 5.5% and 9.3%:

ixed Rates Expiration Dates Notional Amount 5.5% - 9.3% October 2013 through October 2014 $ 18.140 billion (a) 6.8% - 9.0% October 2015 through October 2017 $ 12.600 billion (b)

(a) Swaps related to an aggregate $1.6 billion principal amount of debt expired in 2013. Per the terms of the transactions, the notional amount of swaps entered into in 2011 grew by $1.280 billion 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.

TCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achieved through the interest rate swaps.

Basis swaps in effect at September 30, 2013 totaled $11.967 billion notional amount. The basis swaps relate to debt outstanding through 2014.

The interest rate swaps have resulted in net gains (losses) reported in interest expense and related charges as presented in the table below. See Note 8 to Financial Statements for discussion of nonperformance risk adjustments included in unrealized net gain in 2013.

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Realized net loss $ (160) $ (168) $ (466) $ (505)

Unrealized net gain (loss) including reversals of previously recorded amounts related to settled positions 413 (20) 899 (16)

Total $ 253 $ (188) $ 433 $ (521)

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.518 billion (before nonperformance risk adjustment) and $2.065 billion at September 30, 2013 and December 31, 2012, respectively. The decline in the net liability reflected unrealized gains due to higher interest rates and swap settlements. This mark-to-market position can change materially in value as market conditions change, which could result in significant volatility in reported net income. For example, at September 30, 2013, a one percent change in interest rates would result in an increase or decrease of approximately $525 million in our cumulative unrealized mark-to-market net liability.

First-Lien Securityfor Natural Gas Hedging Programand Interest Rate Swaps - Approximately 95% of the positions in the natural gas hedging program and all of the TCEH interest rate swaps are secured by a first-lien interest in the assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes. Certain entities are counterparties to both our natural gas hedging program positions and our interest rate swaps and have entered into master agreements that provide for netting and setoff of amounts related to these positions. At September 30, 2013, our net liability positions related to these counterparties together with liability positions related to entities that are counterparties to only our interest rate swaps totaled approximately $1.2 billion (before nonperformance risk adjustment). This amount is subject to change based on changes in interest rates and natural gas prices.

SeasonalSuspension of Certain GenerationOperations - In October 2013, ERCOT approved our notice of intent (filed in September 2013) to suspend operations at one of the three generation units at our Martin Lake generation facility for approximately six months beginning December 2013 due to low wholesale power prices and other market conditions. The unit is expected to return to service during the peak demand months in the summer of 2014. Our mines that support the Martin Lake facility are expected to continue year-round operations.

In August 2013, ERCOT approved our notice of intent, as previously disclosed, to suspend operations beginning October 1, 2013 at two of the three generation units at our Monticello generation facility due to low wholesale power prices and other market conditions. The two Monticello units are expected to return to service during the peak demand months in the summer of 2014. Our mines that support the Monticello generation facility are expected to continue year-round operations.

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Table of Contents At current wholesale market prices of electricity, we do not expect the suspension of operations to significantly impact our results of operations, liquidity or financial condition. The previously disclosed seasonal suspension of two generation units at Monticello that began December 1, 2012 ended June 1, 2013 as planned.

NaturalGas-FueledGenerationDevelopment - In August 2013, the TCEQ granted air permits to Luminant to build two natural gas combustion turbines totaling 420 MW to 460 MW at its existing DeCordova generation facility. In May 2013, Luminant filed an air permit application with the TCEQ to build two natural gas combustion turbines totaling 420 MW to 460 MW at its existing Tradinghouse generation facility. While we believe current market conditions do not provide adequate economic returns for the development or construction of these facilities, we believe additional generation resources will be needed to support future electricity demand growth and reliability in the ERCOT market.

Liability ManagementProgram - At September 30, 2013, EFH Corp. and its consolidated subsidiaries had $38.3 billion principal amount of long-term debt outstanding. In October 2009, we implemented a liability management program designed to reduce debt, capture debt discount and extend debt maturities through debt exchanges, repurchases and extensions. Activities under 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 2014 to October 2017 and $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016.

Other liability management activities since October 2009 include debt exchange, issuance and repurchase activities as follows:

Debt Security (except where noted, debt amounts are principal amounts) Acquired Debt Issued/Cash Paid EFH Corp. 10.875% Notes due 2017 $ 1,967 $ -

EFH Corp. Toggle Notes due 2017 3,126 53 EFH Corp. 5.55% Series P Senior Notes due 2014 910 -

EFH Corp. 6.50% Series Q Senior Notes due 2024 549 -

EFH Corp. 6.55% Series R Senior Notes due 2034 459 -

TCEH 10.25% Notes due 2015 1,875 TCEH Toggle Notes due 2016 751 -

TCEH Senior Secured Facilities due 2013 and 2014 1,623 EFH Corp. and EFIH 9.75% Notes due 2019 252 256 EFH Corp 10% Notes due 2020 1,058 561 EFIH 11% Notes due 2021 406 EFIH 10% Notes due 2020 3,482 EFIH Toggle Notes due 2018 1,392 TCEH 15% Notes due 2021 1,221 TCEH 11.5% Notes due 2020 (a) 1,604 Cash paid, including use of proceeds from debt issuances in 2010 (b) -- 1,062 Total (c) $ 12,570 $ 10,037 (a) Debt issued amount represents $1.750 billion principal amount less $12 million in debt discount and $134 million in proceeds used for transaction costs related to the issuance of these notes and the amendment and extension of the TCEH Senior Secured Facilities. The net proceeds amount of $1.604 billion was used to repay borrowings under the TCEH Senior Secured Facilities, and the remaining transaction costs were funded with cash on hand.

(b) 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 TCEH 15% Senior Secured Second Lien Notes due 2021.

The total $390 million of proceeds was used to repurchase debt.

(c) Total debt acquired includes an aggregate $2.228 billion principal amount that is held by EFH Corp. and EFIH, including $564 million of EFH Corp.

debt held by EFH Corp. All other debt acquired has been canceled.

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Table of Contents In January 2013, EFIH issued $1.391 billion principal amount of debt in exchange for $1.266 billion principal amount of EFH Corp. debt and $139 million principal amount of EFIH debt. See Note 5 to Financial Statements for discussion of these and other debt-related transactions and Note I to Financial Statements regarding "Liquidity Considerations" and "Discussions with Creditors." Since inception, the transactions in 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.

EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) continue to consider and evaluate possible transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and have entered 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 and extensions of debt obligations and exchanges or conversions of debt for preferred or common equity or warrants, including exchanges or conversions of debt of EFH Corp., EFIH, EFCH and TCEH into preferred or common equity or warrants of EFH Corp., EFIH, EFCH, TCEH and/or any of their subsidiaries.

In evaluating whether to undertake any liability management transaction, we will take into account, among other things, liquidity requirements, prospects for future access to capital, contractual restrictions, tax consequences, the market price and maturity dates of its outstanding debt and potential transaction costs. Any liability management transaction, including any refinancing or extension, may occur on a stand-alone basis or in connection with, or immediately following, other liability management transactions.

Environmental Matters - See Note 6 to Financial Statements for a discussion of the CSAPR and other EPA actions as well as related litigation.

Greenhouse Gas Emissions - In September 2013, the EPA issued a proposed rule for greenhouse gas emission standards for new electricity generation units. We are currently reviewing this proposed rule; however, at this time it is uncertain how (if at all) the proposed rule, if finalized, would affect our results of operations, liquidity or financial condition.

President Obama has also directed the EPA to propose standards, regulations, or guidelines that address greenhouse gas emissions from modified, reconstructed, and existing power plants by June 2014 and finalize them by June 2015. The proposed rule is to include guidelines that require states to submit to the EPA their implementing plans and regulations by June 2016. We cannot predict the outcome of this rulemaking. It is uncertain how (if at all) any such proposed rule, if finalized, would affect our results of operations, liquidity or financial condition.

In addition, the US Supreme Court (Supreme Court) recently granted review in Am. Chemist.v Council, et al v. EPA, et aL. In that case, the Supreme Court will consider whether EPA's regulation of greenhouse gas emissions from new motor vehicles allow it to require permits under the CAA for stationary sources that emit greenhouse gases. We are not a party to that case. It is uncertain how (if at all) any decision by the Supreme Court would affect our results of operations, liquidity or financial condition.

Mercury and Air Toxics Standard (MATS)- In December 2011 the EPA finalized the MATS rule, which regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases. Any additional control equipment retrofits on our lignite/coal-fueled generation units required to comply with the MATS rule as finalized would need to be installed within three to four years from the April 2012 effective date of the rule. In April 2012, we filed a petition for review of the MATS rule 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 the MATS rule, including changes to the work practice standards affecting all units. In March 2013, the EPA finalized the revised standards for new coal-fired units and certain other minor changes but did not address the work practice standards. In June 2013, the EPA solicited comments on certain proposed changes to these work practice standards. We cannot predict the outcome of this rulemaking.

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Table of Contents Regional Haze - S02 and NOx reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions are required either on a unit-by-unit basis or by state participation in an EPA-approved regional trading program such as the CAIR. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) conceming regional haze to the EPA, which we believe would not have a material impact on our generation facilities. In December 2011, the EPA proposed a limited disapproval of the SIP due to its reliance on the CAIR and a Federal Implementation Plan for Texas providing that the inclusion in the CSAPR programs meets the regional haze requirements for SO 2 and NOx reductions.

In June 2012, the EPA finalized the limited disapproval of the Texas regional haze SIP, but did not finalize a Federal Implementation Plan for Texas. We cannot predict whether or when the EPA will finalize a Federal Implementation Plan 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 Fifth Circuit Court challenging the EPA's limited disapproval of the Texas regional haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court's decision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of Federal Implementation Plans regarding regional haze. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending regional haze appeals. The consolidated cases now in the D.C. Circuit Court are held in abeyance pending completion of the CSAPR rehearing proceeding described in Note 6 to Financial Statements. We cannot predict when or how the D.C. Circuit Court will rule on these petitions. In May 2013, the TCEQ finalized a required five-year revision to its Regional Haze (SIP), and a court-ordered deadline for the EPA to propose a decision on the Texas Regional Haze SIP was extended to May 2014.

FinancialServices Reform Legislation - In July 2010, the US Congress enacted financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer 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 to enforce consumer protection laws and promulgate rules against unfair, deceptive or abusive practices; to enhance regulation of the derivatives markets, including the requirement for central clearing of over-the-counter derivative instruments and additional capital and margin requirements for certain derivative market participants and to implement a number of new corporate governance requirements 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 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 use to 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 the clearing requirements. The legislation mandates significant compliance requirements for any entity that is determined to be a Swap Dealer or Major Swap Participant and additional reporting and recordkeeping requirements for all entities that participate in 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 of the term Swap and the Swap Dealer/Major Swap Participant rule became effective in October 2012. Accordingly, we are required to continually assess our activity to determine if we will be required to register as a Swap Dealer or Major Swap Participant. Based on our assessments to date, we are not a Swap Dealer or Major Swap Participant.

The reporting requirements under the Financial Reforn Act for entities that are not Swap Dealers or Major Swap Participants became effective in August 2013, and we are in compliance with these rules.

In September 2012, the District Court for the District of Columbia issued an order that vacated and remanded to the CFTC its Position Limit Rule (PLR), which would have been effective in October 2012. The PLR provided for specific position limits related to 28 Core Referenced Futures Contracts, including the NYMEX Henry Hub Natural Gas Futures Contract, the NYMEX Light Sweet Crude Oil Futures Contract and the NYMEX New York Harbor No. 2 Heating Oil Futures Contract. If the PLR had been approved by the court, we would have been required to comply with the portion of the PLR applicable to the contracts noted above, which would result in increased monitoring and reporting requirements. We cannot predict when, or in what form, the CFTC will change the PLR.

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Table of Contents The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. However, the final rule for margin requirements for Swap Dealers and Major Swap Participants has not been issued, thus we have not been able to assess the impact of the final rule on our operations. If we were required to post cash collateral on our swap transactions with Swap Dealers and Major Swap Participants, our liquidity would likely be materially impacted, and our ability to enter into OTC derivatives to hedge our commodity and interest rate risks would be significantly limited.

Recent PUCT/ERCOT Actions- In May 2013, ERCOT published an updated Capacity, Demand, and Reserves report. The May 2013 report showed declining reserve margins in the ERCOT market that fall below the current 13.75% target reserve margin to 11.6% in 2015 and 10.4% in 2016. A number of changes to the ERCOT market rules have been implemented for the stated purpose of sending appropriate price signals to encourage development of generation resources in ERCOT. These changes, among others, include an increased system-wide offer cap that applies to wholesale power offers in ERCOT (from its previous level of $3,000 per MWh to $4,500 per MWh effective August 2012, $5,000 per MWh effective June 2013 and $7,000 and $9,000 per MWh in the surnmers of 2014 and 2015, respectively).

In September 2013, the PUCT directed ERCOT to develop the processes necessary to implement a new price mechanism, "the operating reserve demand curve" (also known as "ORDC" and "Hogan B+"), which would provide for an increasing price adder to real-time wholesale power prices as reserves decline.

The market rules implementing the operating reserve demand curve require approval by the ERCOT Board and could be appealed to the PUCT. Although two of the three PUCT commissioners indicated in October 2013 that ERCOT should have a required reserve margin instead of a target reserve margin, discussions are expected to continue among the PUCT, ERCOT, market participants and other stakeholders regarding the level of the reserve margin and additional actions necessary to meet a required reserve margin.

Sunset Review'/2013 Texas Legislative Session - Sunset review is the regular assessment of the continuing need for a state agency to exist, and is grounded in 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 agency to the Texas Legislature, which action may include modifying or even abolishing the agency. The PUCT and the RCT were subject to review by the Sunset Commission in 2013.

During the 2013 legislative session that ended in May 2013, the Texas Legislature passed the PUCT Sunset bill and extended the life of the PUCT for 10 years through 2023. The bill did not fundamentally change the management or operation of the PUCT related to electricity issues. The bill included various electric service regulation changes, including clarification on PUCT oversight of ERCOT, protections regarding customer privacy related to advanced meter data and new PUCT authority to issue cease and desist orders. The Legislature did not pass the RCT Sunset bill, but it did extend the life of the RCT until 2017 at which time the RCT will undergo another full Sunset review.

No legislation passed during the 2013 Texas legislative session, including the Sunset Review actions described above, is expected to have a material impact on our results of operations, liquidity or financial condition. The Texas Legislature is scheduled to convene its next legislative session in January 2015.

Oncor Matters with the PUCT - Competitive Renewable Energy Zones (CREZs) - In 2009, the PUCT awarded Oncor CREZ 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 approved by the PUCT. The projects involve the construction of transmission lines and stations to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in the western part of Texas to population centers in the eastern part of Texas. In addition to these projects, ERCOT completed a study in December 2010 that will result in Oncor and other transmission service providers building additional facilities to provide further voltage support to the transmission grid as a result of CREZ. Oncor currently estimates, based on these additional voltage support facilities and the approved routes and stations for its awarded CREZ projects, that CREZ construction costs will total approximately $2.0 billion. CREZ-related costs could change based on finalization of costs for the additional voltage support facilities and final detailed designs of subsequent project routes. At September 30, 2013, Oncor's cumulative CREZ-related capital expenditures totaled $1.842 billion, including

$382 million in 2013. Oncor expects that all necessary permitting actions and other requirements and all line and station construction activities for Oncor's CREZ construction projects will be completed by the end of 2013. Additional voltage support projects are expected to be completed by early 2014, with the exception of one series capacitor project that is scheduled to be completed in December 2015.

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Table of Contents Transmission Cost Recovery and Rates (PUCTDocket Nos. 41543, 41002 and 40451) - In order to reflect increases or decreases in its wholesale transmission costs, including fees paid to other transmission service providers, Oncor is required to file an update to the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs twice a year. In June 2013, Oncor filed an application to update the TCRF, which became effective September 1, 2013. This application was designed to increase Oncor's billings for the period from Septembcr 2013 through February 2014 by $88 million. In November 2012, Oncor filed an application to update the TCRF, which became effective March 1, 2013. This application was designed to reduce Oncor's billings for the period from March 2013 through August 2013 by $47 million. In June 2012, Oncor filed an application to update the TCRF, which became effective in September 2012. This application was designed to increase Oncor's billings for the period from September 2012 through February 2013 by

$129 million.

TransmissionInterim Rate Update Applications (PUCTDocket Nos. 41706 and 41166) - In order to reflect changes in its invested transmission capital, PUCT rules allow Oncor to update its transmission cost of service (TCOS) rates by filing up to two interim TCOS rate adjustments in a calendar 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's delivery rates, to REPs with retail customers in Oncor's service territory. In July 2013, Oncor filed an application for an interim update of its TCOS rate. The new rate was approved by the PUCT and became effective in September 2013. Oncor's annualized revenues will increase by an estimated $71 million with approximately $45 million of this increase recoverable through transmission costs charged to wholesale customers and $26 million recoverable from REPs through the TCRF component of Oncor's delivery rates. In January 2013, Oncor filed an application for an interim update of its TCOS rate. The new rate was approved by the PUCT and became effective in March 2013. Oncor's annualized revenues increased by an estimated $27 million with approximately $17 million of this increase recoverable through transmission costs charged to wholesale customers and $10 million recoverable from REPs through the TCRF component of Oncor's delivery rates.

Applicationfor 2014 EnergD,Efficiency Cost Recover, Factor (PUCTDocket No. 41544) - In May 2013, Oncor filed an application with the PUCT to request approval of the energy efficiency cost recovery factor (EECRF) for 2014. PUCT rules require Oncor to make an annual EECRF filing by the first business day in June in each year for implementation on March 1 of the next calendar year. The requested 2014 EECRF was $73 million, which is the same amount established for 2013, and would result in a monthly charge for residential customers of $1.01 as compared to the 2013 residential charge of

$1.23 per month. The requested 2014 EECRF is designed to recover $62 million of Oncor's costs for the 2014 program year, a $12 million performance bonus based on Oncor's 2012 results and a $1 million decrease for over-recovery of 2012 costs. A settlement has been reached, and PUCT approval is expected in the fourth quarter 2013.

Applicationfor Reconciliation ofAdvanced Meter Surcharge (PUCTDocket No. 41814) - In September 2013, Oncor filed an application with the PUCT for reconciliation of all costs incurred and investments made from January 1, 2011 through December 31, 2012, in the deployment of Oncor's advanced metering system (AMS) pursuant to the AMS Deployment Plan approved in Docket No. 35718. During the 2011 to 2012 period, Oncor incurred approximately $300 million of capital expenditures and $34 million of operating and maintenance expense, and billed customers approximately $174 million through the AMS surcharge. In addition to the reconciliation, Oncor is seeking a finding from the PUCT that approximately $28 million of additional estimated capital expenditures and approximately $4 million of additional estimated annual operation and maintenance expense related to cyber security and disaster recovery protections are reasonable and necessary costs associated with the deployment of an advanced metering system are recoverable through the AMS surcharge. Oncor is not seeking a change in the AMS surcharge in this proceeding, and anticipates that the proceeding will be concluded in the second quarter of 2014.

Summar, - We cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly affect our results of operations, liquidity or financial condition.

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Table of Contents RESULTS OF OPERATIONS ConsolidatedFinancialResults - Three Months Ended September 30, 2013 Comparedto Three Months Ended September 30, 2012 See "Competitive Electric Segment - Financial Results" below for a discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities; operating costs; depreciation and amortization; SG&A expenses and franchise and revenue-based taxes.

See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges decreased $411 million to $533 million in 2013. The decrease was driven by $414 million in unrealized mark-to-market net gains on interest rate swaps in 2013 compared to $21 million in net losses in 2012. See Note 8 to Financial Statements regarding nonperformance risk adjustment related to interest rate swaps. This change was partially offset by $23 million in higher interest expense driven by higher average borrowings.

See Note 13 to Financial Statement for details of interest expense and related charges.

Income tax benefit totaled $100 million and $296 million in 2013 and 2012, respectively. Excluding the $38 million in total income tax benefit recorded in the third quarter of 2013 related to resolution of IRS audit matters (see Note 13 to Financial Statements regarding uncertain tax positions), the effective tax rate effective tax rate was 29.7% and 36.5% in 2013 and 2012, respectively. The decrease in the effective tax rate was driven by a lower lignite depletion deduction.

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) increased $5 million to $114 million in 2013. The increase in Oncor's earnings reflected higher revenues driven by higher transmission rates and growth in points of delivery, partially offset by higher depreciation and lower interest income. See Note 2 to Financial Statements.

After-tax results improved $412 million to $5 million in net income in 2013.

• After-tax results in the Competitive Electric segment improved $411 million to $18 million in net income.

• Earnings from the Regulated Delivery segment increased $5 million to $114 million as discussed above.

After-tax net expenses from Corporate and Other activities include recurring interest expense on outstanding debt as well as corporate general and administrative expenses and totaled $127 million and $123 million in 2013 and 2012, respectively. Corporate and Other activities include legal and consulting expenses related to our liability management program totaling $20 million (pretax) in the third quarter 2013 (and none in 2012). The change also reflected an asset impairment in 2012 and lower retirement benefit expense due to the pension plan actions in 2012.

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Table of Contents ConsolidatedFinancialResults - Nine Months Ended September 30, 2013 Comparedto Nine Months Ended September 30, 2012 See "Competitive Electric Segment - Financial Results" below for a discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities; operating costs; depreciation and amortization; SG&A expenses and franchise and revenue-based taxes.

See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges decreased $831 million to $1.915 billion in 2013. The decrease was driven by $903 million in unrealized mark-to-market net gains on interest rate swaps in 2013 compared to $12 million in net losses in 2012. See Note 8 to Financial Statements regarding nonperformance risk adjustment related to interest rate swaps. This change was partially offset by $80 million in higher interest expense driven by higher average borrowings.

See Note 13 to Financial Statements for details of interest expense and related charges.

Income tax benefit totaled $925 million and $879 million in 2013 and 2012, respectively. Excluding the $305 million in total income tax benefit recorded in the nine months ended September 30, 2013 related to resolution of IRS audit matters (see Note 13 to Financial Statements regarding uncertain tax positions), the effective tax rate was 34.2% and 34.7% in 2013 and 2012, respectively. The decrease in the effective tax rate was driven by a lower lignite depletion deduction, partially offset by lower accrued interest on uncertain tax positions and lower Texas margin tax expense.

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) increased $6 million to $255 million in 2013. Equity in earnings in 2013 included an $11 million favorable tax effect due to resolution of certain income tax positions at Oncor. The change in Oncor's earnings also reflected higher depreciation, lower interest income and higher operation and maintenance expenses, partially offset by higher revenues reflecting higher transmission rates and growth in points of delivery. See Note 2 to Financial Statements.

Net loss decreased $773 million to $635 million in 2013.

Net loss in the Competitive Electric segment decreased $551 million to $768 million.

• Earnings from the Regulated Delivery segment increased $6 million to $255 million as discussed above.

After-tax net expenses from Corporate and Other activities totaled $122 million and $338 million in 2013 and 2012, respectively. The change reflects

$226 million of income tax benefit related to resolution of IRS audits, which represents the portion applicable to Corporate and Other activities, recorded in the nine months ended September 30, 2013 as discussed in Note 13. Corporate and Other activities include legal and consulting expenses related to our liability management program totaling $22 million (pretax) in the nine months ended September 30, 2013 (and none in 2012). The activities also reflected $11 million (pretax) in lower retirement benefit expense due to the pension plan actions in 2012 (see Note 10 to Financial Statements).

Non-GAAP EarningsMeasures In communications with investors, we use a non-GAAP earnings measure that reflects adjustments to earnings reported in accordance with US GAAP in order to review and analyze underlying operating performance. These adjustments, which are generally noncash, consist of unrealized mark-to-market gains and losses, impairment charges, debt extinguishment gains and other charges, and credits or gains that are unusual or nonrecurring. All such items and related amounts are disclosed in our annual report 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 under certain debt securities covenants (see "Financial Condition Financial Covenants, Credit Rating Provisions and Cross Default Provisions" below).

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Table of Contents Competitive ElectricSegment FinancialResults Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Operating revenues $ 1,893 $ 1,752 $ 4,572 $ 4,358 Fuel, purchased power costs and delivery fees (852) (850) (2,175) (2,153)

Net gain (loss) from commodity hedging and trading activities 58 (3) 29 229 Operating costs (189) (201) (685) (636)

Depreciation and amortization (331) (328) (1,012) (992)

Selling, general and administrative expenses (175) (174) (502) (484)

Franchise and revenue-based taxes (18) (19) (51) (55)

Other income 1 2 7 12 Other deductions (35) (31) (39) (37)

Interest income 1 10 6 36 Interest expense and related charges (374) (785) (1,434) (2,303)

Loss before income taxes (21) (627) (1,284) (2,025)

Income tax benefit 39 234 516 706 Net income (loss) $18 $ (3A3) S (768) $ (1,319) 58

Table of Contents CompetitiveElectric Segment Sales Volume and CustomerCount Data Three Months Ended September 30, Nine Months Ended September 30, 2013 2012  % Change 2013 2012  % Change Sales volumes:

Retail electricity sales volumes - (GWh):

Residential 7,657 7,891 (3.0)% 17,737 18,682 (5.1)%

Small business (a) 1,635 1,757 (6.9)% 4,156 4,694 (11.5)%

Large business and other customers 2,679 2,846 (5.9)% 7,478 7,892 (5.2)%

Total retail electricity 11,971 12,494 (4.2)% 29,371 31,268 (6.1)%

Wholesale electricity sales volumes (b) 11,029 9,337 18.1% 28,566 24,085 18.6%

Total sales volumes 23,000 21,831 5.4% 57,937 55,353 4.7%

Average volume (kilowatt-hours) per residential customer (c) 5,010 5,019 (0.2)% 11,500 11,707 (1.8)%

Weather (North Texas average) -

percent of normal (d):

Cooling degree days 106.5% 105.5% 0.9 % 103.5% 113.7% (9.0)%

Heating degree days 104.1% 74.6% 39.5%

Customer counts:

Retail electricity customers (end of period, in thousands) (e):

Residential 1,524 1,566 (2.7)%

Small business (a) 176 176 Large business and other customers 17 17 Total retail electricity customers 1,717 1,759 (2.4)%

(a) Customers with demand of less than 1 MW annually.

(b) Includes net amounts related to sales and purchases of balancing energy in the ERCOT 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 from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). 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 of meters does not reflect the number of individual customers.

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Table of Contents Competitive Electric Segment Revenue and Commodity Hedging and Trading Activities Three Months Ended September 30, Nine Months Ended September 30, 2013 2012  % Change 2013 2012  % Change Operating revenues:

Retail electricity revenues:

Residential $ 998 $ 982 1.6% $ 2,310 $ 2,322 (0.5)%

Small business (a) 197 214 (7.9)% 523 583 (10.3)%

Large business and other customers 181 195 (7.2)% 517 549 (5.8)%

Total retail electricity revenues 1,376 1,391 (1.1)% 3,350 3,454 (3.0)%

Wholesale electricity revenues (b) (c) 449 291 54.3% 1,019 715 42.5%

Amortization of intangibles (d) 4 7 (42.9)% 15 15 Other operating revenues 64 63 1.6% 188 174 8.0%

Total operating revenues $ 1,893 $ 1,752 8.0% $ 4,572 $ 4,358 4.9%

Net gain (loss) from commodity hedging and trading activities:

Realized net gains on settled positions $ 228 $ 538 (57.6)% $ 739 $ 1,553 (52.4)%

Unrealized net losses (170) (541) (68.6)% (710) (1,324) (46.4)%

Total $ 58 $ (3) $ 29 $ 229 (a) Customers with demand of less than 1 MW annually.

(b) Upon settlement of physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, rather than contract price. As a result, these line item amounts include a noncash component that we deem "unrealized."

(The offsetting differences between contract and market prices are reported in net gain (loss) from commodity hedging and trading activities.) These amounts are as follows:

Three Months Ended September 30, Nine Months Ended September 30, 2013 2012 2013 2012 Reported in revenues $ - $ 4 $ (1)$ -

Reported in fuel and purchased power costs 7 i1 18 34 Net gain $ 7 $ 15 $ 17 $ 34 (c) Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.

(d) Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting from purchase accounting.

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Table of Contents Competitive Electric Segment Production,PurchasedPower and Delivery Cost Data Three Months Ended September 30, Nine Months Ended September 30, 2013 2012  % Change 2013 2012  % Change Fuel, purchased power costs and delivery fees ($ millions):

Fuel for nuclear facilities $ 45 $ 47 (4.3)% $ 128 $ 139 (7.9)%

Fuel for lignite/coal facilities 273 251 8.8% 674 606 11.2%

Total nuclear and lignite/coal facilities 318 298 6.7% 802 745 7.7%

Fuel for natural gas facilities and purchased power costs (a) 94 97 (3.1)% 219 248 (11.7)%

Amortization of intangibles (b) 9 14 (335.7)% 29 39 (25.6)%

Other costs 48 58 (1[7.2)% 146 147 (0.7)%

Fuel and purchased power costs 469 467 0.4% 1,196 1,179 1.4%

Delivery fees (c) 383 383 -- % 979 974 0.5%

Total 852 $ 850 0.2% $ 2,175 $ 2,153 1.0%

Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:

Nuclear facilities $ 8.50 $ 8.85 (4.0)% $ 8.47 $ 8.83 (4.1)%

Lignite/coal facilities (d) $ 19.25 $ 20.21 (4.8)% $ 19.95 $ 21.01 (5.0)%

Natural gas facilities and purchased power (e) $ 46.61 $ 44.98 3.6% $ 46.74 $ 45.26 3.3%

Delivery fees per MWh $ 31.88 $ 30.56 4.3% $ 33.19 $ 31.06 6.9%

Production and purchased power volumes (GWh):

Nuclear facilities 5,273 5,276 (0.1 )% 15,170 15,772 (3.8)%

Lignite/coal facilities (f) 16,474 15,179 8.5% 40,004 35,929 11.3%

Total nuclear and lignite/coal facilities 21,747 20,455 6.3 % 55,174 51,701 6.7%

Natural gas facilities 525 594 (11.6)% 767 1,117 (31.3)%

Purchased power (g) 728 782 (6.9)% 1,996 2,535 (21.3)%

Total energy supply volumes 23,000 21,831 5.4% 57,937 55,353 4.7%

Capacity factors:

Nuclear facilities 103.8% 103.9% (0.1)% 100.7% 104.3% (3.5)%

Lignite/coal facilities (f) 93.1% 85.7% 8.6% 76.2% 68.2% 11.7%

Total 95.5% 89.8% 6.3 % 81.6% 76.2% 7.1%

(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 contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.

(c) Includes delivery fee charges from Oncor.

(d) Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table on previous page.

(e) Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (d) immediately above.

(f) Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal-fueled units totaling 860 GWh and 2,510 GWh for the three months ended September 30, 2013 and 2012, respectively, and 7,790 GWh and 7,480 GWh for the nine months ended September 30, 2013 and 2012, respectively.

(g) Includes amounts related to line loss and power imbalances.

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Table of Contents Competitive ElectricSegment - FinancialResults - Three Months Ended September 30, 2013 Comparedto Three Months Ended September 30, 2012 Operating revenues increased $141 million, or 8%, to $1.893 billion in 2013.

Retail electricity revenues decreased $15 million, or 1%, to $1.376 billion reflecting a $58 million decline in sales volumes partially offset by $43 million in higher average prices. Sales volumes fell 4% reflecting declines in both the residential and business markets. Residential volumes reflected a 3%

decline in customer counts. Business markets volumes declined 6% reflecting competitive intensity and changes in customer mix. Weather did not have a significant effect on volume changes. Overall average retail pricing increased 3% driven by residential markets and due in part to higher delivery fees incurred and passed on to customers.

Wholesale electricity revenues increased $158 million, or 54%, to $449 million in 2013 reflecting a $105 million increase driven by higher average prices and a $53 million increase in sales volumes. Higher average prices reflected an increase in natural gas prices. Sales volumes increased 18% reflecting higher available generation due to lower economic backdown and lower volumes sold in our retail operations.

Fuel, purchased power costs and delivery fees increased $2 million to $852 million in 2013. Lignite/coal fuel costs increased $22 million driven by higher generation volumes. Natural gas fuel costs decreased $10 million reflecting lower generation volumes, partially offset by increased fuel prices, and other costs decreased $10 million primarily due to lower net charges from ERCOT.

A 9% increase in lignite/coal-fueled generation volumes was driven by less economic backdown in 2013 reflecting higher wholesale power prices.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $58 million in net gains and $3 million in net losses for the three months ended September 30, 2013 and 2012, respectively, and is largely reflective of the natural gas hedging program discussed above under "Significant Activities and Events and Items Influencing Future Performance - Natural Gas Hedging Program and Other Hedging Activities":

Three Months Ended September 30, 2013 Net Realized Net Unrealized Gains Losses Total Hedging positions $ 203 $ (146) $ 57 Trading positions 25 (24) 1 Total $ 228 $ (170) $ 58 Three Months Ended September 30, 2012 Net Realized Net Unrealized Gains Losses Total Hedging positions $ 494 $ (475) $ 19 Trading positions 44 (66) (22)

Total $ 538 $ (541) $ (3)

The decreases in net realized gains and unrealized losses reflected lower volumes and prices of maturing positions in the natural gas hedging program.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $7 million in net gains in 2013 and $15 million in net gains in 2012 (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).

Operating costs decreased $12 million, or 6%, to $189 million in 2013. The decrease included $8 million in lower nuclear generation maintenance costs reflecting activities performed for the fall refueling outage completed in the fourth quarter of 2012 (and no refueling outage in the fall of 2013) and $3 million in lower lease expense due to purchase of the interest in a trust holding certain combustion turbines (see Note 5 to Financial Statements).

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Table of Contents SG&A expenses increased $1 million to $175 million in 2013. The increase reflected $14 million in legal and consulting costs in the third quarter associated with our liability management program, compared to $4 million in the third quarter 2012. This increase is partially offset by $11 million in lower employee-related expenses reflecting lower benefit costs and incentive compensation expense.

Other deductions totaled $35 million in 2013 and $31 million in 2012. Other deductions in 2013 include a $27 million impairment of remaining assets from a cancelled generation development program. Other deductions in 2012 included a $24 million impairment of mineral interests.

Interest income decreased $9 million to $1 million in 2013. The decrease was driven by EFH Corp.'s settlement of the TCEH Demand Notes. See Note II to Financial Statements.

Interest expense and related charges decreased $411 million, or 52%, to $374 million in 2013. The decrease was driven by $413 million in unrealized mark-to-market net gains on interest rate swaps in 2013 compared to $20 million in net losses in 2012. See Note 8 to Financial Statements regarding nonperformance risk adjustment related to interest rate swaps. This change was partially offset by $19 million in higher amortization of debt issuance costs and discounts reflecting the January 2013 amendment and extension of the TCEH Revolving Credit Facility.

Income tax benefit totaled $39 million and $234 million on pretax losses in 2013 and 2012, respectively. Excluding the $38 million in total income tax benefit recorded in 2013 related to resolution of IRS audit matters (see Note 13 to Financial Statements regarding uncertain tax positions), the effective tax rate was 4.8% and 37.3% in 2013 and 2012, respectively. The decrease in the effective tax rate reflected a decrease in the lignite depletion deduction, partially offset by lower Texas margin tax expense and lower nondeductible interest on debt.

After-tax net income for the segment was $18 million in 2013 compared to an after-tax net loss of $393 million in 2012. The change was driven by unrealized gains on interest rate swaps compared to unrealized losses in 2012, and lower unrealized losses on commodity hedging activities.

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Table of Contents Competitive ElectricSegment-- FinancialResults- Nine Months Ended September 30, 2013 Compared to Nine Months EndedSeptember 30, 2012 Operating revenues increased $214 million, or 5%, to $4.572 billion in 2013.

Retail electricity revenues decreased $104 million, or 3%, to $3.350 billion reflecting a $210 million decline in sales volumes partially offset by $106 million in higher average prices. Sales volumes fell 6% reflecting declines in both the residential and business markets. Residential volumes declined 5%

reflecting a 3% decrease in customer counts and milder weather in the second quarter. Business market volumes declined 8% reflecting competitive intensity and changes in customer mix. Overall average retail pricing increased 3% driven by residential markets and due in part to higher delivery fees incurred and passed on to customers.

Wholesale electricity revenues increased $304 million, or 43%, to $1.019 billion in 2013 reflecting a $171 million increase due to higher average prices and a $133 million increase in sales volumes. Higher average prices reflected an increase in natural gas prices. Sales volumes increased 19% reflecting higher generation volumes and lower volumes sold in our retail operations.

Fuel, purchased power costs and delivery fees increased $22 million, or 1%, to $2.175 billion in 2013. Lignite/coal fuiel costs increased $68 million driven by higher generation volumes. Natural gas fuel costs decreased $27 million reflecting decreases in generation volumes, partially offset by increased fuel prices. Nuclear fuel costs decreased $11 million reflecting a decrease in generation volumes and lower prices.

An 11% increase in lignite/coal-fueled generation volumes was driven by fewer unplanned and planned outage days, while nuclear-fueled generation volumes decreased 4% reflecting a planned refueling outage in the spring of 2013.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $29 million and $229 million in net gains for the nine months ended September 30, 2013 and 2012, respectively, and is largely reflective of the natural gas hedging program discussed above under "Significant Activities and Events and Items Influencing Future Performance - Natural Gas Hedging Program and Other Hedging Activities."

Nine Months Ended September 30,2013 Net Realized Net Unrealized Gains (Losses) Losses Total Hedging positions $ 751 $ (709) $ 42 Trading positions (12) (1) (13)

Total $ 739 $ (710) $ 29 Nine Months Ended September 30, 2012 Net Realized Net Unrealized Gains Losses Total Hedging positions $ 1,504 $ (1,310) $ 194 Trading positions 49 (14) 35 Total $ 1,553 $ (1,324) $ 229 The decreases in net realized gains and unrealized losses reflected lower volumes and prices of maturing positions in the natural gas hedging program.

Net unrealized losses in 2012 were mitigated by the effect of unrealized gains on unsettled positions due to decreases in forward natural gas prices.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $17 million in net gains in 2013 and $34 million in net gains in 2012 (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).

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Table of Contents Operating costs increased $49 million, or 8%, to $685 million in 2013. The increase reflected $42 million in higher nuclear generation outage costs driven by the planned refueling outage in the spring of 2013. The balance of the increase was driven by higher maintenance costs associated with lignite/coal-fueled generation unit outages of $18 million, reflecting timing and scope of the activities, partially offset by $6 million in lower lease expense due to purchase of the interest in a trust holding certain combustion turbines and $6 million in lower information technology project costs.

Depreciation and amortization increased $20 million, or 2%, to $1.012 billion in 2013. The increase reflected retirement of coal plant assets and capital investment.

SG&A expenses increased $18 million, or 4%, to $502 million in 2013. The increase reflected $48 million in legal and consulting costs in the nine months ending September 30, 2013 associated with our liability management program, compared to $4 million in 2012. This increase is partially offset by

$21 million lower employee-related costs primarily reflecting lower incentive compensation expense.

Other deductions totaled $39 million in 2013 and $37 million in 2012. Other deductions in 2013 include a $27 million impairment of remaining assets from a cancelled generation development program. Other deductions in 2012 included a $24 million impairment of mineral interests.

Interest income decreased $30 million to $6 million in 2013. The decrease was driven by EFH Corp.'s settlement of the TCEH Demand Notes. See Note 11 to Financial Statements.

Interest expense and related charges decreased $869 million, or 38%, to $1.434 billion in 2013. The decrease was driven by $899 million in unrealized mark-to-market net gains on interest rate swaps in 2013 compared to $16 million in net losses in 2012. See Note 8 to Financial Statements regarding nonperformance risk adjustment related to interest rate swaps. This change was partially offset by $59 million in higher amortization of debt issuance costs and discounts reflecting the January 2013 amendment and extension of the TCEH Revolving Credit Facility.

Income tax benefit totaled $516 million and $706 million on pretax losses in 2013 and 2012, respectively. Excluding the $78 million in total income tax benefit recorded in the nine months ended September 30, 2013 related to resolution of IRS audit matters (see Note 13 to Financial Statements regarding uncertain tax positions), the effective tax rate was 34.1% and 34.9% in 2013 and 2012, respectively. The decrease in the effective tax rate reflected a decrease in the lignite depletion deduction, partially offset by lower Texas margin tax expense and lower nondeductible interest on debt.

After-tax loss for the segment decreased $551 million to $768 million in 2013 driven by unrealized mark-to-market net gains on interest rate swaps, compared to net losses in 2012, and the income tax benefit related to audit resolutions, partially offset by lower net gains from commodity hedging activities.

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Table of Contents Competitive ElectricSegment - Energy-Related Commodity Contractsand Mark-to-Market Activities The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2013 and 2012. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $695 million and $1.290 billion in unrealized net losses in 2013 and 2012, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. The portfolio consists primarily of economic hedges but also includes proprietary trading positions.

Nine Months Ended September 30, 2013 2012 Commodity contract net asset at beginning of period $ 1,664 $ 3,190 Settlements of positions (a) (749) (1,420)

Changes in fair value of positions in the portfolio (b) 54 130 Other activity (c) (47) (36)

Commodity contract net asset at end of period $ 922 $ 1,864 (a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related 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 the value of positions in the natural gas hedging program (see discussion above under "Significant Activities and Events and Items Influencing Future Performance - Natural Gas Hedging Program and Other Hedging Activities"), as well as changes in value of other hedging positions. Excludes changes in fair value in the month the position settled as well as 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 or payment of cash or other consideration, generally related to options purchased/sold.

Maturity Table - The following table presents the net commodity contract asset arising from recognition of fair values at September 30, 2013, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

Maturity dates of unrealized commodity contract net asset at September 30, 2013 Less than Source of fair value 1 year 1-3 years Total Prices actively quoted $ 20 $ (9) $ 11 Prices provided by other external sources 764 151 915 Prices based on models (9) 5 (4)

Total $ 775 $ 147 $ 922 Percentage of total fair value 84% 16% 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 which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT's North Hub that are deemed active markets extend through 2015 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 options valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 8 to Financial Statements for fair value disclosures and discussion of fair value measurements.

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Table of Contents FINANCIAL CONDITION Cash Flows - Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012 - Cash used in operating activities totaled $269 million in 2013 compared to cash provided by operating activities of $98 million in 2012. The change of $367 million reflected a decrease of $703 million in net realized gains from the natural gas hedging program. Favorable changes in margin deposits totaling $124 million and $105 million in higher net distributions (including income tax payments) received from Oncor Holdings were largely offset by higher interest payments. Favorable net changes in various working capital and other asset and liability accounts were due in large part to timing of payments.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $130 million and $146 million for the nine months ended September 30, 2013 and 2012, respectively. The difference represented 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 line items including operating revenues and fuel and purchased power costs and delivery fees.

Cash used in financing activities totaled $15 million in 2013 and cash provided by financing activities totaled $1.463 billion in 2012. Activity in 2012 reflected the issuance of $2.0 billion of EFIH senior notes, the proceeds from which were primarily used to repay $950 million in borrowings under the TCEH Revolving Credit Facility and fund a $680 million escrow account to repay the balance of the TCEH Demand Notes (see Note II to Financial Statements).

Activity in 2012 also included a $159 million payment to settle transition bond reimbursement agreements with Oncor (see Note 11 to Financial Statements).

See Note 5 to Financial Statements for further detail of short-term borrowings and long-term debt.

Cash provided by investing activities totaled $187 million in 2013 and cash used in investing activities totaled $1.275 billion in 2012. Amounts provided in 2013 reflected the use by EFH Corp. of $680 million of cash previously in escrow (reported as restricted cash at December 31, 2012) to repay the balance of the TCEH Demand Notes (see Note II to Financial Statements). Capital expenditures (excluding nuclear fuel purchases) decreased $154 million to

$372 million in 2013 reflecting decreased environmental-related spending, partially offset by increased spending on lignite mine development and generation plant projects. Nuclear fuel purchases decreased $96 million to $59 million due to timing of refueling cycles. Cash used in investing activities in 2013 also included $40 million used to acquire the owner participant interest in a trust established to lease six natural gas-fired combustion turbines to TCEH. See Note 5 to Financial Statements and discussion below under "Debt Financing Activity" regarding the debt obligation of the trust. Cash used in 2012 included a

$680 million increase in restricted cash related to the issuance of EFIH senior notes discussed above.

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Table of Contents Debt Activity - Activities related to short-term borrowings and long-term debt during the nine months ended September 30, 2013 are as follows (all amounts presented are principal, and settlements include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

Borrowings Settlements TCEH (a) $ 385 $ (90)

EFCH -- (4)

EFIH (b) 1,474 (139)

EFH Corp. (c) - (1,273)

Total long-term 1,859 (1,506)

Total short-term - TCEH (d) 90 -

Total $ 1,949 S (1,506)

(a) Borrowings represent noncash principal increases of TCEH Term Loan Facilities as fees in consideration for the extension of $645 million of commitments under the TCEH Revolving Credit Facility, as well as debt assumed of $45 million in connection with the purchase of the interest in a trust holding certain combustion turbines as discussed above. Settlements represent $82 million of payments of principal at scheduled maturity or mandatory tender dates and $8 million of payments of capital lease liabilities.

(b) Borrowings represent $1.391 billion of EFIH debt issued in exchanges for EFH Corp. and EFIH debt in January 2013 and $83 million of noncash principal increases of EFIH Toggle Notes issued in June 2013 in payment of accrued interest as discussed below under "EFIH Toggle Notes Interest Election." Settlements represent noncash retirements related to January 2013 debt exchanges.

(c) Settlements include $1.266 billion of noncash retirements related to January 2013 debt exchanges.

(d) Short-term amount represents net borrowings under the accounts receivable securitization program (see Note 4 to Financial Statements).

See Note 5 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 nine months ended September 30, 2013:

Available Liquidity September 30, 2013 December 31, 2012 Change Cash and cash equivalents - EFH Corp. (parent entity) $ 225 $ 314 $ (89)

Cash and cash equivalents - EFIH (a) 329 1,104 (775)

Cash and cash equivalents - TCEH 1,262 1,175 87 TCEH Letter of Credit Facility 171 183 (12)

Total liquidity $ 1,987 $ 2,776 $ (789)

(a) December 31, 2012 includes $680 million in cash held in escrow that was used in January 2013 to settle the TCEH Demand Notes.

The decrease in available liquidity of $789 million in the nine months ended September 30, 2013 was driven by $431 million in cash used for capital expenditures, including nuclear fuel purchases, and $269 million in cash used in operating activities. See discussion of cash flows above. Based on forward wholesale power prices in ERCOT, which are subject to the effects of changing market conditions, TCEH may not have sufficient liquidity, absent any financing transactions, to meet its obligations within the next twelve months.

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Table of Contents Debt Capacity - We believe that EFH Corp., EFIH and TCEH are permitted under applicable debt agreements to issue additional debt (in each case, subject to certain exceptions and conditions set forth in our applicable debt documents) as follows:

• EFH Corp. and EFIH collectively are permitted to issue up to approximately $250 million of additional aggregate principal amount of debt secured by EFIH's equity interest in Oncor Holdings on a second-priority basis;

• EFIH is permitted under its debt agreements to issue up to approximately $375 million of additional principal amount of senior unsecured debt (subject to certain exceptions and conditions set forth in its debt agreements). Such unsecured debt 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 by substantially all of the assets of TCEH 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

• TCEH is permitted to issue an unlimited amount of additional first-priority debt in order to refinance the first-priority debt outstanding under the TCEH Senior Secured Facilities.

Investment Capacity - We believe that EFIH and TCEH are permitted under applicable debt agreements to make "investments" that could result in, among other things, additional liquidity through financings secured by existing assets (in each case, subject to certain exceptions and conditions set forth in the applicable debt documents) as follows:

• EFIH is permitted under the terms of the indentures governing its debt to make investments of up to approximately $435 million, of which approximately $210 million is for investment in similar businesses and approximately $225 million is a general investment basket, and

• TCEH is permitted under the TCEH Senior Secured Facilities to make additional investments of approximately $1.4 billion, of which approximately

$915 million may include investments in unrestricted subsidiaries and joint ventures (as defined). The balance is a general restricted payment basket that limits the aggregate amount of investments and dividends and redemptions of certain debt.

These debt capacity and investment capacity amounts are estimates based on our current interpretation of the covenants set forth in our debt agreements and do not take into account exceptions in the debt agreements that may allow for the incurrence of (i) additional secured or unsecured debt, including, but not limited to, acquisition debt, refinancing debt, capital leases and hedging obligations and (ii) additional investments, including but not limited to, permitted investments. Moreover, such amounts could 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 included in 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 and the investments we are permitted to make under our debt agreements could be materially different than the amounts provided above.

Pension and OPEBPlan Funding - See Note 10 to Financial Statements.

EFIHToggle Notes InterestElection - EFIH has the option every six months at its discretion, ending with the interest payment due June 2016, to use the payment-in-kind (PIK) feature of its toggle notes ($1.393 billion aggregate principal amount issued in December 2012 and January 2013) in lieu of making cash interest payments. Once EFH makes a PIK election, the election is valid for each succeeding interest payment period until it revokes the applicable election. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.

EFIH made its June 2013 interest payment and expects to make its December 2013 interest payment on the EFIH Toggle Notes by using the PIK feature of those notes. During the applicable PIK interest periods, the interest rate on these notes is increased from 11.25% to 12.25%. As a result of the PIK election, EFIH increased the aggregate principal amount of the notes by $83 million in June 2013 and is expected to issue an additional $90 million in December 2013.

See Note 5 to Financial Statements for further discussion of the EFIH Toggle Notes.

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Table of Contents Liquidity Effects of Commodity Hedging and TradingActivities - Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral posting obligations. At September 30, 2013, approximately 95% of the natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral posting requirements for those hedging transactions. See Note 5 to Financial Statements for more information about the TCEH Senior Secured Facilities.

Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. At September 30, 2013, essentially all cash collateral held was unrestricted. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.

At September 30, 2013, an insignificant amount of positions related to the natural gas hedging program were not directly secured on an asset-lien basis and thus are subject to cash collateral or letter of credit posting requirements if natural gas prices increase.

At September 30, 2013, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• For exchange cleared transactions (including initial margin), $4 million in cash has been posted with counterparties, net of $16 million in cash received, as compared to $69 million posted at December 31, 2012;

• For over-the-counter and other non-exchange cleared transactions, $336 million in cash has been received from counterparties, net of $1 million in cash posted, as compared to $598 million received, net of $2 million in cash posted, at December 31, 2012;

• $353 million in letters of credit have been posted with counterparties, as compared to $376 million posted at December 31, 2012, and

• $30 million in letters of credit have been received from counterparties, as compared to $22 million received at December 31, 2012.

Income Tax Matters - EFH Corp. files a US federal income tax return that includes the results of EFCH, EFFH, Oncor Holdings and TCEH. EFH Corp. is a corporate member of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH is classified as a disregarded entity for US federal income tax purposes. Prior to the restructuring transaction in April 2013 discussed below, EFCH was a corporate member of the group.

Oncor is a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group. Pursuant to applicable US Treasury regulations and published guidance of the IRS, 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, EFUH, and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, which provides, among other things, that any corporate member or disregarded entity in the group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. EFH Corp., Oncor Holdings and Oncor are parties 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 of tax liability such entity would have owed if it filed a separate corporate tax return.

In April 2013, we received a private letter ruling from the IRS in which the IRS ruled that upon the consummation of certain internal corporate transactions (the Transactions) involving EFH Corp. and EFCH, an excess loss account (ELA) and a deferred intercompany gain (DIG), described immediately below, would be eliminated without causing the recognition of tax gain or loss. On April 15, 2013, EFH Corp. and EFCH completed the Transactions, resulting in the elimination of the ELA and the DIG.

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Table of Contents An ELA and a DIG were reflected in the tax basis of the EFCH stock held by EFH Corp. The ELA, totaling approximately $19 billion, was created in connection with financing transactions related to the Merger. The DIG, totaling approximately $4 billion, was created as a result of an internal corporate reorganization prior to the Merger. The financing transactions and internal corporate reorganization that created the ELA and DIG involved TCEH and its assets, but not EFIH or Oncor Holdings. The difference between EFH Corp.'s tax basis in the stock of EFCH and the amount of the stock investment for financial reporting purposes represented an outside basis difference. Because we had tax strategies available to us that we believed would avoid triggering income tax payments upon a transaction involving our investment in EFCH, we did not record deferred income tax liabilities with respect to this outside basis difference.

In consummating the Transactions, (i) EFH Corp. contributed all of the stock of EFCH to a newly formed wholly owned subsidiary, EFH2 Corp.

(EFH2) (a Texas corporation), (ii) EFCH was converted from a Texas corporation into a Delaware limited liability company and was renamed Energy Future Competitive Holdings Company LLC and (iii) EFH Corp. merged with and into EFH2, with EFH2 continuing as the surviving corporation. In connection with the Transactions, EFH2 was renamed Energy Future Holdings Corp.

Immediately after the consummation of the Transactions, each of EFH2 and EFCH had the same management, assets, businesses and operations as EFH Corp. and EFCH had, respectively, immediately prior to the consummation of the Transactions. 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 and EFH 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 related to the Texas margin tax are expected to total approximately $50 million, and no payments or refunds of federal income taxes are expected. Income tax payments (all Texas margin tax) totaled $65 million and $67 million for the nine months ended September 30, 2013 and 2012, respectively.

See Note 13 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.

Accounts Receivable SecuritizationProgram - See Note 4 to Financial Statements for discussion of the Accounts Receivable Securitization Program. On October 29, 2013, we terminated the Accounts Receivable Securitization Program and repaid all outstanding obligations under the program.

Distributionsof Earningsfrom Oncor Holdings - Oncor Holdings' distributions of earnings to us totaled $148 million and $100 million for the nine months ended September 30, 2013 and 2012, respectively. Oncor Holdings' board of directors also declared a distribution to us totaling $65 million payable on October 31, 2013. See Note 2 to Financial Statements for discussion of limitations on amounts Oncor can distribute to its members.

Oncor has credit risk exposure to trade accounts receivable from TXU Energy, which relate to delivery services provided by Oncor to TXU Energy.

This exposure totals $154 million at September 30, 2013 and represents $162 million in accounts receivable, including $53 million in unbilled accounts, net of $8 million secured by letters of credit posted by TCEH. Because Oncor had committed to the PUCT, in connection with the Merger, that it would not seek regulatory rate recovery for credit losses associated with affiliated REPs, Oncor's earnings would be reduced by the amount (after-tax) of any default by TXU Energy.

FinancialCovenants, Credit Rating Provisionsand Cross Default Provisions - The terms of the TCEH Senior Secured Facilities and the accounts receivable securitization program (see Note 4 to Financial Statements) contain an identical maintenance covenant with respect to leverage ratio. At September 30, 2013, we were in compliance with such covenants.

Covenants andRestrictions under FinancingArrangements - The TCEH Senior Secured Facilities and the indentures governing substantially all of the debt EFH Corp.'s subsidiaries (excluding Oncor) have issued in connection with, and subsequent to, the Merger contain covenants that could have a material impact on our liquidity and operations. In particular, the TCEH Senior Secured Facilities include a requirement to timely deliver to the lenders copies of audited annual financial statements that are not qualified as to the status of TCEH and its subsidiaries as a going concern. We need to resolve our liquidity needs, including refinancing the $3.8 billion of maturities due in October 2014 under the TCEH Senior Secured Facilities, in order to satisfy this covenant (or obtain a waiver of the covenant) with respect to our audited financial statements for the year ended December 31, 2013. See Note I to Financial Statements.

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Table of Contents Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. 10.875% Notes and EFH Corp.

Toggle Notes) for the twelve months ended September 30, 2013 totaled $4.622 billion for EFH Corp. See Exhibits 99(b), 99(c) and 99(d) for a reconciliation of net income (loss) to Adjusted EBITDA for EFH Corp., TCEH and EFIH, respectively, for the nine and twelve months ended September 30, 2013 and 2012.

The table below summarizes TCEH's secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and the TCEH accounts receivable securitization program and other EFH Corp., EFTH and TCEH financial ratios that are applicable under certain thresholds in 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, the EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes and the EFIH Notes. The debt incurrence and restricted payments/limitations on investments covenants thresholds presented below represent levels that must be met in order for EFH Corp., EFIH or TCEH to incur certain debt or make certain restricted payments and/or investments. See "Debt Capacity" above for discussion regarding additional debt EFH Corp., EFIH and TCEH are permitted to issue under applicable debt agreements. TCEH is in compliance with its maintenance covenants. In January 2013, in accordance with amendments to the terms of the EFH Corp. 9.75% Notes and EFH Corp. 10% Notes and their governing indentures, restrictive covenants under those notes were removed (see Note 5 to Financial Statements).

September 30, December 31, Threshold Level at 2013 2012 September 30,2013 Maintenance Covenant:

TCEH Senior Secured Facilities and TCEH's accounts receivable securitization program:

Secured debt to Adjusted EBITDA ratio 7.38 to 1.00 5.88 to 1.00 Must not exceed 8.00 to 1.00 (a)

Debt Incurrence Thresholds:

EFIH Notes:

EFIH fixed charge coverage ratio (b) 0.3 to 1.0 0.3 to 1.0 At least 2.0 to 1.0 TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes:

TCEH fixed charge coverage ratio 1.0 to 1.0 1.2 to 1.0 At least 2.0 to 1.0 TCEH Senior Secured Facilities:

TCEH fixed charge coverage ratio 1.0 to 1.0 1.2 to 1.0 At least 2.0 to 1.0 Restricted Payments/Limitations on Investments Thresholds:

EFH Corp. 10.875% Notes and Toggle Notes:

General restrictions (Sponsor Group payments):

EFH Corp. leverage ratio 12.3 to 1.0 10.1 to 1.0 Equal to or less than 7.0 to 1.0 EFIH Notes:

General restrictions (non-EFH Corp. payments):

EFIH fixed charge coverage ratio (b)(c) 1.8 to 1.0 2.1 to 1.0 At least 2.0 to 1.0 General restrictions (EFH Corp. payments):

EFIH fixed charge coverage ratio (b) (c) 0.3 to 1.0 0.3 to 1.0 At least 2.0 to 1.0 EFIH leverage ratio 7.7 to 1.0 7.0 to 1.0 Equal to or less than 6.0 to 1.0 TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes:

TCEH fixed charge coverage ratio 1.0 to 1.0 1.2 to 1.0 At least 2.0 to 1.0 TCEH Senior Secured Facilities:

Payments to Sponsor Group:

TCEH total debt to Adjusted EBITDA ratio 10.6 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 ($906 million excluded at September 30, 2013) principal amount of TCEH senior secured first lien notes whose proceeds are used to prepay term loans or deposit letter of credit loans under the TCEH Senior Secured Facilities.

(b) Calculations exclude interest income on the EFH Corp. 10.875% Notes and Toggle Notes that EFIH distributed as a dividend to EFH Corp. in January 2013 (see Note 5 to Financial Statements).

(c) The EFIH fixed charge coverage ratio for paying dividends or repurchasing or making distributions in respect of capital stock (EFH Corp. payments) excludes the results of Oncor Holdings and its subsidiaries. The EFIH fixed charge coverage ratio for making investments (non-EFH Corp. payments) includes the results of Oncor Holdings and its subsidiaries.

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Table of Contents MaterialCredit Rating Covenants and Creditworthiness Effects on Liquidit, - As a result of TCEH's non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, at September 30, 2013, counterparties to those contracts could have required TCEH to post up to an aggregate of $12 million in additional collateral. This amount largely represents the unfavorable market terms of these contracts at September 30, 2013; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas are required to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. At September 30, 2013, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $21 million, with $10 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at September 30, 2013, TCEH posted letters of credit in the amount of $65 million, which are subject to adjustments.

The RCT 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 RCT, TCEH may be required to post cash, letter of credit or other tangible assets as collateral 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 accepted by the RCT and the level of mining reclamation obligations. The estimated posting amount relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts. As disclosed in Note 13 to Financial Statements, our recorded mining reclamation liability totaled $86 million at September 30, 2013, which represents the present value of estimated costs to complete reclamation of land mined or being mined.

ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $140 million at September 30, 2013 (which is subject to daily adjustments based on settlement activity with ERCOT).

Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit 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 ratings below investment grade.

Other arrangements of EFH Corp. and its subsidiaries, including Oncor's credit facility and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

Material Cross Default/AccelerationProvisions - Certain of our financing arrangements contain provisions that could result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that 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 in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.616 billion at September 30, 2013, excluding $19 million held by EFH Corp.) under such facilities.

The indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and the TCEH Senior Secured Second Lien Notes contain a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under 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 Secured Second Lien Notes.

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Table oftContents Under the terms of a TCEH rail car lease, which has $39 million in remaining lease payments at September 30, 2013 and terminates in 2017, if TCEH fails 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 accelerate the payment of any remaining lease payments due under the lease.

Under the terms of another TCEH rail car lease, which has $42 million in remaining lease payments at September 30, 2013 and terminates in 2028, if payment obligations of TCEH in excess of $200 million in the aggregate to third-party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

The indentures governing the EFIH Notes contain a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFIH or any of its restricted subsidiaries or of any debt that EFIH guarantees in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFIH Notes.

We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds stated in the contracts, which vary. The subsidiaries whose default would trigger cross default vary depending on the contract.

Each of TCEH's natural gas hedging agreements and interest rate swap agreements that are secured with a lien on its assets on 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 ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge or interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to have a significant effect on liquidity.

Guarantees- See Note 6 to Financial Statements for discussion of guarantees.

OFF-BALANCE SHEET ARRANGEMENTS See Notes 2 and 6 to Financial Statements regarding VIEs and guarantees, respectively.

COMMITMENTS AND CONTINGENCIES See Note 6 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS There have been no recently issued accounting standards effective after September 30, 2013 that are expected to materially impact our financial statements.

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Table of Contents Item3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwise indicated.

Market risk is the risk that in the ordinary course of business we may experience a loss in value as a result of changes in market conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. Our exposure to market risk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge conmnodity prices.

Risk Oversight We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy 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 groups that 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 from changes in market conditions and include, but are not limited to, position review, Value at Risk (VaR) methodologies and stress test 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 validation and reporting, and 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 the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits, and evaluates the risks inherent in our businesses.

Commodity PriceRisk The competitive business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. We actively manage the portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully 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 with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

Natural Gas Hedging Program - See "Significant Activities and Events and Items Influencing Future Performance" above and Note 9 to Financial Statements for a description of the program, including potential effects on reported results.

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Table of Contents VaR Methodology-- A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.

A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of(i) an assumed confidence level; (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data.

Trading VaR- This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five days.

September 30, 2013 December 31, 2012 Month-end average Trading VaR: $ 2 $ 7 Month-end high Trading VaR: $ 4 $ 12 Month-end low Trading VaR: $ 1 $ 1 VaR for Energy-Related ContractsSubject to Mark-to-Market(MtM) Accounting - This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.

September 30, 2013 December 31, 2012 Month-end average MtM VaR: $ 72 $ 132 Month-end high MtM VaR: $ 97 $ 206 Month-end low MtM VaR: $ 43 $ 96 Earningsat 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), based on a 95% confidence level and an assumed holding period of five to 60 days.

September 30, 2013 December 31, 2012 Month-end average EaR: $ 29 $ 109 Month-end high EaR: $ 37 $ 161 Month-end low EaR: $ 23 $ 77 The 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 hedging program due to maturities and lower market volatility.

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Table of Contents Interest Rate Risk At September 30, 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 $18 million, taking into account the interest rate swaps discussed in Note 5 to Financial Statements.

Credit Risk Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty's financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties' financial strength, measurement of current and potential future exposures and contract 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 to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Further, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. This process 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) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $1.236 billion at September 30, 2013. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at September 30, 2013 include $592 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $60 million. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, 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 trading activities, 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 marketing companies. At September 30, 2013, the exposure to credit risk from these counterparties totaled $644 million taking into account the netting provisions of the master agreements described above but before taking into account $369 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $275 million increased $20 million in the nine months ended September 30, 2013.

Of this $275 million net exposure, essentially all is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies' published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.

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Table of Contents The following table presents the distribution of credit exposure at September 30, 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 represents wholesale trade accounts receivable and net asset positions in the balance sheet arising from hedging and trading activities after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 9 to Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

Exposure Before Credit Credit Net Collateral Collateral Exposure Investment grade $ 626 $ 366 $ 260 Noninvestment grade 18 3 15 Totals $ 644 $ 369 $ 275 Investment grade 97.2% 94.5%

Noninvestment grade 2.8% 5.5%

In addition to the exposures in the table above, contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable 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 two counterparties, which represented 18% and 15% of the $275 million net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, each of which is rated as investment grade, and the importance of our business relationship with the counterparties.

With respect to credit risk related to the natural gas hedging program, all of the transaction volumes are with counterparties that have an investment grade credit rating. However, there is current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program, with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us.

While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.

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Table of Contents FORWARD-LOOKING STATEMENTS This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including such matters as activities under our liability management program, financial or operational projections, capital allocation, future capital expenditures, business strategy, 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 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 are based on reasonable assumptions, any such forward-looking statement involves uncertainties and 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 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 Cormmission, the NERC, the Texas Reliability Entity, Inc., the PUCT, the RCT, 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 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; o operations of mines; o self-bonding requirements;

° 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; o changes in tax laws and policies; o changes in and compliance with environmental and safety laws and policies, including the CSAPR, MATS, and greenhouse gas and other climate change initiatives, and o 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 heat rates and interest rates;

• weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, 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 international credit markets; 79

Table of Contents

• the willingness of our lenders to extend the maturities of our debt instruments and the terms and conditions of any such extensions;

• access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds 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, reach agreement with our creditors on the terms of any change in our capital structure, or otherwise address our significant interest payments and debt maturities, including through the potential exchange of debt securities for debt or equity securities or potential waiver of any covenants contained in our debt agreements;

• any defaults under certain of our financing arrangements that could trigger cross default or cross acceleration provisions under 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 the potential 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 under ERISA; 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 resulting from 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 oour 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, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict 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 unduly rely on such forward-looking statements.

INDUSTRY AND MARKET INFORMATION The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT, the PUCT and NYMEX. We did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information.

Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not 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 we make no assurances that the predictions contained therein are accurate.

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Table of Contents Item 4. CONTROLS AND PROCEDURES An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect at the end of the current period included in this quarterly report. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this quarterly report, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION Item 1. LEGAL PROCEEDINGS Reference is made to the discussion in Note 6 to Financial Statements regarding legal proceedings.

Item IA. RISK FACTORS In addition to the other information set forth in this report, you should carefully consider the risk factors discussed under 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 DISCLOSURES 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 Safety and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects US mines, including ours, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 9 5(a) to this quarterly report on Form I0-Q.

Item 5.. OTHER INFORMATION Accounts Receivable Securitization Program Termination On October 29, 2013, EFH Corp. and its subsidiaries, TCEH, TXU Energy and TXU Energy Receivables Company LLC (TXU Energy Receivables Company) terminated the TXU Energy accounts receivable securitization program (the program). For a description of the Accounts Receivable Securitization Program, see Note 7 to the 2012 Form 10-K and Note 4 to Financial Statements.

In connection with the termination of the program, (i) TXU Energy repurchased $491 million in accounts receivable from TXU Energy Receivables Company for an aggregate purchase price of $474 million, which constituted all of the accounts receivable outstanding and previously sold by TXU Energy to TXU Energy Receivables Company under the program pursuant to the Trade Receivables Sale Agreement, dated as of November 30, 2012, among TXU Energy, TXU Energy Receivables Company and EFH Corp. (Trade Receivables Sale Agreement), (ii) TXU Energy Receivables Company paid TXU Energy

$11 million, constituting repayment in full of the outstanding obligations under the subordinated note previously issued by TXU Energy Receivables Company to TXU Energy as partial consideration for the accounts receivable sold to TXU Energy Receivables Company pursuant to the Trade Receivables Sale Agreement, and (iii) TXU Energy Receivables Company paid Citibank, N.A. (Citibank), as Group Managing Agent under the First Lien Trade Receivables Financing Agreement, dated as of November 30, 2012, among TXU Energy Receivables Company, TXU Energy, certain Investors party thereto, and Citibank (Trade Receivables Financing Agreement), an amount equal to $126 million, constituting all of TXU Energy Receivables Company's outstanding obligations under the Trade Receivables Financing Agreement. Upon the payment of such amounts, the Trade Receivables Sale Agreement and the Trade Receivables Financing Agreement were terminated. Citibank also serves as the administrative agent and collateral agent under TCEH's Senior Secured Credit Facilities and collateral agent under the TCEH Senior Secured Notes.

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Table of Contents Election of EFH Corp. Board of Directors On October 30, 2013, pursuant to a unanimous written consent of the EFH Corp. shareholders executed in lieu of an annual meeting of shareholders, the following directors were reelected to the board of directors of EFH Corp. to serve until the next annual meeting of the shareholders or until their respective successors are duly elected and qualify:

Arcilia C. Acosta David Bonderman Donald L. Evans Thomas D. Ferguson Brandon A. Freiman Scott Lebovitz Marc S. Lipschultz Michael MacDougall Kenneth Pontarelli William K. Reilly Jonathan D. Smidt Billie I. Williamson John F. Young Kneeland Youngblood 82

Table of Contents Item 6. EXHIBITS (a) Exhibits filed or furnished as part of Part H are:

As Exhibits Previously Filed With File Number* Exhibit (3(i)) Articles of Incorporation 3(a) 1-12833 3(a) - Restated Certificate of Formation of Energy Future Holdings Corp.

Form I0-Q (Quarter ended March 31, 2013) (filed May 2, 2013)

(3(ii)) By-laws 3(b) 1-12833 3(b) - Amended and Restated Bylaws of Energy Future Holdings Corp.

Form I0-Q (Quarter ended March 3 I, 2013) (filed May 2, 2013)

(31) Rule 13a - 14(a)/15d-14(a) Certifications 31(a) - Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b) - Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32) Section 1350 Certifications 32(a) - Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., 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 of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(95) Mine Safety Disclosures 95(a) - Mine Safety Disclosures (99) Additional Exhibits 99(a) - Condensed Statement of Consolidated Income - Twelve Months Ended September 30, 2013.

99(b) - Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2013 and 2012.

99(c) - Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2013 and 2012.

99(d) - Energy Future Intermediate Holding Company LLC Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2013 and 2012.

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Table of Contents As Exhibits Previously Filed With File Number* Exhibit XBRL Data Files l01.1NS - XBRL Instance Document 101 .SCH - XBRL Taxonomy Extension Schema Document 101 .CAL - XBRL Taxonomy Extension Calculation Document 101.DEF - XBRL Taxonomy Extension Definition Document 1O0LAB - XBRL Taxonomy Extension Labels Document lOI.PRE - XBRL Taxonomy Extension Presentation Document Incorporated herein by reference 84

Table of Contents SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Energy Future Holdings Corp.

By: /s/ STAN SZLAUDERBACH Name: Stan Szlauderbach

Title:

Senior Vice President and Controller (Principal Accounting Officer)

Date: October 31, 2013 85

Exhibit 31(a)

ENERGY FUTURE HOLDINGS CORP.

Certificate Pursuant to Section 302 of Sarbanes - Oxley Act of 2002 I, John F. Young certify that:

I. I have reviewed this quarterly report on Form IO-Q 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 necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the 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 material respects 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 (as defined in Exchange Act Rules 13a-15(e) and l5d-l 5(e)) and internal control over financial reporting (as defined in Exchange Act Rules 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 under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known 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 designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of 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 conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent finctions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: October 31, 2013 /s/ JOHN F. YOUNG Name: John F. Young

Title:

President and Chief Executive Officer

Exhibit 31(b)

ENERGY FUTURE HOLDINGS CORP.

Certificate Pursuant to Section 302 of Sarbanes - Oxley Act of 2002 1, Paul M. Keglevic, certify that:

1. I have reviewed this quarterly report on Form I O-Q 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 necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the 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 material respects 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 (as defined in Exchange Act Rules 13a-5 1 (e) and 15d- 15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-1 5(f) and 15d-l 5(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known 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 designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of 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 conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: October 31, 2013 /s/ PAUL M. KEGLEVIC Name: Paul M. Keglevic

Title:

Executive Vice President and Chief Financial Officer

Exhibit 32(a)

ENERGY FUTURE HOLDINGS CORP.

Certificate Pursuant to Section 906 of Sarbanes - Oxley Act of 2002 CERTIFICATION OF CEO The undersigned, John F. Young, President and Chief Executive Officer of Energy Future Holdings Corp. (the "Company"),

DOES HEREBY CERTIFY that, to his knowledge:

I. The Company's Quarterly Report on Form 10-Q for the period ended September 30, 2013 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 31st day of October, 2013.

/s/ JOHN F. YOUNG Name: John F. Young

Title:

President and Chief Executive Officer A signed original of this written statement required by Section 906 has been provided to Energy Future Holdings Corp. and will be 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 906 of Sarbanes - Oxley Act of 2002 CERTIFICATION OF CFO The undersigned, Paul M. Keglevic, Executive Vice President and Chief Financial Officer of Energy Future Holdings Corp.

(the "Company"), DOES HEREBY CERTIFY that, to his knowledge:

1. The Company's Quarterly Report on Form 10-Q for the period ended September 30, 2013 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 31st day of October, 2013.

/s/ PAUL M. KEGLEVIC Name: Paul M. Keglevic

Title:

Executive Vice President and Chief Financial Officer A signed original of this written statement required by Section 906 has been provided to Energy Future Holdings Corp. and will be retained by Energy Future Holdings Corp. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 95(a)

Mine Safety Disclosures Safety 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 workplace accidents 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 Safety and Health Act of 1977, as amended (the Mine Act), as well as other regulatory agencies such as the RCT. The MSHA inspects US mines, including ours, on a regular basis and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment.

Such citations and orders can be contested and appealed to the Federal Mine Safety and Health Review Commission (FMSHRC), which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. The number of citations, 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 Protection Act and Item 104 of Regulation S-K sourced from data documented at October 1, 2013 in the MSHA Data Retrieval System for the three months ended September 30, 2013 (except pending legal actions, which are at September 30, 2013), are as follows:

Received Received Notd" Notic of Legal Legal Legal Tot.l Doltar Total Number of P..rn. of Potential to Actions Actions Actioon Section 104 Section Section 104(d) Section Section Valnu of MSKA of Miolng Violaions Have Pattern Pending at Initiated Resolved S and S 104(b) Citations and 1l0(bX2) 107(.) Assessments Related Under Section Under LWst Day of During During Mine (a) Citations (b) Orders Orders Violations Orders Proposed(o) Fatalities 14.) Section 104(.) priod (d) Period Period BeCkVille 4 . .. ..- - - 4 Big Brown 3 -. .. 1 - - - 2 -

Kosse - - - 2-S u l ph u r S p ri ng s . ........ - - - I Three Oaks - - - 2 2

Turlington - - -.... 2 - -

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 injury if left unabated.

(c) Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in the three months ended September 30, 2013, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.

(d) Pending actions before the FMSHRC involving a coal or other mine. All 10 are contests of proposed penalties.

Exhibit 99(a)

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES CONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

Twelve Months Ended September 30, 2013 (millions of dollars)

Operating revenues $ 5,850 Fuel, purchased power costs and delivery fees (2,838)

Net gain from commodity hedging and trading activities 189 Operating costs (937)

Depreciation and amortization (1,388)

Selling, general and administrative expenses (723)

Franchise and revenue-based taxes (76)

Impairment of goodwill (1,200)

Other income 24 Other deductions (366)

Interest income 1 Interest expense and related charges (2,677)

Loss before income taxes and equity in earnings of unconsolidated subsidiaries (4,141)

Income tax benefit 1,278 Equity in earnings of unconsolidated subsidiaries (net of tax) 276 Net loss $ (2,587)

Exhibit 99(b)

Energy Future Holdings Corp. Consolidated Adjusted EBITDA Reconciliation (millions of dollars)

Twelve Months Twelve Months Nine Months Ended Nine Months Ended Ended Ended September 30, 2013 September 30, 2012 September 30,2013 September 30,2012 Net loss $ (635) $ (1,408) $ (2,587) $ (1,545)

Income tax benefit (925) (879) (1,278) (971)

Interest expense and related charges 1,915 2,746 2,677 3,573 Depreciation and amortization 1,030 1,015 1,388 1,395 EBITDA $ 1,385 $ 1,474 $ 200 $ 2,452 Oncor Holdings distributions of earnings 148 100 195 152 Interest income (1) (2) (1) (2)

Amortization of nuclear fuel 114 124 146 162 Purchase accounting adjustments (a) 20 74 20 96 Impairment of goodwill - - 1,200 -

Impairment and write-down of other assets 30 9 69 13 Debt extinguishment gains - - - (26)

Equity in earnings of unconsolidated subsidiary (net of tax) (255) (249) (276) (300)

Unrealized net loss resulting from commodity hedging and trading transactions 693 1,290 929 985 EBITDA amount attributable to consolidated unrestricted subsidiaries - -_ 4 -

Noncash compensation expense (b) 5 11 5 16 Transition and business optimization costs (c) 17 31 21 40 Transaction and merger expenses (d) 29 29 39 39 Restructuring and other (e) 77 8 84 (40)

Charges related to pension plan actions (f) - - 285 -

Expenses incurred to upgrade or expand a generation station (g) 100 69 100 100 Subtotal $ 2,362 $ 2,968 $ 3,020 $ 3,687 Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions) 1,256 1,254 1,602 1,571 Adjusted EBITDA per Restricted Payments Covenant $ 3,618 $ 4,222 $ 4,622 $ 5,258 (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 nuclear fuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Twelve months ended 2012 also reflects the write-down of mineral interests in third quarter 2012.

(b) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and exclude capitalized amounts.

(c) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costs related to supply chain and information technology efficiency initiatives. 2012 also includes costs related to generation plant reliability.

(d) Transaction and merger expenses primarily represent Sponsor Group management fees.

(e) Restructuring and other in the nine and twelve months ended 2013 includes costs associated with EFH Corp.'s liability management program. The amount in the twelve months ended September 30, 2012 reflects reversal of a severance accrual.

(f) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employees of EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pension obligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensive income.

(g) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs.

Exhibit 99(c)

Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA Reconciliation (millions of dollars)

Twelve Months Twelve Months Nine Months Ended Nine Months Ended Ended Ended September 30, 2013 September 30,2012 September 30,2013 September 30,2012 Net loss $ (679) $ (1,252) $ (2,375) $ (1,332)

Income tax benefit (468) (670) (692) (713)

Interest expense and related charges 1,324 2,200 1,876 2,879 Depreciation and amortization 1,012 992 1,363 1,365 EBITDA $ 1,189 $ 1,270 $ 172 $ 2,199 Interest income (6) (36) (16) (57)

Amortization of nuclear fuel 114 124 146 162 Purchase accounting adjustments (a) 20 54 21 64 Impairment of goodwill 1,200 Impairment and write-down of other assets 3 I 8 4 Unrealized net loss resulting from commodity hedging and trading transactions 693 1,290 929 985 Net loss attributable to noncontrolling interests 1 (1) 1 EBITDA amount attributable to consolidated unrestricted subsidiaries and other equity interests (15) (6) (13) (8)

Corporate depreciation, interest and income tax expenses included in SGC&A expense 8 13 12 18 Noncash compensation expense (b) 3 8 2 12 Transition and business optimization costs (c) 15 30 18 39 Transaction and merger expenses (d) 29 29 38 38 Restructuring and other (e) 54 7 61 (43)

Charges related to pension plan actions (f) 141 Expenses incurred to upgrade or expand a generation station (g) 100 69 100 100 Adjusted EBITDA per Incurrence Covenant $ 2,207 $ 2,854 $ 2,818 $ 3,514 Expenses related to unplanned generation station outages 35 64 53 83 Adjusted EBITDA per Maintenance Covenant $ 2,242 $ 2,918 $ 2,871 $ 3,597 (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 nuclear fuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Twelve months ended 2012 also reflects the write-down ofmineral interests in third quarter 2012.

(b) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and exclude capitalized amounts.

(c) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costs related to supply chain and information technology efficiency initiatives. 2012 also includes costs related to generation plant reliability.

(d) Transaction and merger expenses primarily represent Sponsor Group management fees.

(e) Restructuring and other in the nine and twelve months ended 2013 includes costs associated with the liability management program. The amount in the twelve months ended September 30, 2012 reflects reversal of a severance accrual.

(f) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employees of EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pension obligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensive income.

(g) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs.

Exhibit 99(d)

Energy Future Intermediate Holding Company LLC Consolidated Adjusted EBITDA Reconciliation (millions of dollars)

Twelve Months Twelve Months Nine Months Ended Nine Months Ended Ended Ended September 30,2013 September 30,2012 September 30,2013 September 30,2012 Net income $ 68 $ 308 $ 75 $ 358 Income tax expense (100) 35 (108) 36 Interest expense and related charges 566 368 724 457 EBITDA $ 534 $ 711 $ 691 $ 851 Oncor Holdings distributions of earnings 148 100 195 152 Interest income (284) (462) (420) (551)

Equity in earnings of unconsolidated subsidiary (net of tax) (255) (249) (276) (300)

Restructuring and other (a) 5 - 5 -

Adjusted EBITDA per Incurrence Covenant $ 148 $ 100 $ 195 $ 152 Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions) 1,256 1,254 1,602 1,571 Adjusted EBITDA per Restricted Payments Covenant $ 1,404 $ 1,354 $ 1,797 $ 1,723 (a) Restructuring and other in the nine and twelve months ended 2013 includes costs associated with EFH Corp.'s liability management program.