CPSES-200500331, (CPSES) - Guarantees of Payment of Deferred Premiums

(CPSES) - Guarantees of Payment of Deferred Premiums

ML050470019
Person / Time
Site:	Comanche Peak
Issue date:	02/04/2005
From:	Blevins M TXU Generation Co, LP, TXU Power
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CPSES-200500331, TXX-05030
Download: ML050470019 (67)

Text

9%lXU "I Poxwer TXU Power Mike Blevins Comanche Peak Steam Senior Vice President &

Electric Station Chief Nuclear Officer P. O. Box 1002 (EO1)

Glen Rose, TX 76043 Tel: 254 897 5209 Ref: IOCFRI40.21(e)

Fax: 254 897 6652 mikeblevinsbtxu.com CPSES-200500331 Log # TXX-05030 February 4, 2005 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555

SUBJECT:

COMANCHE PEAK STEAM ELECTRIC STATION (CPSES)

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

Pursuant to I0CFRl40.21(e), TXU Generation Company LP (TXU Power) hereby submits FORM I0-Q for TXU Energy Company LLC for the period ending September 30, 2004 (enclosed), to demonstrate the Company's ability to pay deferred premiums under the Secondary Financial Program. The cash flow for the quarterly period ending September 30, 2004 is found on page 3 of the report.

This communication contains no licensing basis commitments regarding CPSES Units l and 2.

M (A, A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

• Comanche Peak

• Diablo Canyon

• Palo Verde

• South Texas Project

• Wolf Creek

TXX-05030 Page 2 of 2 Sincerely, TXU Generation Company LP By:TXU Generation Management Company LLC, Its General Partner Mike Blevns By: /&1 <TadL

/Fred W. Madden Director Regulatory Affairs JDS/js Enclosure c - B. S. Mallett, Region IV W. D. Johnson, Region IV M. C. Thadani, NRR Resident Inspectors, CPSES

Enclosure to TXX-05030 FORM 10-Q TXU Energy Co LLC - N/A

I.

SIC~~ StAC. :Of FORM 10-Q

- TXU ENERGY CO LLC - N/A Filed: November 15, 2004 (period: September 30, 2004)

Quarterly report which provides a continuing view of a company's financial position

I n-

.PART FINANCIAL INFORMATION Item 1. Financial Statements item 2. Manaaements Discussion and Analysis of Financial Condition Item 3. Quantitative and Qualitative Disclosures About Market Risk ................... 47 Item 4. Controls and Procedures ..... 49 PART 11.

OTHER INFORMATION Item 1. Leaal Proceedinas ....................... 50

.PART 11 OTHER INFORMATION Item 6, Exhibits ................ 50 PART 1.

FINANCIAL INFORMATION Item 1. FINANCIAL STATEMENTS ITENT 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ITERI 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK tITEŽ1 4. CONTROLS AND PROCEDURES PART 11.

OTHER INFORMATION ITENM1. LEGAL PROCEEDINGS ITEMS 6. EXHIBITS SIGNATURE EX-31 EX 31 EX-32 EX-32 EX-99 (Exhibits not specifically designated by another number and by investment companies)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q I X ) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2004

-- OR --

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 333-108876 TXU EnergyCompany LLC A Delaware Limited Liability Company 75-2967817 (State of Organization) (I.R.S. Employer Identification No.)

1601 Bryan Street, Dallas TX, 75201-3411 (214) 812-4600 (Address of Principal Executive Offices) (Registrant's Telephone Number)

(Zip Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the 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 X No Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes No X As of November 9, 2004, all outstanding common membership interests in TXU Energy Company LLC were held by TXU US Holdings Company.

TABLE OF CONTENTS PAGE Glossary .......................................................................................... ii PART 1. FINANCIAL INFORMATION Item 1. Financial Statements Condensed Statements of Consolidated Income -

Three and Nine Months Ended September 30, 2004 and 2003 ..................... 1 Condensed Statements of Consolidated Comprehensive Income-Three and Nine Months Ended September 30, 2004 and 2003 ..................... 2 Condensed Statements of Consolidated Cash Flows -

Nine Months Ended September 30, 2004 and 2003 ............................... 3 Condensed Consolidated Balance sheets -

September 30, 2004 and December 31, 2003 .................................... 4 Notes to Condensed Financial Statements..................................... S Report of Independent Registered Public Accounting Firm..................... 21 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations .................................................... 22 Item 3. Quantitative and Qualitative Disclosures About Market Risk ................... 47 Item 4. Controls and Procedures ...................................................... 49 PART II. OTHER INFORMATION Item 1. Legal Proceedings ............................................................. 50 Item 6. Exhibits...................................................................... 50 SIGNATURE.......................................................................................... 51 Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K that contain financial information of TXU Energy Company LLC and its subsidiaries are made available to the public, free of charge, on the TXU Corp. website at http://www.txucorp.com, shortly after they have been filed with the Securities and Exchange Commission. TXU Energy Company LLC will provide copies of current reports not posted on the website upon request. The information on TXU Corp.'s website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-Q.

i

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

1999 Restructuring Legislation that restructured the electric utility industry in Texas to provide for retail competition 2003 Form 10-K ................ Energy's Annual Report on Form 10-K for the year ended December 31, 2003 Bcf .............. billion cubic feet Commission ..........  ;: Public Utility Commission of Texas EITF ......... ... Emerging Issues Task Porce EITF 98-10 ... . EITF Issue No. 98-10, 'Accounting for Contracts Involved in Energy Trading and Risk Management Activities' EITF 02-3 ..................................... EITF Issue No. 02-3, 'Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" Electric Delivery ............................. . refers to TXU Electric Delivery Company, formerly Oncor Electric Delivery Company, a subsidiary of US Holdings, or Electric Delivery and its consolidated bankruptcy remote financing subsidiary, TXU Electric Delivery Transition Bond Company LLC, depending on context Energy......................................... refers to TXU Energy Company LLC, a subsidiary of US Holdings, and/or its consolidated subsidiaries, depending on context ERCOT....................................... Electric Reliability Council of Texas. the Independent System Operator and the regional reliability coordinator of various electricity systems within Texas FASB ......................................... Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting FERC ......................................... Federal Energy Regulatory Commission FIN . Financial Accounting Standards Board Interpretation FIN 46......................................... FIN No. 46. "Consolidation of Variable Interest Entities -

An Interpretation of ARB No. 51" FIN 46R....................................... FIN No. 46 (Revised 2003), 'Consolidation of Variable Interest Entities - An Interpretation of ARB No. S1" Fitch.......................................... Fitch Ratings, Ltd.

GWh .......................................... gigawatt-hours Historical service territory................... US Holdings' historical service territory, largely in north Texas, at the time of entering retail competition on January 1, 2002 Moody's ..................................... Moody's Investors Services, Inc.

ii

M .............................................

" megawatts NRC ............................................. United States Nuclear Regulatory Commission price-to-beat rate ............................. residential and small business customer electricity rates established by the Commission in the restructuring of the Texas market that are required to be charged in a REP's historical service territories until January 1, 2005 or when 40t of the electricity consumed by such customer classes is supplied by competing REPs, adjusted periodically for changes in fuel costs, and required to be available to those customers until January 1, 2007 REP ............................................ retail electric provider S. Standard &Poor's, a division of The McGraw Hill Companies Sarbanes-Oxley ................................. Sarbanes - Oxley Act of 2002 SEC ............................................ United States Securities and Exchange Commission SFAS ........................................... Statement of Financial Accounting Standards issued by the FASB SFAS 133. SPAS No. 133, 'Accounting for Derivative Instruments and Hedging Activities" SFAS 140. SFAS No. 140, 'Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement 125" SFAS 143. SPAS No. 143, 'Accounting for Asset Retirement Obligations' SFAS 150. SFAS No. 150, 'Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" SG.selling, general and administrative TXU Business Services......................... TXU Business Services Company, a subsidiary of TXU Corp.

TXU Corp...................................... refers to TXU Corp., a holding company, and/or its consolidated subsidiaries, depending on context TXU Gas........................................ TXU Gas Company, a subsidiary of TXU Corp.

TXU Mining ................................... TXU Mining Company LP, a subsidiary of Energy TXU Portfolio Management. ...................... TXU Portfolio Management Company LP, a subsidiary of Energy US............................................. United States of America US GAAP. ....................................... accounting principles generally accepted in the US US Holdings .................................. TXU US Holdings Company, a subsidiary of TXU Corp.

iii

PART 1. FINANCIAL INFORMATION Item 1. FINANCIAL STATEMENTS TXU ENERGY COMPANY LLC CONDENSED STATEMENTS OF CONSOLIDATED INCOME (Unaudited)

- Three Months Ended T - Nine Months Ended September 30, September 30.

2004 2003 - 2004 2003 (millions of dollars)

Operating revenues ..........................  ; . $2.51? $2,437 $6, 589 $6 243 Costa and expenses:

Cost of energy sold, including delivery fees...................... 1.556 1.539 4,157 4,037 Operating costs................................................. 145 164 513 506 Depreciation and amortizationz..................................... 83 100 268 306 Selling, general and administrative expenses...................... 182 166 491 456 Franchise and revenue-based taxes................................. 28 29 80 84 Other income....................................... (36) (20) (50) (43)

Other deductions. ...................................... 20 4 301 9 Interest income. ...................................... (13) (1) (21) (3)

Interest expense and related charges .............................. 91 83 263 246 2_0__

Total costs and expenses...................................... 2,056 2.064 6. 002 5,598 Income from continuing operations before income taxes and cumulative effectof changes in accounting principles ......................... 461 373 587 645 Income tax expense ................................................... 152 123 179 205 Income from continuing operations before cumulative affect of changes in accounting principles............................... 309 250 408 440 Loss from discontinued operations, net of tax benefit (Note 3)....... (3) (1) (33) (2)

Cumulative effect of changes in accounting principles, net of tax benefit (Note 2) ............................................. _ (58)

Net income........................................................... $ 306 $ 249 $ 375 $ 380 See Notes to Financial Statements 1

TXU ENERGY COMPANY LLC CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Unaudited)

Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 (millions of dollars)

Components related to continuing operations:

Income from continuing operations before cumulative effect of changes in accounting principles................................... $ 309 $ 250 $ 408 $ 440 Other comprehensive income (loss), net of tax effects Cash flow hedge activity--

Net change in fair value of derivatives (net of tax benefit of

$2, $11. $46 and $63)........................................... (12) (20) (87) (119)

Amounts realized in earnings during the period (net of tax expense of $3, $24, $11 snd $63) ................................ 8 46 20 117 Total........................................................... (4) 26 (67) (1)

Comprehensive income related to continuing operations................. 305 276 341 439 Comprehensive loss related to discontinued operations................. (3) (1) (33) (2)

Cumulative effect of changes in accounting principles, net of tax benefit.......................................................... - 58)

Comprehensive income....................................... $ 302 $ 275 $ 308 $ 379 See Notes to Financial Statements.

2

TXU ENERGY COMPANY LLC CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)

Nine Months Ended September 30, 2004 2003 (millions of dollars)

Cash flows - operating activities:

Income from continuing operations before cumulative effect of changes in accounting principles. ...................................... $ 408 $ 440 Adjustments to reconcile income from continuing operations before cumulative effect of changes in accounting principles to cash provided by operating activities:

Depreciation and amortization ............................................... 315 356 Deferred income taxes and investment tax credits - net ...................... 17 30 Asset writedown charges...................................................... 186 Net gain from sale of assets. ...................................... (48) (40)

Net effect of unrealized mark-to-market valuations of commodity contracts.... 46 (58)

Retail clawback accrual...................................................... (19)

Loss on early extinguishment of debt......................................... 1 1 Net equity loss from unconsolidated affiliates and joint ventures............ 7 Changes in operating assets and liabilities..................................... (144) 319 788___ ______

Cash provided by operating activities .................................... 788 1,029 Cash flows - financing activities:

Issuances of long-term debt..................................................... 800 1,400 Retirements/repurchases of debt................................................. (229) (222)

Increase (decrease) in notes payable to banks................................... 565 (282)

Net change in advances from affiliates.....  ;.......' (1,201) (1,580)

Distribution paid to parent..................................................... (525) (575)

Decrease in note payable to TXU Electric Delivery Company....................... (161)

Debt premium, discount, financing and reacquisition expenses.................... (15) (30)

Cash used in financing activities...................................... (605) (1,450)

Cash flows - investing activities:

Capital expenditures............................................................ (149) (123)

Nuclear fuel.................................................................... (46) (45)

Proceeds from sale of assets.................................................... 19 19 Other........................................................................... 20 (9)

Cash used in investing activities...................................... (156) (158)

__3)__

Cash used by discontinued operations. ...................................... (40) (3)

Net change in cash and cash equivalents....................................... (13) (582)

Cash and cash equivalents - beginning balance..................................... 18 603 Cash and cash equivalents - ending balance........................................ $ 5 $ 21 See Notes to Financial Statements.

3

TXU ENERGY COMPANY LLC CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

September 30, December 31, 2004 2003 (millions of dollars)

ASSETS Current assets:

Cash and cash equivalents ..................................... $ S $ s18 Advances to affiliates........................ . 1,524 289 Accounts receivable - trade .. 989 943 Inventories.................... 296 386 Commodity contract assets .. 707 548 Other current assets .. 317 225 Total current assets .. 3,838 2,409 Investments...................................................... 522 479 Property, plant and equipment - net. 9.833 10,345 Goodwill......................................................... 517 533 Commodity contract assets...................................... 229 109 Cash flow hedge and other derivative assets.24 88 Assets held for sale .27 59 Other noncurrent assets .200 127 Total assets............$................................... 5 15,190 $ 14,;49 LIABILITIES AND MEMBERSHIP INTERESTS Current liabilities:

Notes payable - banks. 565 $ -

Long-term debt due currently .. 31 1 Accounts payable - trade:

Affiliates (principally TXU Electric Delivery Company) 243 211 All other..................... 844 712 Notes or other liabilities due TXU Electric Delivery Company 30 13 Commodity contract liabilities .. 545 502 Accrued taxes ......................... ............. 163 292 Other current liabilities .. 549 564 Total current liabilities. 2,970 2,295 Accumulated deferred income taxes.1,892 1,950 Investment tax credits....................................... 346 360 Commodity contract liabilities .309 47 Cash flow hedge and other derivative liabilities 218 140 Notes or other liabilities due to TXU Electric Delivery Company 407 424 Other noncurrent liabilities and deferred credits................ 1,193 1,342 Long-term debt, less amounts due currently....................... 3,630 3,084 Preferred membership interests, held by TXU Corp. at September 30, 2004, net of discount of $242 and $253 (Note 4) 508 497 Liabilities held for sale .......................... 8.............. 11 Total liabilities........................14.............. - - 81 10,150 Contingencies (Note 6)

Membership interests (Note 5):

Capital account.................... 3,886 4,109 Accumulated other comprehensive loss .(177) (110)

Total membership interests .3,709 3,999 Total liabilities and membership interests .................. $ 15,190 $ 14,149 See Notes to Financial Statements.

4

TXU ENERGY COMPANY LLC NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited)-

1. SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS Description of Business - Energy is a subsidiary of US Holdings, which is a subsidiary of TXU Corp. Energy is engaged in electricity generation and retail and wholesale energy sales and hedging and risk management operations. Energy is currently managed as an integrated business; consequently, there are no reportable business segments. -

Strategic Initiatives and Other Actions - Mr. C. John Wilder, who was named president and chief executive of TXU Corp. in February 2004, and senior management have been reviewing the operations of TXU Corp. and have formulated certain strategic initiatives and continue to develop others. Areas being reviewed include:

o Performance in competitive markets, including profitability in new markets; o Cost structure, including organizational alignments and headcount; o Management of natural gas price risk and cost effectiveness of the generation fleet; and - ,.

o Non-core business activities.  : -

As discussed below, implementation of the strategic initiatives as well as other actions taken to date have resulted in total-charges of $8 million ($5 million after-tax) in the third quarter of .2004 and $284 million ($185 million after-tax) year-to-date, substantially all reported in other deductions, related to asset writedowns and employee severance. In the third quarter of 2004, Energy recorded gains on the disposition of properties, principally undeveloped land, totaling $18 million ($12 million after-tax), reported in other income.

Charges recorded in the three-month-and nine-month periods ended September 30, 2004 and 2003 reported in other deductions are detailed in Note 8.

Capgemini Energy Agreement - -

On May 17, 2004, Energy entered into a'services agreement with a subsidiary of Cap Gemini North America Inc.-, Capgemini Energy LP (Capgemini), a new company initially providing business-process support services to TXU Corp.,

but immediately implementing a plan to offer similar services to other utility companies. Under the ten-year-agreement, over 2,500 TXU Corp. employees (including approximately 1,100 from Energy) transferred to Capgemini effective July 1, 2004. Outsourced base support services performed by Capgemini for a fixed fee, subject to adjustment for volumes or other factors, include information technology, customer call center, billing and collections, human resources, supply chain and certain accounting activities.

As part of the agreement, Capgemini was provided a royalty-free right, under an asset license arrangement, to use information technology assets, consisting primarily of capitalized software. A portion of the software was in development and had not yet been placed in service by Energy. As a result of outsourcing its information technology activities, Energy no longer intends to develop the majority of these projects and from Energy's perspective the software is abandoned. The agreements with Capgemini do not require that any software in development be completed and placed in service. Consequently, the carrying value of these software projects was written off, resulting in a charge of $107 million ($70 million-after-tax) for the nine months ended September 30, 2004, reported in other deductions, essentially all of which was recorded in the second quarter of 2004. The remaining assets were transferred to a subsidiary of TXU Corp. at book value in exchange for an interest in that subsidiary. Such interest is accounted for by Energy on the equity method, and Energy recorded equity losses (representing depreciation expense) of $7 million in the third quarter of 2004, reported in other deductions. ;

The TXU Corp. subsidiary received a 2.9% limited partnership interest in Capgemini in exchange for the asset license described above. Energy and Electric Delivery have the right to sell (the 'put option') their interest in the subsidiary to Cap Gemini America Inc. for $200 million, plus the subsidiary's share of Capgemini's undistributed earnings, upon expiration of the services agreement, or earlier upon the occurrence of certain unexpected events. Cap Gemini North America Inc. has the right to purchase Energy's and Electric Delivery's interests under the same terms and conditions. The partnership interest has been recorded at an initial value of $2.9 million and is being accounted for on the cost method.

5

Energy has recorded its share of the fair value of the put option as a noncurrent asset largely offset by a reduction to the carrying value of the software transferred to the subsidiary, in accordance with the accounting principles related to sales and licensing of internally developed software described in AICPA Statement of Position 98-1, 'Accounting for the Costs of Computer Software Developed or Obtained for Internal Use."

Also as part of its agreement, TXU Corp. agreed to indemnify Capgemini for severance costs incurred by Capgemini for former TXU Corp. employees terminated within 18 months of their transfer to Capgemini. Accordingly, Energy recorded a

$27 million ($18 million after-tax) charge for severance expense in the second quarter of 2004, which represents a reasonable estimate of the indemnity and is reported in other deductions. The charge includes an allocation of severance related to TXU Business Services Company employees. The transition costs applicable to Energy are expected to be largely recorded during the fourth quarter of 2004.

Transfer and Sale of TXU Fuel Company On April 30, 2004, Energy distributed the assets of TXU Fuel Company, its gas transportation subsidiary, to US Holdings at book value, including $16 million of allocated goodwill (see Note 5). On June 2, 2004, US Holdings completed the sale of the assets of TXU Fuel Company to Energy Transfer Partners, L.P. for $500 million in cash. The assets of TXU Fuel Company consisted of approximately 1,900 miles of intrastate pipeline and a total system capacity of 1.3 Bcf/day. As part of the transaction, Energy entered into a market-price based transportation agreement with the new owner to transport gas to Energy's generation plants. Because of the continuing involvement in the business through the transportation agreement, the business has not been accounted for as a discontinued operation.

Facility Closures and Other Actions Related to Generation Operations In the third quarter of 2004, Energy recorded gains totaling $18 million

($12 million after-tax) related to the sale of undeveloped land. The gains are reported in other income.

In the second quarter of 2004, Energy initiated a plan to sell the Pedricktown, New Jersey 122 MW power production facility and exit the related power supply and gas transportation agreements. Accordingly, Energy recorded an impairment charge of $26 million ($17 million after-tax) to write down the facility to estimated fair market value. The results of the business and the impairment charge are reported in discontinued operations as discussed in Note 3.

As part of Energy's review of its generation asset portfolio, Energy completed a review of its spare parts and equipment inventory to determine the appropriate level of such inventory. The review included nuclear, coal and gas-fired generation-related facilities. As a result of this review, Energy recorded a charge of $19 million ($51 million after-tax), reported in other deductions, in the second quarter of 2004 to reflect excess inventory on hand and to write down carrying values to scrap values.

In March 2004, Energy announced the planned permanent retirement, completed in the second quarter of 2004, of eight gas-fired operating units due to electric industry market conditions in Texas. Energy also temporarily closed four other gas-fired units and placed them under evaluation for retirement. The 12 units represented a total of 1,471 MW, or more than 13%, of Energy's gas-fired generation capacity in Texas. A majority of the 12 units were designated as 'peaking units' and operated only during the summer for many years and have operated only sparingly during the last two years. Most of the units were built in the 1950's. Energy also determined that it would close its Winfield North Monticello lignite mine in Texas, and such closure has been completed, as it is no longer economical to operate when compared to the cost of purchasing coal to fuel the adjacent generation facility. A total charge of $8 million ($5 million after-tax) was recorded in the first quarter of 2004, reported in other deductions, for production employee severance costs ($7 million pre-tax) and impairments related to the various facility closures ($1 million pre-tax).

Organizational Realignment and Headcount Reductions During the second quarter of 2004, management completed a comprehensive organizational review, including an analysis of staffing requirements. As a result, Energy completed a self-nomination severance program and finalized a plan for additional headcount reductions under an involuntary severance program, which has been largely completed. Accordingly, in the second quarter of 2004, Energy recorded severance charges totaling $43 million ($28 million after-tax),

reported in other deductions.

Preferred Membership Interests In April 2004, TXU Corp. purchased from the holders Energy's preferred membership interests with a liquidation value of $750 million. Energy's carrying amount of the security, which remains outstanding, is the $750 million liquidation amount less $242 million remaining unamortized discount and $30 million in unamortized debt issuance costs.

Discontinued Businesses - Note 3 presents detailed information regarding the discontinued New Jersey generation operations and the strategic retail services business; The condensed consolidated financial statements for all periods presented reflect the reclassification of the results of these businesses as discontinued operations.

Basis of Presentation -- The condensed consolidated financial statements of Energy have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in its 2003 Form 10-K, except for the changes in estimates of depreciable lives of assets discussed below and the presentation of certain operations as discontinued. In the opinion of management, all other adjustments (consisting of normal 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. 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 the 2003 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) was enacted in December 2003.,TXU Corp. is accounting for the effects of the Medicare Act in accordance with FASB Staff Position 106-2. For the three and nine months ended September 30, 2004, the effect of adoption of the Medicare Act was a reduction of approximately $3 million and $8 million, respectively, in Energy's postretirement benefit costs.

Certain reclassifications have been made to conform prior period data to the current period presentation. All dollar amounts in the financial statements and tables in the notes are stated in millions of dollars unless otherwise indicated.

Depreciation of Energy Production Facilities -- Effective January 1, 2004, the estimates of the depreciable lives of lignite-fired generation facilities were extended an average of nine years to better reflect the useful lives of the assets, and depreciation rates for the Comanche Peak nuclear generating plant were decreased as a result of an increase in-the estimated lives of boiler and -

turbine generator components of the plant by an average of five years. The net impact of these changes was a reduction in depreciation expense of $11 million and $33 million ($7 million and $21 million after-tax) in the three and nine months, respectively, ended September 30, 2004.

.7

_. _s U Effective April 1, 2003, the estimates of the depreciable lives of the Comanche Peak nuclear generating plant and several gas generation plants were extended to better reflect the useful lives of the assets. At the same time, depreciation rates were increased on lignite and gas generation facilities to reflect additional investments in equipment. The net impact of these changes was an additional reduction in depreciation expense of $12 million ($8 million after-tax) in the nine months ended September 30, 2004.

Changes in Accounting Standards -- FIN 46R was issued in December 2003 and replaced FIN 46, which was issued in January 2003. FIN 46R expands and clarifies the guidance originally contained in FIN 46, regarding consolidation of variable interest entities. FIN 46R did not impact results of operations or financial position for the first nine months of 2004.

2. CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES The following summarizes the effect on results for 2003, reported in the first quarter, of changes in accounting principles effective January 1, 2003:

Charge from rescission of EITF 98-10, net of tax effect of $34 million ..... $(63)

Credit from adoption of SFAS 143, net of tax effect of $3 million .......... 5 Total net charge ...................................................... $(58)

On October 25, 2002, the EITF, through EITF 02-3, rescinded EITF 98-10, which required mark-to-market accounting for all trading activities. Pursuant to this rescission, only financial instruments that are derivatives under SFAS 133 are subject to mark-to-market accounting. Financial instruments that may not be derivatives under SFAS 133, but were marked-to-market under EITF 98-10, consist primarily of gas transportation and storage agreements, power tolling, full requirements and capacity contracts. This new accounting rule was effective for new contracts entered into after October 25, 2002. Non-derivative contracts entered into prior to October 26, 2002, continued to be accounted for at fair value through December 31, 2002; however, effective January 1, 2003, such contracts were required to be accounted for on a settlement basis. Accordingly, a charge of $97 million ($63 million after-tax) was reported as a cumulative effect of a change in accounting principles in the first quarter of 2003. Of the total, $75 million reduced net commodity contract assets and liabilities and $22 million reduced inventory that had previously been marked-to-market as a trading position. The cumulative effect adjustment represents the net gains previously recognized for these contracts under mark-to-market accounting.

SFAS 143 became effective on January 1, 2003. SFAS 143 requires entities to record the fair value of a legal liability for an asset retirement obligation in the period of its inception. For Energy, such liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite plant ash treatment facilities. The liability is recorded at its net present value with a corresponding increase in the carrying value of the related long-lived asset. The liability is accreted each period, representing the time value of money, and the capitalized cost is depreciated over the remaining useful life of the related asset.

As the new accounting rule required retrospective application to the inception of the liability, the effects of the adoption reflect the accretion and depreciation from the liability inception date through December 31, 2002.

Further, the effects of adoption take into consideration liabilities of $215 million (previously reflected in accumulated depreciation) Energy had previously recorded as depreciation expense and $26 million (reflected in other noncurrent liabilities) of unrealized net gains associated with the decommissioning trusts.

The following table summarizes the impact as of January 1, 2003 of adopting SFAS 143:

Increase in property, plant and equipment - net .................. $488 Increase in other noncurrent liabilities and deferred credits... (528)

Increase in accumulated deferred income taxes .................... (3)

Increase in affiliated receivable ................................ 48 Cumulative effect of change in accounting principles ............. $ 5 8

The asset retirement liability at September 30, 2004 was $610 million.

comprised of a $599 million liability as of December 31, 2003 and $30 million of accretion during the nine months ended September 30, 2004, reduced by $19 million in reclamation payments.

With respect to nuclear decommissioning costs, for Energy the adoption of SFAS 143 results in timing differences in the recognition of asset retirement costs that are being recovered through the regulatory process.

3. DISCONTINUED OPERATIONS The following summarizes the historical consolidated financial information of the businesses reported as discontinued operations:

Three Months Ended September 30, Nine Months Ended September 30, 2004 2004 Strategic Strategic Retail Retail Services Pedricktown Total Services Pedricktown Total

$ 3 _________

Operating revenues....................... $ 3 $ 8 $ it

• 13 S 27 $ 40 Operating costa and expenses.............. 4 12 - 16 30 46 Other deductions - net.................... 10 20 Operating loss before income taxes........ (U)

{1 (13) (3) (16)

Income tax expense (benefit)..............  : , 1 ' I (4) 1 (1) (5)

Operating loss........ .. , . (2) ___

(2) (9) (2) }, (111 Charges related to exit (after-tax). (1) (U) (5) (17) (22)

{---D Loss from discontinued operations.... -: (3); $ (3) $ (14) $ ____

(19) $ (33)

Three Months Ended September 30, Nine Months Ended September 30,

-- 2003 - 2003

-- Strategic Strategic

' - -' Retail Retail

- Services Pedricktown Total Services Pedricktown Total Operating revenues ............................ . S 1 1 0 $ 21 $ 54 5 18 $ 72 operating costs and expenses . .........

..... . 8 10 18 49 21 70 Other deductions - net . .4 - 4 4 4 Operating income (loss) before income taxes..-'

- (1) - (1) (3) (2) 1 Income tax expense (benefit)................. (1)

-1 I - --

operating loss ........................... . (1) _ (1) (2) (2)

Loss from discontinued operations . .1. . $ (1) $ (2) $ (2)

Pedricktown - In the second quarter.of,2004, Energy initiated a plan to sell the Pedricktown, New Jersey 122 MWpower production facility and exit the related power supply and gas transportation agreements. Accordingly, results for the second quarter of 2004 included a $17 million after-tax charge to write down the facility to estimated fair market value.

Strategic Retail Services - In December 2003, Energy finalized a formal plan to sell its strategic retail services business, which is engaged principally in providing energy management services. Energy expects to substantially complete the sales of these operations to various parties by year-end 2004. Results for 2004 reflect a $9 million ($6 million after-tax) charge recorded in the second quarter to settle a contract dispute.

Balance sheet - The following details the assets and liabilities held for sale:

September 30, 2004 Strategic Retail Services Pedricktown Total Current assets........................................... $ 4 $ 2 $ 6 Investments.............................................. 2 2 Property, plant and equipment............................ 3 16 19 Assets held for sale................................ $ 9 $ 18 $ 27 Current liabilities...................................... $. 4 $ 4 Noncurrent liabilities................................... ..... 4 4 Liabilities held for sale........................... $ 8 $ B

4. FINANCING ARRANGEMENTS Short-term Borrowings -- At September 30, 2004, Energy had outstanding short-term borrowings consisting of bank borrowings under the three-year revolving credit facility of $565 million at a weighted average interest rate of 4.27%. At December 31, 2003, Energy had no outstanding short-term borrowings.

Credit Facilities -- At September 30, 2004, TXU Corp. had credit facilities (some of which provide for long-term borrowings) as follows:

At September 30, 2004 Maturity Authorized Facility Letters of Cash

______________________Facility_____

Facility Date Borrowers Limit Credit Borrowings Availability Energy, Electric 364-day Credit Facility June 2005 Delivery $ 600 $ 80 $ - $ 520 Three-Year Revolving Credit Energy, Electric Facility June 2007 Delivery 1,400 - 565 835 Five-Year Revolving Credit Facility August 2008 TXU Corp. Soo 429 71 Fv-Year-----Revolving Credit----------

Five-Year Revolving Credit Energy, Electric Facility June 2009 Delivery 500 - _ 500 Total $3,000 $ 509 $ 565 $ 1,926 On September 28, 2004, portions of the Brazos River Authority Pollution Control Revenue Refunding Bonds related to the Twin Oak facility were redeemed at par as follows: $57 million of Series 2001C; $21 million of Series 2003C; $16 million of Series 2002A; $4 million of series 1995B3; and $3 million of Series 2001D.

In June 2004. US Holdings, Energy and Electric Delivery replaced $2.25 billion of credit facilities scheduled to mature in 2005 with $2.5 billion of credit facilities for Energy and Electric Delivery maturing in June 2005, 2007 and 2009. These facilities are used for working capital and general corporate purposes and provide back-up for any future issuances of commercial paper by Energy or Electric Delivery. At September 30, 2004, there was no such commercial paper outstanding.

In April 2004, Energy entered into a $1.0 billion, 364-day credit facility. In July 2004, borrowings under this facility were repaid with proceeds from Energy's issuance of $800 million floating rate senior notes and repayment of advances to affiliates and the facility was subsequently terminated.

TXU Corp.'s $500 million five-year revolving credit facility provides for up to $500 million in letters of credit and/or up to $250 million of loans ($500 million in the aggregate). To the extent capacity is available under this facility, it may be made available to US Holdings, Energy or Electric Delivery for borrowings, letters of credit or other purposes.

Sale of Receivables -- TXU Corp. has established an accounts receivable securitization program. The activity under this program is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU

Receivables Company, a consolidated wholly-owned bankruptcy remote direct subsidiary of TXU Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities). As of September 30, 2004, $629 million of undivided interests in Energy's accounts receivable had been sold by TXU Receivables Company. Effective June 30,,2004, the program was extended through June 28, 2005. As part of the extension, the maximum amount available under the program was increased from $600 million to $700 million in recognition of seasonal power sales. Additionally, the extension allows for increased availability of funding through a credit ratings-based reduction (based on each originator's credit rating) of customer deposits previously used to reduce the amount of undivided interests that could be sold. Undivided interests will now be reduced by 100% of the customer deposits for a Baa3/BBB- rating; SO% for a Baa2/BBB rating; and zero % for a Baal/BBB+ and above rating.

-10

- L .

All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, are generally due to seasonal variations in the level of accounts receivable and changes in collection trends. TXU Receivables Company has issued subordinated notes payable to the originators for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originators that was funded by the sale of the undivided interests.

The discount from face amount on the purchase of receivables principally funds program fees paid by TXU Receivables Company to the funding entities, as well as a servicing fee paid by TXU Receivables Company to TXU Business Services, a direct subsidiary of TXU Corp. The program fees (losses on sale),

which consist primarily of interest costs on the underlying financing, were approximately $7 million for each of the nine-month periods ending September 30, 2004 and 2003 and approximated 1.9t and 2.5% for the first nine months of 2004 and 2003, respectively, of the average funding under the program on an annualized basis; these fees represent the net incremental costs of the program to Energy and are reported in SG&A expenses. The servicing fee, which totaled approximately $3 million and S4 million for the first nine months of 2004 and 2003, respectively, compensates TXU Business Services for its services as collection agent, including maintaining the detailed accounts receivable collection records.

The September 30, 2004 balance sheet reflects $984 million face amount of trade accounts receivable reduced by $629 million of undivided interests sold by TXU Receivables Company. Funding under the program increased $125 million for the nine months ended September 30, 2004. Funding under the program for the nine months ended September 30, 2003 increased $198 million. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable approximated fair value due to the short-term nature of the collection period.

Activities of TXU Receivables Company related to Energy for the nine months ended September 30, 2004 and 2003 were as follows:

Nine Months Ended September 30, 2004 2003 Cash collections on accounts receivable ...................................... $ 4,928 $4,933 Face amount of new receivables purchased..................................... (4.979) (4,862)

Discount from face amount of purchased receivables ........................... 10 11 Program fees paid ............................................................ (7) (7)

Servicing fees paid .......................................................... (3) (4)

Increase (decrease) in subordinated notes payable ............................ (74) (268)

Operating cash flows provided to Energy under the program ............... 5 (125) $ (197)

Upon termination of the program, cash flows to Energy would be delayed as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests sold instead of purchasing new receivables.

The level of cash flows would normalize in approximately 16 to 31 days.

11

Contingencies Related to Sale of Receivables:Program -- Although TXU Receivables Company expects to be able to pay its subordinated notes from the collections of purchased receivables, these notes are subordinated to the undivided interests of the financial institutions in those receivables, and collections might not be sufficient to pay the subordinated notes. The program may be terminated if either of the following events occurs:

1) all of the originators cease to maintain their required fixed charge coverage ratio and debt to capital (leverage) ratio;

2) the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts,

'disputes and other allowances) 'or the'days collection outstanding ratio exceed stated thresholds and the financial institutions do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables, not separately to the receivables of each originator.

The delinquency and dilution ratios exceeded the relevant thresholds during the first four months of 2003, but waivers were granted. These ratios were affected by issues related to the transition to competition. Certain billing and collection delays arose due to implementation of new systems and processes within Energy and ERCOT for clearing customers' switching and billing data. Strengthened credit and collection policies and practices have brought the ratios into consistent compliance with the program requirement.

Under terms of the receivables sale program, all the originators are required to maintain specified fixed charge coverage and leverage ratios (or supply a parent guarantor that meets the ratio requirements). The failure, by an originator or its parent guarantor, if any,:to maintain the specified financial' ratios would prevent that originator from selling its accounts receivable under the program. If all the originators and the parent'guarantor, if any, fail to maintain the specified financial ratios so that there are no eligible originators, the facility would terminate.

12

Long-term Debt -- At September 30, 2004 and December 31, 2003, the long-term debt of Energy and its consolidated subsidiaries consisted of the following:

September 30, December 31, 2004 2003 PollutiorL Control Revenue Bonds:

Brazos River Authority:

3.000O Fixed Series 1994A due May 1, 2029, remarketing date May 1, 2005(a)........... $ 39 $ 39 5.400% Fixed Series 1994B due May 1, 2029, remarketing date May 1, 2006(a)........... 39 39 5.400% Fixed Series 1995A due April 1, 2030, remarketing date May 1, 2006(a)......... 50 50 5.050% Fixed Series 1995B due June 1, 2030, remarketing date June 19, 2006(a)........ 114 118 7.700% Fixed Series 1999A due April 1, 2033.......................................... 111 111 6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013(a)... 16 16 7.700% Fixed Series 1999C due March 1, 2032.......................................... 50 50 4.9501 Fixed Series 2001A due October 1, 2030, remarketing date April 1, 2004(a)..... 121 4.7501 Fixed Series 2001B due May 1, 2029, remarketing date November 1, 2006(a)...... 19 19 5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011(a)...... 217 274 1.464% Floating Series 2001D due May 1, 2033......................................... 266 271 1.730% Floating Taxable Series 20011 due December 1, 2036(b)......................... 63 63 1.4 36% Floating Series 2002A due May 1, 2037(b)...................................... 45 61 6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)....... 44 44 6.300% Fixed Series 2003B due July 1, 2032........................................... 39 39 6.750% Fixed Series 2003C due October 1, 2038........................................ 52 72 5.400% Fixed Series 20030 due October 1, 2029, remarketing date October 1, 2014(a)... 31 31 Sabine River Authority of Texas:

6.450% Fixed Series 2000A due June 1, 2021........................................... 51 51 5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011(a). 91 91 5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011(a). 107 107 5.800% Fixed Series 2003A due July 1, 2022........................................... 12 12 6.150% Fixed Series 2003B due August 1, 2022......................................... 45 45 Trinity River Authority of Texas:

6.250% Fixed series 2000A due May 1, 2028............................................ 14 14 5.000% Fixed Series 2001A due May 1, 2027, remarketing date November 1, 2006(a). 37 37 Other:

6.875% TXU Mining Fixed Senior Notes due August 1, 2005.............................. 30 30 6.125% Fixed Senior Notes due March 15, 2008(c)...................................... 250 250 7.000% Fixed Senior Notes due March 15, 2013......................................... 1,000 1,000 2.380% Floating Rate Senior Notes due January 17, 2006 .............................. 800 Capital lease obligations............................................................ 9 13 Other ................................................................................ 1 8 Fair value adjustments related to interest rate swaps................................ 17 11 Unamortized--discount................................................................ (2)

Total Energy .................................................................... 3,661 3,085 Less amount due currently................................................................ 31 1 Total long-term debt ............................ 3,630 $ 3,084 (a) These series are in the multiannual 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.

(b) Interest rates in effect at September 30, 2004. These series are in a flexible or weekly rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit. Series in the flexible mode will be remarketed for periods of less than 270 days.

(c) Interest rates swapped to floating on an aggregate $250 million principal amount.

On September 28, 2004, portions of the Brazos River Authority Pollution Control Revenue Refunding Bonds related to the Twin Oak facility were redeemed at par as follows: $57 million of Series 2001C; $21 million of Series 2003C;

$16 million of Series 2002A; $4 million of series 1995B; and $3 million of Series 2001D.

In July 2004, Energy issued $800 million of floating rate senior notes in a private placement offering with registration rights. The net proceeds of $798 million were used to repay, in part, borrowings outstanding under its fully drawn $1.0 billion 364 day credit facility, which was subsequently terminated.

The notes bear interest at an annual rate equal to 3-month LIBOR, reset quarterly, plus 0.78t and will mature on January 17, 2006.

In April 2004, the Brazos River Authority Series 2001A pollution control revenue bonds with an aggregate principal amount of $121 million were purchased upon mandatory tender. Energy intends to remarket these bonds at a later date.

13

Fair Value Hedges -- Energy uses fair value hedging strategies to manage its exposure to fixed interest-rates on long-term debt. At September 30, 2004,

$250 million of fixed rate debt had been effectively converted to variable rates through interest rate swap transactions, expiring through 2008. These swaps qualified for and have been designated as fair value hedges using the short-cut method of hedge accounting provided by SFAS'133.- As-such, the company assumes that changes in the value of the derivative are perfectly offset by changes in the value of the debt; therefore,.there is no hedge ineffectiveness recognized.

In August 2004, fixed-to-variable swaps related to $500 million debt were settled for a gain of $394 thousand, which will be amortized to offset interest expense over the remaining life of the related debt. In April 2004, fixed-to-variable interest rate swaps related to:$100 million of debt were settled for a gain of $3.5 million, which will be amortized to offset interest expense over the remaining life of the debt. In March 2004, fixed-to-variable interest rate swaps related to $400 million of debt were settled for a gain of

$18 million, which will also be amortized to offset interest expense over the remaining life of the related-debt.

Preferred Membership Interests -- In July 2003, Energy exercised its right to exchange its $750 million 9% Exchangeable Subordinated Notes issued in November 2002 and due November 2012 for exchangeable preferred membership interests with identical economic and other.terms. The preferred membership interests bear distributions at the annual rate of 9% and permit the deferral of such distributions. The holders of the preferred membership-interests had the option to exchange these interests at any time, subject to certain restrictions, for up to approximately 57 million shares of TXU Corp. common stock at an exchange price of $13.1242 per share. At issuance of the notes that were subsequently exchanged for the preferred membership interests, Energy recognized a capital contribution from TXU Corp. and a corresponding discount on-the securities of $266 million, which represented the value of the exchange right as TXU Corp. granted an irrevocable right to exchange the securities for TXU Corp.

common stock. This discount is being amortized to interest expense and related charges over the term of the securities. As.:a result, the effective distribution rate on the preferred membership interestsiis 16.2%. In April 2004, TXU Corp.

purchased these mandatorily redeemable securities from the holders, as discussed in Note 1, and as a result the securities effectively represent Energy debt held by TXU Corp.  ! ' -

5. MEMBERSHIP INTERESTS - -

In August 2004, Energy approved a cash distribution of $175 million which was paid to US Holdings in October 2004. -In June 2004, Energy approved a cash distribution of $175 million which was paid to US Holdings in July 2004. In February 2004, Energy approved a cash distribution of $175 million which was paid to US Holdings in April 2004. In November 2003, Energy approved a cash distribution of $175 million which was paid to US Holdings in January 2004.

The following table presents the changes in Membership Interests for the nine months ended September 30, 2004:

Accumulated Other Total Capital Comprehensive Membership Accounts Gain (Loss) Interests Balance at December 31, 2003.....-............ $4,109 $(110) $3,999 Distributions paid to parent .(525) - (525)

Net income ......... 375 - 375 Cash flow hedges - (67) (67)

Transfer of TXU Fuel Company ownership. (73) - (73)

.': - - - _---_ _ I - - - - - __

Balance at September 30, 2004 .. . $3,886 $(177) $3,709 14 *......

14'

6. CONTINGENCIES Request from Commodities Futures Trading Commission (CFTC) On April 13, 2004, the CFTC issued a subpoena requiring TXU Corp. to produce information about storage of natural gas, including weekly and monthly storage reports to the Energy Information Administration submitted by TXU Fuel Company and TXU Gas.

The request sought information for the period of October 31, 2003 through January 2, 2004. TXU Corp. cooperated with the CFTC by producing the requested information and believes that TXU Gas and TXU Fuel Company have not engaged in any activity that would justify action against them by the CFTC. On August 30, 2004, the CFTC issued a press release confirming that its investigation, which included the investigation regarding gas storage reports, had been closed, and TXU Corp. has received nothing from the CFTC to indicate that the CFTC will take any action against TXU Gas or TXU Fuel Company.

Guarantees -- Energy has entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions. These guarantees have been grouped based on similar characteristics and are described in detail below.

Residual value guarantees in operating leases -- Energy is the lessee under various operating leases, entered into prior to January 1, 2003 that obligate it to guarantee the residual values of the leased facilities. At September 30, 2004, the aggregate maximum amount of residual values guaranteed was approximately $195 million with an estimated residual recovery of approximately $100 million. The average life of the lease portfolio is approximately seven years.

Debt obligations of the parent-- Energy has provided a guarantee of the obligations under TXU Corp.'s finance lease (approximately $120 million at September 30, 2004) for its headquarters building.

Shared saving guarantees -- As part of the operations of the strategic retail services business, which Energy intends to sell (see Note 3), Energy has guaranteed that certain customers will realize specified annual savings resulting from energy management services it has provided. In aggregate, the average annual savings have exceeded the annual savings guaranteed. The maximum potential annual payout is approximately $1 million and the maximum total potential payout is approximately $6 million. No shared savings guarantees were issued during the nine months ended September 30, 2004 that required recording a liability. The average remaining life of the portfolio is approximately seven years. These guarantees will be transferred or eliminated as part of expected transactions for the sale of the strategic retail services business.

Letters of credit -- Energy has entered into various agreements that require letters of credit for financial assurance purposes. Approximately $384 million of letters of credit were outstanding at September 30, 2004 to support existing floating rate pollution control revenue bond debt of approximately $376 million. The letters of credit are available to fund the payment of such debt obligations. These letters of credit expire in 2008.

Energy has outstanding letters of credit in the amount of $113 million to support hedging and risk management margin requirements in the normal course of business. As of September 30, 2004, approximately 84% of the obligations supported by these letters of credit mature within one year, and substantially all of the remainder mature in the next six years.

Surety bonds -- Energy has outstanding surety bonds of approximately $29 million to support performance under various subsidiary contracts and legal obligations in the normal course of business. The term of the surety bond obligations is approximately one year.

Legal Proceedings -- On July 7, 2003, a lawsuit was filed by Texas Commercial Energy (TCE) in the United States District Court for the Southern District of Texas, Corpus Christi Division, against Energy and certain of its subsidiaries, as well as various other wholesale market participants doing business in ERCOT. claiming generally that defendants engaged in market manipulation, in violation of antitrust and other laws, primarily during the period of extreme weather conditions in late February 2003. An amended complaint was filed in February 2004 that joined additional. unaffiliated defendants.

Three retail electric providers filed motions for leave to intervene in the action alleging claims substantially identical to TCE's. In addition, approximately 25 purported former customers of TCE filed a motion to intervene in the action alleging claims substantially identical to TCE's, both on their 15

own behalf and on behalf of a putative class of all former customers of TCE. An order granting Energy's Motion-to Dismiss based on the filed rate doctrine was entered on June 24, 2004. TCE has appealed the dismissal, however, Energy believes the dismissal of the antitrust claims was proper and that it has not committed any violation of the antitrust laws. Further, the Commission's investigation of the market conditions in late February 2003 has not resulted in any findings adverse to Energy. Accordingly, Energy believes that TCE's and the interveners' claims against Energy and its subsidiary companies are without merit and Energy and its subsidiaries intend to vigorously defend the lawsuit on appeal. Energy is, however, unable to estimate any possible loss or predict the outcome of this action.

I On April 28, 2003, a lawsuit was filed by a former employee of TXU Portfolio Management in the United States District-Court for the Northern District of Texas, Dallas Division, against TXU Corp., Energy and TXU Portfolio Management. The Court has reset this case for trial on June 6, 2005 and discovery in the case is proceeding. Plaintiff asserts claims under Section 806 of Sarbanes-Oxley arising from plaintiff's employment termination and claims for breach of contract relating to payment of certain bonuses. Plaintiff seeks back pay, payment of bonuses and alternatively, reinstatement or future compensation, including bonuses. Energy believes the plaintiff's claims are without merit.

The plaintiff was terminated as the result of a reduction in force, not as a reaction to any concerns the plaintiff had expressed, 'and plaintiff was not in a position with TXU Portfolio Management such that he had knowledge or information that would qualify the plaintiff to evaluate TXU'Corp.'s financial statements or assess the adequacy of TXU Corp.'s financial disclosures. Thus, Energy does not believe that there is any merit to the plaintiff's claims under Sarbanes-Oxley. TXU Corp., Energy and TXU Portfolio Management dispute the plaintiff's claims and intend to vigorously defend the litigation.

On March 10, 2003, a lawsuit was filed by Kimberly P. Killebrew in the United States District Court for the Eastern District of Texas, Lufkin Division, against TXU Corp. and TXU Portfolio Management, asserting generally that defendants engaged in manipulation of the wholesale electric market, in violation of antitrust and other laws. This case was transferred to the Beaumont Division of the Eastern District of Texas and on March 24, 2004 subsequently transferred to the Northern District of Texas,-Dallas Division. This action is brought by an individual, alleged to be a retail 'consumer of electricity, on behalf of herself and as a proposed representative of a putative class of retail purchasers of electricity that are similarly situated. Defendants have filed a motion to dismiss the lawsuit which is pending before the court; however, as a result of the dismissal of the antitrust claims in the litigation described above brought by TCE, the parties have agreed to stay this litigation until the appeal in the TCE case has been decided. Energy believes that the plaintiff lacks standing to assert any antitrust claims against TXU Corp. or TXU Portfolio Management, and that defendants have not violated antitrust laws or other laws as claimed by plaintiff. Therefore, Energy believes that plaintiff's claims are without merit and plans to vigorously defend the lawsuit. Energy is, however, unable to estimate any possible loss or predict the outcome of this action.

General -- In addition to the above, Energy is involved in various other legal and administrative proceedings in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect upon its financial position, results of operations or cash flows.

7. DERIVATIVES AND HEDGES As of September 30. 2004, it is expected that $68 million of after-tax net losses accumulated in other comprehensive income will be reclassified into earnings during the next twelve months. Of this amount, $62 million relates to commodity hedges and $6 million relates to financing-related hedges.

Energy experienced net hedge ineffectiveness of $4 million and $21 million, reported as a loss in revenues, for the three and nine months ended September 30, 2004, respectively. For the'three and nine months ended September 30, 2003, there were no hedge ineffectiveness losses.

The net effect of unrealized mark-tb-market ineffectiveness accounting (versus settlement accounting), which includes the above amounts as well as the effect of reversing unrealized gains and losses recorded in previous periods to offset realized gains and losses in the current period, totaled $3 million and

$20 million, respectively, in net losses for the three and nine months ended September 30, 2004 and $10 and $24 million 'in net gains for the three and nine months ended September 30, 2003.

16

8. SUPPLEMENTARY FINANCIAL INFOR.ATION Other Income and Deductions --

Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Other income:

Net gain on sale of properties and businesses. $ 35 $ 19 $ 48 $ 40 Other......................................... 1 1 2 3 Total other income......................... $ 36 $ 20 $ so $ 43

==

Other deductions:

Software write-off............................ $ (2) $ - $ 107 Employee severance charges.................... 3 _ 89 Spare parts inventory writedown............... _ 79 Equity in losses of unconsolidated entities... 8 _ 8 Expenses related to canceled construction projects.................................... 1 2 5 4 Casualty loss (gas storage explosion)......... S 5 Settlement of purchase power agreement........ 3 3 Loss on retirement of debt.................... 1 1 1 1 Other......................................... 1 1 4 4 Total other deductions..................... $ 20 $ 4 $ 301 $ 9 Severance Liability Related to Restructuring Activities Energy Liability for severance costs accrued as of June 30, 2004........... $ 84 Additions to liability....................................... 3 Payments charged against liability.............................. (53)

Liability for severance costs accrued as of September 30, 2004... $ 34 The above table excludes severance included in discontinued operations.

Interest Expense and Related Charges --

Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Interest (a)....................................... $ 68 $ 62 $ 197 $ 217 Distributions on preferred membership interests (b) 17 17 51 17 Amortization of discount and debt issuance costs... 9 6 21 17 Capitalized interest............................... (3) (2) (6) (5)

Total interest expense and related charges...... $ 91 $ 83 $ 263 $ 246 (a) Included in interest for the nine months ended September 30, 2003 is $34 million related to the exchangeable subordinated notes that were exchanged for preferred membership interests in July 2003.

(b) In April 2004, TXU Corp. purchased from the holders Energy's preferred membership interests, and subsequent to this purchase, Energy has paid distributions on the preferred membership interests to TXU Corp.

Affiliate Transactions - The following represent the significant affiliate transactions of Energy:

o Energy incurs electricity delivery fees charged by Electric Delivery.

For the three months ended September 30, 2004 and 2003, these fees totaled $417 million and $441 million, respectively. For the nine months ended September 30, 2004 and 2003, these fees totaled $1.1 billion and $1.2 billion, respectively.

o Energy records interest expense to Electric Delivery with respect to Electric Delivery's generation-related regulatory assets, which now consists entirely of the securitization bonds. The interest expense reimburses Electric Delivery for the interest expense Electric Delivery incurs on that portion of its debt associated with the generation-related regulatory assets. For the three months ended

September 30, 2004 and 2003, this interest expense totaled $15 million and $12 million, respectively. For the nine months ended September 30, 2004 and 2003, this interest expense totaled $40 nlillion and $36 million, respectiorely. F .-:.-.

17 .> - .;-

{ .. .

- -:' +

r f .

_ . , > z  :,

f  ;, - ..

. ' .; '1.-; ' '

. ' . ]

. F

• ' > '. X .' '

- W. . w , ¢ I .

4 , . . .

is .- ' ' ' F

. T t .. .. 4 ... . e S.'.' , " '

ffit t * . ...

\ .

• ' t ' L i, 4 at v v*; t

- r q s .

. .. . . l .

, . fi ^ _; _

- ' ' ' I '; '  !

X 1,

, ., - t ........... .. . . ..

- . r . l, .  :

, . , . ,, , A,

" ' ,,', 1 _,.

• t

o Under the terms of the settlement plan, Electric Delivery issued an initial $500 million of securitization bonds in 2003 and issued $790 million in June 2004. The incremental income taxes Electric Delivery will pay on the increased delivery fees to be charged to Electric Delivery's customers related to the bonds will be reimbursed by Energy.

Therefore, Energy's financial statements reflect a $437 million non-interest bearing payable to Electric Delivery (530 million of which is due currently) that will be extinguished as Electric Delivery pays the related income taxes.

o The average daily balances of short-term advances to affiliates during the three months ended September 30, 2004 was $1.5 billion and average daily short-term advances from affiliates during the three months ended September 30, 2003 was $47 million. Interest income earned on the advances for the three months ended September 30, 2004 was $10 million and interest expense incurred on the advances for the three months ended September 30, 2003 was $343 million. The weighted average interest rate for the three months ended September 30, 2004 and 2003 was 2.62V and 2.86%, respectively. The average daily balances of short-term advances to affiliates during the nine months ended September 30, 2004 were $905 million and average daily short-term advances from affiliates during the nine months ended September 30, 2003 was $500 million. Interest income earned on the advances for the nine months ended September 30, 2004 was $19 million and interest expense incurred on the advances for the nine months ended September 30, 2003 was $9 million. The weighted average interest rate for the nine months ended September 30, 2004 and 2003 was 2.77% and 2.76%,

respectively.

o TXU Business Services charges Energy for financial, accounting, environmental and other administrative services at cost. For the three months ended September 30, 2004 and 2003, these costs totaled $10 million and $54 million, respectively, and are primarily included in SG&A expenses. For the nine months ended September 30, 2004 and 2003, these costs totaled $144 million and $173 million, respectively.

Effective July 1, 2004, under the ten year services agreement with Capgemini several of the functions previously performed by TXU Business Services are now provided by Capgemini. Outsourced base support services performed by Capgemini for a fixed fee, subject to adjustment for volumes or other factors, include information technology, customer call center, billing, human resources, supply chain and certain accounting activities (See Note 1 for further discussion).

o Energy received payments from TXU Gas under a service agreement that began in 2002 and ended June 30, 2004 and covered customer billing and customer support services provided for TXU Gas. These revenues totaled

$15 million and $22 million for the nine months ended September 30, 2004 and 2003, respectively, and are included in other revenues. On October 1, 2004, TXU Corp. and Atmos Energy Corporation completed a merger by division in which Atmos Energy Corporation acquired TXU Gas' operations.

o Energy records the amount owed by Electric Delivery for the future costs of decommissioning the Comanche Peak nuclear facility as a non-current asset. Funds for decommissioning are collected monthly from Electric Delivery. Realized gains and other earnings on the nuclear decommissioning trust holdings reduce the non-current asset. As of September 30, 2004, the balance of the noncurrent asset related to the Comanche Peak nuclear facility asset retirement obligation was $42 million.

o In April 2004, TXU Corp. purchased from the holders Energy's exchangeable preferred membership interests, and as a result Energy has paid distributions to TXU Corp. on these securities, which remain outstanding, since the purchase. Interest expense and related charges associated with these securities, including amortization of the related discount, totaled $21 million for the three months ended September 30, 2004 and $37 million for the nine months ended September 30, 2004 since the date of TXU Corp.'s purchase of securities.

Pension and Other Postretirement Benefits -- Energy is a participating employer in the TXU Retirement Plan, a defined benefit pension plan sponsored by TXU Corp. Energy also participates with TXU Corp. and other affiliated subsidiaries of TXU Corp. to offer health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. The allocated net periodic pension cost and net periodic postretirement benefits cost other than pensions applicable to Energy was $12 million and $15 million for the three month periods ended September 30, 2004 and 2003, respectively and $43 million and $44 million for the nine months ended September 30, 2004 and 2003. respectively.

The Capgemini outsourcing transaction on July 1, 2004, (see Note 1) triggered a curtailment of the pension and postretirement plans and a remeasurement of the related liabilities. The effects of the remeasurement, which include an increase in the discount rate of 0.25%. as well as the Medicare Act enacted in December 2003, have resulted in lower pension and postretirement benefits expense.

13

Accounts Receivable -- At September.30, 2004 and December 31, 2003, accounts receivable of $989 million and $943 million are stated net of-allowance for uncollectible accounts of $40 million and $51 million, respectively. During the nine months ended September 30, 2004, bad debt expense was $76 million, account write-offs were $90 million and other activity increased the allowance for uncollectible accounts by $3 million. During the nine months ended September 30, 2003, bad debt expense was $68 million, account write-offs were $64 million and other activity decreased the allowance for uncollectible accounts by $4 million. Allowances related to receivables sold are reported in current liabilities and totaled $35 million and $39 million at September 30, 2004 and December 31, 2003, respectively.

Accounts receivable included $406 million and $388 million of unbilled revenues at September 30, 2004 and December.31, 2003, respectively.

Intangible Assets -- Intangible assets other than goodwill are comprised of the following:

As of September 30, 2004 As of December 31, 2003 Gross Gross Carrying Accumulated Carrying Accumulated Amount Amortization Net Amount Amortization Net Intangible assets subject to amortization included in property, plant and equipment:

Capitalized software placed in service (unrelated to outsourced activities at September 30, 2004) ...................... $ 3 $ 1 $ 2 $ 241 $ 112 $ 129 Land easements . .2 1 1 11 8 3 Mineral rights and other . .30 22 8 31 22 9 Total ................................... $ 35 $ 24 $ 11 $ 283 $ 142 $ 141 Aggregate Energy amortization expense for intangible assets for the three months ended September 30, 2004 and 2003 was less than $1 million and $10 million, respectively. Aggregate Energy amortization expense for intangible assets for the nine months ended September 30, 2004 and 2003 was $21 million and

$27 million, respectively. At September 30, 2004, the weighted average useful lives of capitalized software, land easements and mineral rights and other were 5 years, 54 years and 40 years, respectively.

During the second quarter of 2004, Energy transferred information technology assets, consisting primarily of capitalized software, to a subsidiary of TXU Corp at book value. See Note 1 for further discussion.

Goodwill of $517 million and $533 million at September 30, 2004 and December 31, 2003, respectively, was stated net of previously recorded accumulated amortization of $60 million. Energy transferred $16 million of goodwill to US Holdings in connection with the transfer of TXU Fuel Company to US Holdings on April 30, 2004.

Commodity Contracts -- At September 30, 2004 and December 31, 2003, current and noncurrent commodity contract assets, arising largely from mark-to-market accounting, totaled $936 million and $657 million, respectively, and are stated net of applicable credit (collection) and performance reserves totaling $23 million and $18 million, respectively. Performance reserves are provided for direct, incremental costs to settle the contracts. Current and non-current commodity contract liabilities totaled $854 million and $549 million at September 30, 2004 and December 31, 2003, respectively.

Inventories by Major Category --

September 30, December 31, 2004 2003 Materials and supplies .................................................... $ 133 $ 225 Fuel stock ................................................................ 79 78 Gas stored underground .................................................... 84 83 Total inventories ................................................... S 296 $ 386 19

As described in Note 1, Energy recorded a charge in the second quarter of

$79 million ($51 million after-tax) to write down spare parts and equipment inventory.

Property, Plant and Equipment -- At September 30, 2004 and December 31, 2003, property, plant and equipment of $9.8 billion and $10.3 billion is stated net of accumulated depreciation and amortization of $7.4 billion and $7.6 billion, respectively.

Supplemental Cash Flow Information -- See Note 1 regarding the effects of Capgemini being provided a royalty-free right, under an asset license arrangement, to use information technology assets, consisting primarily of capitalized software, which were noncash in nature. See Note 2 for the effects of adopting SFAS 143, which were noncash in nature. The transfer of TXU Fuel Company ownership as discussed in Note 5 was noncash in nature.

20

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM TXU Energy Company LLC:

We have reviewed the accompanying condensed consolidated balance sheet of TXU Energy Company LLC and subsidiaries (Energy) as of September 30, 2004, and the related condensed statements of consolidated income and of comprehensive income for the three-month and nine-month periods ended September 30, 2004 and 2003, and the condensed statements of consolidated cash flows for the nine-month periods ended September 30, 2004 and 2003. These interim financial-statements are the responsibility of Energy's management..-

We conducted our review in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit in accordance with standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Energy as of December 31. 2003, and the related statements of consolidated -

income, comprehensive income, cash flows and membership interests for the year then ended (not presented herein); and in our report (which includes an explanatory paragraph related to the rescission of Emerging Issues Task Force Issue No. 98-10), dated March 11, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, is fairly stated in all material-respects in relation to the consolidated balance sheet from which it has been derived.

DELOITTE E TOUCHE LLP Dallas, Texas November 12, 2004 21 -

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS BUSINESS Energy is a subsidiary of US Holdings, which is a subsidiary of TXU Corp.

Energy is engaged in electricity generation and retail and wholesale energy sales.

Energy currently has no reportable segments, however, management intends to realign its operations into two core business segments consisting of Power (the electricity production business) and Energy (the retail and wholesale energy sales and hedging and risk management operations) effective with reporting for the first quarter of 2005.

Strategic Initiatives and Other Actions -Mr. C. John Wilder, who was named president and chief executive of TXU Corp. in February 2004, and senior management have been reviewing the operations of TXU Corp. and have formulated certain strategic initiatives and continue to develop others. Areas being reviewed include:

o Performance in competitive markets, including profitability in new markets; o Cost structure, including organizational alignments and headcount; o Management of natural gas price risk and cost effectiveness of the generation fleet; and o Non-core business activities.

Energy anticipates performance improvements as a result of various strategic initiatives, including lower administrative support costs, more efficient and cost-effective utilization of generation-related assets and increased return on investments. As discussed below, implementation of the strategic initiatives as well as other actions taken to date have resulted in total charges of $8 million ($5 million after-tax) in the third quarter of 2004 and $284 million ($185 million after-tax) year-to-date, substantially all reported in other deductions, related to asset writedowns and employee severance. In the third quarter of 2004, Energy recorded gains on the disposition of properties, principally undeveloped land, totaling $18 million

($12 million after-tax), reported in other income.

Charges recorded in the three-month and nine-month periods ended September 30, 2004 and 2003 reported in other deductions are detailed in Note 8 to Financial Statements.

The review of Energy's operations and formulation of strategic initiatives is ongoing, and additional charges are expected. The phases of the plan resulting in the charges to date are anticipated to be largely completed in 2004. Upon completion of each phase of the plan, Energy expects to fully describe the actions intended to improve the financial performance of its operations. Certain of the strategic initiatives described below could result in additional material charges that Energy is currently unable to predict. In addition, other new strategic initiatives are likely to be undertaken that could also materially affect Energy's financial results.

Capgemini Energy Agreement On May 17, 2004, Energy entered into a services agreement with a subsidiary of Cap Gemini North America Inc., Capgemini Energy LP (Capgemini), a new company initially providing business process support services to TXU Corp.,

but immediately implementing a plan to offer similar services to other utility companies. Under the ten-year agreement, over 2,500 TXU Corp. employees (including approximately 1,100 from Energy) transferred to Capgemini effective July 1, 2004. Outsourced base support services performed by Capgemini for a fixed fee, subject to adjustment for volumes or other factors, include information technology, customer call center, billing and collections, human resources, supply chain and certain accounting activities. Energy expects that the Capgemini arrangement will result in lower costs and improved service levels.

As part of the agreements, Capgemini was provided a royalty-free right, under an asset license arrangement, to use information technology assets, consisting primarily of capitalized software. A portion of the software was in development and had not yet been placed in service by Energy. As a result of outsourcing its information technology activities, Energy no longer intends to develop the majority of these projects and from Energy's perspective the software is abandoned. The agreements with Capgemini do not 22

require that any software in development be completed and placed in service. Consequently, the carrying value of these software projects was written off, resulting in a charge of $107 million ($70 million after-tax) for the nine months ended September 30. 2004, reported in other deductions, essentially all of which was recorded in the second quarter of 2004. The remaining assets were transferred to a subsidiary of TXU Corp. at book value in exchange for an interest in that subsidiary. Such interest is accounted for by Energy on the equity method, and Energy recorded equity losses (representing depreciation expense) of $8 million in the third quarter of 2004, reported in other deductions.

The TXU Corp. subsidiary received a-2.9% limited partnership interest in Capgemini in exchange for the asset license described above. Energy and Electric Delivery have the right to sell (the 'put option") their interest in the subsidiary to Cap Gemini America Inc. for $200 million,.plus the subsidiary's share of Capgemini's undistributed earnings, upon expiration of the services agreement, or earlier upon the occurrence of certain unexpected events. Cap Gemini North America Inc. has the right to purchase Energy's and Electric Delivery's interests under the same terms and conditions. The partnership interest in Capgemini has been recorded at an-initial value of $2.9 million and is being accounted for on the cost-method.:;.

Energy has recorded its share of the fair value of the put option as a noncurrent asset largely offset by a reduction to the carrying value of the software transferred to the subsidiary, in accordance with the accounting principles related to sales and licensing of internally developed software described in AICPA Statement of Position 98-1, 'Accounting for the Costs of Computer Software Developed or Obtained for Internal Use."

Also as part of the services agreements, TXU Corp. agreed to indemnify Capgemini for severance costs incurred by Capgemini for former TXU Corp.

employees terminated within 18 months of -their transfer to Capgemini.

Accordingly, Energy recorded a $27 million ($18 million after-tax) charge for severance expense in the second quarter of 2004, which represents a reasonable estimate of the indemnity and is reported in other deductions. The charge includes an allocation of severance related to TXU Business Services Company employees. In addition, TXU Corp. committed to pay up to $25 million for costs associated with transitioning the outsourced activities to Capgemini. The transition costs applicable to Energy are expected to be largely recorded during the fourth quarter of 2004.

Transfer and Sale of TXU Fuel Company On April 30, 2004, Energy distributed the assets of TXU Fuel Company, its gas transportation subsidiary, to US Holdings at book value, including $16 million of allocated goodwill. On June 2, 2004, US Holdings completed the sale of the assets of TXU Fuel Company to Energy Transfer Partners, L.P. for $500 million in cash. The assets of TXU Fuel Company consisted of approximately 1,900 miles of intrastate pipeline and a total system capacity of 1.3 Bcf/day. As part of the transaction, Energy entered into a market-price based transportation agreement with the new owner to transport gas to Energy's generation plants.

Because of the continuing involvement in the business through the transportation agreement, the business has not been accounted for as a discontinued operation.

Facility Closures and Other Actions Related to Generation Operations On November 12, 2004, Energy announced plans to declare inactive, or

,mothball", eight natural gas-fired electric-generating units. The units represent a total of 2,516 megawatts (MW), or 25 percent of Energy's natural gas-fired generation capacity in Texas. The units are less efficient than others serving market demand. A severance charge, not yet estimated, related to this action is expected to be recorded in the fourth quarter of 2004.

On October 1, 2004, Energy entered into an agreement to terminate the operating lease for certain mining equipment for approximately $28 million in cash, effective November 1, 2004. The lease termination will result in an estimated net charge of approximately $21 million ($13 million after-tax) to be recorded in other deductions in the fourth quarter of 2004.

In the third quarter of 2004, Energy recorded gains totaling $18 million

($12 million after-tax) related to the sale of undeveloped land. The gains are reported in other income.

In the second quarter of 2004, Energy initiated a plan to sell the Pedricktown, New Jersey 122 MWpower production facility and exit the related power supply and gas transportation agreements. Accordingly, Energy recorded an impairment charge of $26 million ($17 million after-tax) to write down the facility to estimated fair market value. The results of the business and the impairment charge are reported in discontinued operations, as discussed in Note 3 to Financial Statements.

23

--- A-As part of Energy's review of its generation asset portfolio, Energy the completed a review of its spare parts and equipment inventory to determine appropriate level of such inventory. The review included nuclear, coal and gas-fired generation-related facilities. As a result of this review. Energy recorded a charge of $79 million ($51 million after-tax), reported in other deductions, in the second quarter of 2004 to reflect excess inventory on hand and to write down carrying values to scrap values.

In March 2004, Energy announced the planned permanent retirement, due completed in the second quarter of 2004, of eight gas-fired operating units to electric industry market conditions in Texas. Energy also temporarily closed The four other gas-fired units snd placed them under evaluation for retirement.

12 units represented a total of 1,471 MW, or more than 13%. of Energy's gas-fired generation capacity in Texas. A majority of the 12 units were designated as 'peaking units" and operated only during the summer for many years and have operated only sparingly during the last two years. Most of the units were built in the 1950's. Energy also determined that it would close its North Winfield Monticello lignite mine in Texas, and such closure has been of completed, as it is no longer economical to operate when compared to the cost purchasing coal to fuel the adjacent generation facility. A total charge of $8 million ($5 million after-tax) was recorded in the first quarter of 2004, reported in other deductions, for production employee severance costs (S7 million pre-tax) and impairments related to the various facility closures ($1 million pre-tax).

Organizational Realignment and Headcount Reductions Energy intends to realign its operations into two core business segments consisting of:

o Power - the electricity production business; and o Energy - the retail and wholesale energy sales and portfolio management operations.

Processes are currently being developed to report operating results of the Power and Energy business segments. (Only operating results for consolidated Energy are provided in this report.) Results are expected to be reported under the new segment alignment no later than the first quarter of 2005.

During the second quarter of 2004, management completed a comprehensive organizational review, including an analysis of staffing requirements. As a result, Energy completed a self-nomination severance program and finalized a plan for additional headcount reductions under an involuntary severance program, which has been largely completed. Accordingly, in the second quarter of 2004.

Energy recorded severance charges totaling $43 million ($28 million after-tax),

reported in other deductions.

Liability and Capital Management On November 4, 2004, Energy entered into a five-year revolving credit facility that allows for (i) bridge loans, (ii) revolving loans and (iii) letters of credit having a maturity of one year. Bridge loans may total up to

$500 million and will mature no later than October 31, 2005. Letters of credit may total up to $500 million, but in some instances require prepayment of bridge loans in an amount equal to the face value of the letter of credit. Revolving loans may total up to $250 million, but are only available after all bridge loans have been repaid. The aggregate amount of borrowings outstanding at any one time may not exceed $500 million. Energy intends to use this facility for general and corporate purposes, including, in the case of letters of credit, support for pollution control revenue bonds. In addition, pursuant to the terms of the five-year revolving credit facility, bridge loans may be used to loan or distribute funds to TXU Corp. for the repurchase of its common stock.

In April 2004, TXU Corp. purchased from the holders Energy's preferred membership interests with a liquidation value of $750 million. Energy's carrying amount of the security, which remains outstanding, is the $750 million liquidation amount less $242 million remaining unamortized discount and

$30 million in unamortized debt issuance costs.

24

See Note 4 to Financial Statements for further detail of financing arrangements.

Energy intends to utilize cash provided by operating activities in accordance with TXU Corp.'s priorities as follows:

o First, investments to preserve and enhance the quality of customer service and production reliability;=,

o Second, reinvestments in its businesses, applying stringent expectations for cash payback timelines and minimum return on investment; and - -

o Third, to reduce debt and other liabilities, with the objective of strengthening the balance sheet and increasing financial flexibility.

Investment in New Trading Entity In May 2004, Energy and Credit Suisse First Boston (USA), Inc. announced they had entered into a memorandum of understanding to establish a 50/50 investment in an energy marketing and trading entity. After a detailed review of the proposed venture, the parties were unable to agree on an economic arrangement that met each party's strategic objectives and in September 2004 announced a mutual agreement not to pursue the joint venture. Energy will continue to leverage its internal wholesale marketing and risk management capabilities to manage its purchased power needs and economically dispatch its generation fleet in the Texas market.

Strategic Review of Nuclear Assets Energy is currently undertaking a strategic review of its nuclear assets, comprised of two electricity generating units at Comanche Peak, each with a capacity of 1,150 MW. The objectives of this strategic review are to evaluate potential means to reduce the cost risk of outages of these low marginal cost facilities and improve the long-term availability and certainty of electricity supply for Energy's customers. Energy continues to identify and evaluate various potential initiatives as part of this review. Energy expects to complete the review within six months, and no determination has been made as to the likelihood of implementing any of the initiatives.

Consolidation of Real Estate Currently, TXU Corp. owns or leases more than 1.3 million square feet in various management and support office locations, which exceeds its anticipated needs. TXU Corp. has evaluated alternatives to reduce current office space and intends to consolidate into its existing headquarters building in Dallas, Texas, enhancing the facility to enable better employee communication and collaboration and cost effectiveness. Implementation of this initiative is expected to result in charges related to existing leased facilities in the fourth quarter of 2004 and the first quarter of 2005, but the amounts are not yet estimable.

Initiatives to Improve Production Reliability and Performance Energy is undertaking a number of initiatives to improve customer service, electricity production reliability and operational performance. These initiatives include:

o Investment of an additional $275 million over the next three years to improve reliability of coal and nuclear production assets, a 45%

increase in annual spending over the 2003 investment level; and o Replacement of four steam generators in one of the two units of the Comanche Peak nuclear plant in order to maintain the operating efficiency of the unit. Estimated capital requirements for this project are $175 million to $225 million, to be spent largely over the next three years.

25

--Il-RESULTS OF OPERATIONS All dollar amounts in Management's Discussion and Analysis of Financial Condition and Results of Operations and the tables therein are stated in millions of US dollars unless otherwise indicated.

The results of operations and the related management's discussion of those results for all periods presented reflect the discontinuance of the strategic retail services business and the Pedricktown. New Jersey generation facility operations of Energy (see Note 3 to Financial Statements regarding discontinued operations).

26

Operating Data Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Operating statistics - volumes:

Retail electricity sales volumes (GWh):

Historical service territory (a):

Residential .............................................. 9,760 10,991 24,24627,242 Small business (b) ....................................... 3,260 3,233 8,335 9,798 Total historical service territory ..................... 13,020 14,224 32,581 37,040 Other territories (a):

Residential .............................................. 1,096 648 2,345 1,446 Small business (b)....................................... 127 77 277 225 Total other territories ................................ 1,223 725 2,622 1,671 Large business and other customers ....................... 6,412 8,501 19,891 23,941 Total retail electricity ............................... 20,655 23,450 55,094 62,652 Wholesale electricity (Gwh) ................................. 11,929 10,402 36,653 26,145 Total retail and wholesale electricity sales volumes... 32,584 33.852 91,747 88,797 Production and purchased power volumes (GWh):

Nuclear (base load) ...................................... 5 ,036 4,455 13,882 13,608 Lignite/coal (base load) ................................. 11,437 11,441 31,863 30,272 Gas/oil .................................................. 1,983 4,048 4,300 11,870 Purchased power .......................................... 15,196 15,673 44,665 37,536 Total energy supply .................... 33,657 35,617 94,710 93,286 Less line loss and other ................. 1,073 1,765 2,963 4,489 Net energy supply volumes .............................. 32,584 33,852 91,747 88,797 Base load capacity factors t):

Nuclear ................... 99.5% 87.8% 92.1% 90.4%

Lignite/coal .............. 92.5t 92.8% 86.8% 83.2%

Customer counts:

Retail electricity customers (end of period and in thousands - based on number of meters):

Historical service territory (a):

Residential.............................................. 1,997 2,096 Small business (b)....................................... 313 318 Total historical service territory 2,310 2,414 Other territories (a)

Residential.............................................. 195 129 Small business (b)....................................... 6 4 Total other territories 201 133 Large business and other customers _______76 70 Total retail electricity customers 2,587 2,617 (a) Historical service and other territory data for 2003 are best estimates.

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

27

Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Operating revenues (millions of dollars):

Retail electricity revenues:

Historical service territory (a):

Residential.$.............................................. 1,073 1,086 $ 2,472 $ 2,506 Small business (b)....................................... 352 289 867 922 Total historical service territory ..................... 1,425 1,375 3,339 3,428 Other territories (a):

Residential .............................................. 113 54 228 126 Small business (b)....................................... 12 6 25 17 Total other territories ................................ 125 60 253 143 Large business and other customers ....................... 458 551 1,366 1,488 Total retail electricity revenues ........................... 2,008 1,986 4,958 5,059 Wholesale electricity revenues .............................. 487 399 1,429 914 Hedging and risk management activities ...................... (64) 4 (61) 139 Other revenues .............................................. 86 48 263 131 Total operating revenues ............................... $2,517 $ 2,437 5 6,589 $ 6,243 Weather (average for service territory)(c)

Percent of normal:

Cooling degree days .................................... 85.5% 94.0% 87.91 94.6%

Heating degree days .................................... - - 91.8t 109.4*

(a) Historical service and other territory data for 2003 are best estimates.

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

(c) 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).

28

Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Fuel and purchased power costs ($/MWh of supply)

Nuclear generation ........................................ $ 4.32 $ 4.75 $ 4.33 $ 4.47 Lignite/coal generation .................................. $ 12.33 $ 11.89 $ 12.64 $12.54 Gas/oil generation and purchased power................... $ 53.03 $ 48.38 $ 48.05 $48.34 Average total electricity supply ....................... $ 31.95 $ 31.23 $ 29.77 $30.35 Average retail volume (KWh)/customer (calculated using average no. of customers for period)

Residential ..................................... ......... 4,921 5,204 12,091 12,673 Small business ................... .............. 10,530 10,183 26,905 30,599 Large business and other customers...-.'. .; ..... .... 83,907 119,337 274,470 325,248 Average revenues ($/MWh)

Residential . $ 97,99

$109.21 $101.56 $91.72 Small business ........................................... $107.45 $ 89.13 $103.57 $93.71 Large business and other customers ....................... $ 71.47 $ 64.85 $ 68.67 $62.14 Average delivery fees ($/MWh) $ 22.06 $ 18.19 $ 21.76 $18.59 Estimated share of ERCOT retail markets (based on number of meters)

Historical service territory (a):

Residential (b)....................................... 83% 88%

Small business (b)...................................... 1% 84%

Total ERCOT Residential (b)....................................... 45% 46%

Small business (b)...................................... 32% 33%

Large business and other customers (c) .................... 33% 39%

Hedging and risk management activities Net unrealized mark-to-market gains/(losses) ............... $ (15) $ 11 $ (46) $ 58 Realized gains/(losses)................ (49) (7) (15) 81 Total .................................................. $ (64) $ 4 $ (61) $ 139

...... .. .A.. = =..... =..=

(a) Historical service and other territory data for 2003 are best estimates.

(b) Estimated market share is based on the number of customers that have choice. -. _

(c) Estimated market share is based on the annualized consumption for this overall market. -' K Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003 -

operating revenues increased $80 million, or 3%, to S2.5 billion in 2004.

Retail electricity revenues increased $22million, or 1%, to $2.0 billion reflecting a $258 million increase due to higher average pricing, partially offset by a $236 million decline due to lower volumes. A 12% drop in sales volumes was driven by the effect of competitive activity, primarily in the large business market, and milder weather. Lower business market volumes also reflected a strategy to target higher margin customer segments. Milder weather contributed an estimated 6 percentage points to the volume decline. Higher pricing reflected increased price-to-beatrates, reflecting regulatory approved fuel factor increases, and higher pricing in the competitive large business market, both resulting from higher natural gas prices. Retail electricity customer counts at September 30, 2004 declined 1% from September 30, 2003.

Wholesale electricity revenues grew $88 million, or 22%, to $487 million reflecting a $58 million increase attributable-to a 15% rise in sales volumes and a $30 million increase due to the effect of increased natural gas prices on wholesale prices. The increase in wholesale sales volumes also reflected a partial shift in the customer base from retail to wholesale services, particularly in the business market.

29

- -- u Net results from hedging and risk management activities, which are reported in revenues and include both realized and unrealized gains and losses, declined $68 million from a net gain of $4 million in 2003 to a net loss of $64 million in 2004. Because the hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy sold, the changes in such results should not be viewed in isolation, but taken together with the effects of pricing and cost changes on gross margin. Changes in these results reflect market price movements on commodity positions held to hedge gross margin. The decline included $22 million in mark-to-market losses associated with required capacity auctions, $17 million primarily reflecting increased credit reserves due to the effect of increased natural gas prices on contracts and $15 million in mark-to-market losses associated with market price movements against hedges of gas in storage. Results from these activities included the net effect of recording unrealized gains and losses under mark-to-market accounting, versus settlement accounting, of $15 million in net losses in 2004 and net gains of $11 million in 2003. The majority of Energy's natural gas physical sales and purchases are in the wholesale markets and essentially represent hedging activities. These activities are accounted for on a net basis with the exception of retail sales to business customers, which effective October 1, 2003 are reported gross in accordance with new accounting rules and totaled $38 million in revenues for the third quarter of 2004. The increase in other revenues of $38 million to $86 million was driven by this change.

Gross Margin Three Months Ended September 30,

%of  % of 2004 Revenue 2003 Revenue Operating revenues ..................................... $ 2,517 1001 $ 2,437 100%

costs and expenses:

Cost of energy sold, including delivery fees ...... 1,556 62% 1,539 63%

Operating costs ................................... 145 6% 164 7%

Depreciation and amortization related to generation assets ............................. 82 3% 89 4%

Gross margin ........................................... $ 734 29% $ 645 26%

Gross margin is considered a key operating metric as it measures the effect of changes in sales volumes and pricing versus the variable and fixed costs of energy sold.

Gross margin increased $89 million, or 14%, to $734 million in 2004. The margin increase was driven by the higher average pricing, partially offset by lower results from hedging and risk management activities, and the unfavorable effects of a volume mix shift from higher margin retail sales to wholesale sales, higher delivery fees and milder weather. The average cost of total power produced and purchased was up 2%, reflecting improved utilization of base-load (nuclear and lignite-fired) production and improved sourcing of purchased power versus gas-fired generation to largely offset the effects of higher natural gas prices. Gross margin was also favorably impacted by lower depreciation as discussed immediately below.

Operating costs decreased $19 million, or 12%, to $145 million in 2004.

The decrease reflected $10 million related to customer care support services previously provided to TXU Gas (largely offset by lower related revenues), and

$5 million due to the absence of the gas transportation subsidiary sold in June 2004 (largely offset by higher cost of energy sold related to gas-fired production). Other changes in operating costs were individually immaterial and largely offsetting.

Depreciation and amortization related to generation assets decreased $7 million, or 8%, to $82 million, reflecting a decrease of $11 million due to extensions of estimated average depreciable lives of lignite and nuclear generation facilities, assets to better reflect their useful lives, partially offset by the effect of mining activity and the related asset retirement obligation.

Depreciation and amortization not included in gross margin totaled $1 million and $11 million for the three months ended September 30, 2004 and 2003, respectively. This decline primarily reflected the transfer of information technology assets, principally capitalized software, to an affiliate in connection with the Capgemini transaction.

30

SG&A expenses increased $16 million, or 101, to $182 million in 2004 primarily reflecting a $14 million special compensation incentive program expense related to trading activities and $12.million in higher deferred incentive compensation expense due to the increase in the price of TXU Corp.

common stock, partially offset by $6 million in reduced marketing costs outside the historical service territory and a $4 million decrease in bad debt expense.

Other income increased by $16 million to $36 million in 2004. Other income in 2004 included an $18 million gain on sale of undeveloped land. Other income in both 2004 and 2003 reflected $18 million of amortization of a gain on the sale of two generation plants in 2002.

Other deductions increased by $16 million to $20 million in 2004. Other deductions in 2004 consisted largely of $8 million in equity losses (representing depreciation expense) in theTXU Corp. entity holding the capitalized software licensed to Capgemini,;a.$5 million natural gas inventory loss resulting from an explosion at:a third-party storage facility and approximately $3 million to settle a power purchase agreement.

Interest income increased by $12 million to $13 million in 2004 primarily due to higher average advances to affiliates.: I Interest expense and related charges increased by $8 million, or 10%, to

$91 million in 2004. The increase reflected $18 million due to higher average debt levels and $2 million representing higher interest reimbursement to Electric Delivery related to securitized regulatory assets partially offset by

$11 million due to lower average interest rates and $1 million in interest reimbursed to Electric Delivery in 2003 related to the excess mitigation credit that ceased at the end of 2003.

The effective income tax rate was 33.0% in 2004 and 2003. There were no material unusual items affecting the comparison.

Results from continuing operations increased $59 million to $309 million in 2004, reflecting the increase in gross margin partially offset by higher SG&A. Net pension and postretirement benefit costs reduced results from continuing operations by $8 million in 2004 and $9 million in 2003. The decrease in these costs reflects a remeasurement of these liabilities as a result of the transfer of Energy employees to Capgemini and an increase of 0.25% in the discount rate due to higher interest rates, as well as the effects of the Medicare Act enacted in December 2003.

Loss from discontinued operations (see Note 3 to Financial Statements) was

$3 million in 2004 compared to $1 million in 2003. The 2004 loss primarily reflected costs to complete a services contract.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003 Operating revenues increased $346 million, or 6%, to $6.6 billion in 2004.

Retail electricity revenues decreased $101 million, or 2%, to $5.0 billion. This decline reflected a $611 million decrease attributable to a 12% drop in sales volumes, driven by the effect of competitive activity and milder weather, partially offset by a $510 million increase due to higher average pricing. Lower business market volumes also reflected a strategy.to target higher margin customer segments. Higher pricing reflected increased price-to-beat rates, reflecting regulatory approved fuel factor increases, and higher pricing in the competitive large business market, both resulting from higher natural gas prices. Retail electricity customer counts atSeptember 30, 2004 declined 1%

from September 30, 2003. Wholesale electricity revenues grew $515 million, or 56%, to $1.4 billion reflecting a $367 million increase attributable to a 40%

rise in sales volumes and a $148 million increase due to the effect of increased natural gas prices on wholesale prices; Higher wholesale electricity sales volumes reflected the establishment of the new northeast zone in ERCOT. Because Energy has a generation plant and a relatively small retail customer base in the new zone, wholesale sales have increased, and wholesale power purchases also increased to meet retail sales demand in other zones. The increase in wholesale sales volumes also reflected a partial shift in the customer base from retail to wholesale services, particularly in the business market.

31

-- Il-Net results from hedging and risk management activities, which are and unrealized gains and losses.

reported in revenues and include both realized in 2003 to a net loss of declined $200 million from a net gain of $139 million in 2004. Because the hedging activities are intended to mitigate the

$61 million and cost of energy sold, the risk of commodity price movements on revenues isolation, but rather taken changes in such results should not be viewed in changes on gross margin, Changes together with the effects of pricing and cost on commodity positions held to in these results reflect market price movements in mark-to-market losses hedge gross margin. The decline included $22 million in increased reserves, associated with required capacity auctions, $17 million to the effect of increased primarily reflecting increased credit reserves due losses natural gas prices on contracts and $15 million in mark-to-market of gas in storage. The associated with market price movements against hedges storage and retail gas comparison also reflected $34 million of additional gas in 2003, primarily related to businesses sold in late 2003, $18 business margin in 2003 and $11 million due to a favorable settlement with a counterparty Results from million in gains on contracts that are no longer marked-to-market.gains and unrealized these activities included the net effect of recording accounting, of $46 losses under mark-to-market accounting, versus settlement in 2003. The majority million in net losses in 2004 and net gains of $58 million in the wholesale of Energy's natural gas physical sales and purchases are activities are markets and essentially represent hedging activities. These sales to business accounted for on a net basis with the exception of retail in accordance with customers, which effective October 1, 2003 are reported gross the first nine for new accounting rules and totaled $126 million in revenues to $263 million months of 2004. The increase in other revenues of $132 million in 2004 was primarily driven by this change.

Gross Margin Nine Months Ended September 30,

% of I of 2004 Revenue 2003 Revenue

$ 6,589 100% S 6,243 100%

Operating revenues .....................................

4,157 63% 4,037 65V cost of energy sold and delivery fees ............. 8% 506 at Operating costs ................................... 513 Depreciation and amortization related to 4% 277 4%

generation assets ............................. 246

$ 1,673 25% S 1,423 23%

Gross margin ...........................................

The Gross margin increased $250 million, or 18%, to $1.7 billion in 2004.

offset by margin increase was driven by the higher average pricing, partially lower results from hedging and risk management activities, and the unfavorable effects of a volume mix shift from higher margin retail sales to wholesale total power salem, higher delivery fees and milder weather. The average cost of base load produced and purchased declined 2%, reflecting improved utilization of power (nuclear and lignite-fired) production and improved sourcing of purchased prices.

versus gas-fired generation to offset the effects of higher natural gas Gross margin was also favorably impacted by lower depreciation as discussed below.

Operating costs increased $7 million, orIt, to $513 million in 2004. The and component increase reflected $31 million in incremental testing, inspection the nuclear repair costs associated with the planned outage for refueling at maintenance facility, partially offset by lower spending for other repair and projects.Operating costs reflected decline of $10 million related to customer by lower care support services previously provided to TXU Gas (largely offset transportation related revenues), and $7 million due to the absence of the gas sold subsidiary sold in June 2004 (largely offset by higher costs of energy related to gas-fired production). Other changes in operating costs were individually immaterial and largely offsetting.

Depreciation and amortization related to generation assets decreased $31 to million, or 11%, to $246 million, reflecting a decrease of $45 million due extensions of estimated average depreciable lives of lignite and nuclear partially generation facilities' assets to better reflect their useful lives, offset by the effect of mining activity and the related asset retirement obligation.

Depreciation and amortization not included in gross margin totaled $22 and 2003, million and $29 million for the nine months ended September 30, 2004 respectively. The decrease reflected the effect of the transfer of information in technology assets, principally capitalized software, to an affiliate of connection with the Capgemini transaction, partially offset by acceleration the amortization of certain software to reflect a shorter useful life.

32

SG&A expenses increased $35 million, or 8%, to $491 million in 2004 reflecting $29 million of higher deferred incentive compensation expense due to the increase in the price of TXU Corp. common stock, a $14 million special incentive compensation program expense related to trading activities, $11 million in staffing and other costs to improve customer call center service and higher bad debt expense of $8 million primarily reflecting a favorable settlement in 2003, partially offset by-$7.million from various cost reduction initiatives, $6 million in reduced pension and-postretirement benefit costs and

$4 million in reduced marketing costs outside the historical service territory.

Other income increased by $7 million to $50 million in 2004. Other income in 2004 included an $18 million gain on sale of undeveloped property. Other income in both 2004 and 2003 reflected $30 million of amortization of a gain on the sale of two generation plants in 2002.

Other deductions increased $292 million to $301 million in 2004. Other deductions in 2004 consist largely of $107 million for software writedowns, $89 million for employee severance and $79 million in spare parts inventory writedowns, all discussed above under Strategic Initiatives and Other Actions."

Other deductions also reflected $8 million in equity losses (representing depreciation expense) in the TXU Corp. entity holding the capitalized software licensed to Capgemini, a $5 million natural gas inventory loss resulting from an explosion at a third-party storage facility'and approximately $3 million to settle a power purchase agreement.

Interest income increased by $18 million to $21 million in 2004 primarily due to higher average advances to affiliates.

Interest expense and related charges increased by $17 million, or 7%, to

$263 million in 2004. The increase reflected $28 million due to higher average debt levels and $4 million representing higher interest reimbursement to Electric Delivery related to securitized regulatory assets, partially offset by 9 million due to lower average interest rates and $6 million in interest reimbursed to Electric Delivery in 2003 related to the excess mitigation credit that ceased at the end of 2003.

The effective income tax rate decreased to 30.5% in 2004 from 31.8% in 2003 driven by the effects of ongoing tax benefits of depletion allowances and amortization of investment tax credits ona lower income base in 2004.

Income from continuing operations before cumulative effect of changes in accounting principles decreased $32 million.to $408 million in 2004, reflecting the increase in other deductions and SG&A expenses, partially offset by the higher gross margin. Net pension and postretirement benefit costs reduced.income from continuing operations by $27 million in each of 2004 and 2003. The decrease in these costs reflects a remeasurement of these liabilities as a result of the transfer of Energy employees to Capgemini and an increase of 0.25% in the discount rate due to higher interest rates, as well as the effects of the Medicare Act enacted in December 2003.

Loss from discontinued operations (see Note 3 to Financial Statements) was

$33 million in 2004 compared to $2 million in 2003. The 2004 loss reflected a

$17 million after-tax impairment charge related to the Pedricktown, New Jersey generation facility, a $6 million after-tax charge to settle a contract dispute in the strategic retail services business and $6 million after-tax in costs to complete various strategic retail services contracts.

33 2

COMMODITY CONTRACTS AND MARK-TO-MARKET ACTIVITIES The table below summarizes the changes in commodity contract assets and liabilities for the three and nine months ended September 30, 2004. The net change in these assets and liabilities, excluding other activity" as described below, represents the net effect of recording unrealized gains/(losses) under mark-to-market accounting, versus settlement accounting, for positions in the commodity contract portfolio. These positions consist largely of economic hedge transactions, with speculative trading representing a small fraction of the activity.

Three Months Nine Months Ended Ended September 30, September 30, 2004 2004 Balance of net commodity contract assets at beginning of period ............... $ 87 $ 108 Settlements of positions included in the opening balance (1) . ....... (7) (46)

Unrealized mark-to-market valuations of positions held at end of period (2)... (5) 20 Net other activity 13).......................................................... 7 -

salance of net commodity contract assets at end of period ..................... $ 82 $ 82 (1) Represents unrealized mark-to-market valuations of these positions recognized in earnings as of the beginning of the period.

(2) There were no significant changes in fair value attributable to changes in valuation techniques.

(3) Includes initial values of positions involving the receipt or payment of cash or other consideration, such as option premiums and the amortization of such values. These activities have no effect on unrealized mark-to-market valuations.

In addition to the net effect of recording unrealized mark-to-market gains and losses that are reflected in changes in commodity contract assets and liabilities, similar effects arise in the recording of unrealized ineffectiveness mark-to-market gains and losses associated with commodity-related cash flow hedges, which are reflected in changes in cash flow hedge and other derivative assets and liabilities. The total net effect of recording unrealized gains and losses under mark-to-market accounting, versus settlement accounting, is summarized as follows:

Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Operating revenues:

Unrealized gains/glosses) related to commodity contract portfolio.. $ (12) $ 1 $ (26) $ 34 Ineffectiveness gains/(losses) related to cash flow hedges ....... (3) 10 (201 24 Total unrealized gains/losses) ................................... $ (15) $ 11 S (46) $ 58 These amounts are included in the 'hedging and risk management activities, component of revenues.

34

Maturity Table -- Of the net commodity contract asset balance above at September 30, 2004, the amount representing unrealized mark-to-market net gains that have been recognized in current and prior years! earnings is $96 million.

The offsetting net liability of $14 million included in the September 30, 2004 balance sheet is comprised principally-of amounts representing current and prior years' net receipts of cash or other consideration, including option premiums, associated with contract positions, net-of any amortization. The following table presents the unrealized mark-to-market balance at September 30, 2004, scheduled by contractual settlement dates of the underlying positions.

Maturity dates of unrealized net mark-to-market balances at September 30, 2004 Maturity less -Maturity in than,. Maturity of Maturity of Excess of Source of fair value I year . 1-3 years 4-5 years 5 years Total Prices actively quoted........... 88* $ - -- , $- _- $ B8 Prices provided by other external sources............. 76 - (86) 10 (3) (3)

Prices based on models........... 12 (1) 11 Total............................ $176 $(87) $10 $ (3) $ 96 Percentage of total fair value... 183t (90) 10;% (3)V 100%

As the above table indicates, 93% of the'unrealized mark-to-market valuations at September 30, 2004 mature within three years. This is reflective of the terms of the positions and the methodologies employed in valuing positions for periods where there is less market liquidity and visibility. The

'prices actively quoted, category reflects only exchange traded contracts with active quotes available. The 'prices provided by other external sources" category represents forward commodity positions at locations for which over-the-counter broker quotes are available. Over-the-counter quotes for power and natural gas generally extend through 2005 and 2010, respectively. The "prices based on models" category contains the value of all non-exchange traded options, valued using industry accepted option pricing models. In addition, this category contains other contractual arrangements which may have both forward and option components. In many instances; these 'contracts can be broken down into their component parts and modeled as simple forwards and options based on prices actively quoted. As the modeled value is ultimately the result of a combination of prices from two or more different instruments,'it has been included in this category. -

COMPREHENSIVE INCOME Cash flow hedge activity reported in other comprehensive income from continuing operations included:

Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Cash flow hedge activity (net of tax): V , -,

Net change in fair value of hedges-gains/Closses):

Commodities.............................................. $ (12) $ (20) $ (87) $ (118)

Losses realized in earnings (net of tax): ,_ ,

Commodities.............................................. 6 45 16 113 Financing - interest rate swaps ............................. 2 1 4 4

- 8 46 20 117 Effect of cash flow hedges reported in comprehensive results related to continuing operations ................. (4) $ 26 $ (67) $ (1)

- I .

35

__ __1L_

FINANCIAL CONDITION LIQUIDITY AND CAPITAL RESOURCES Cash Flows -- Cash flows provided by operating activities for the nine months ended September 30, 2004 decreased $241 million to $788 million compared to the nine-month period ended September 30, 2003. The decrease reflected unfavorable working capital (accounts receivable, accounts payable and inventories) changes of $200 million due largely to the effect of higher collections in 2003 following billing delays experienced during the transition to competition, $137 million in higher margin deposits associated with hedging activities and $103 million in higher tax payments in 2004. partially offset by higher cash earnings (net income adjusted for the significant noncash items identified in the statement of cash flows) of $223 million.

Cash flows used in financing activities for 2004 were $605 million compared to $1.4 billion for 2003. The activity in 2004 primarily reflected advances to affiliates of $1.2 billion and distributions to US Holdings of $525 million, partially offset by net cash provided by debt issuances and retirements of $556 million and bank borrowings of $565 million. The activity in 2003 reflected repayments of advances from affiliates of $1.6 billion, cash distributions to US Holdings of $575 million and payment of bank borrowings of

$282 million, partially offset by net cash provided by debt issuances and retirements of $1.1 billion.

Cash flows used in investing activities were $156 million in 2004 and $158 million in 2003. Capital expenditures, including nuclear fuel, increased by $27 million in 2004 from $168 million in 2003, driven by the timing of nuclear refueling activities. Proceeds from the sale of undeveloped land provided $18 million in 2004 and the sale of certain retail commercial and industrial gas operations provided $19 million in 2003. Investing activities in 2004 also included $22 million in cash from the settlement of interest rate swaps.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $47 million.

This difference represents amortization of nuclear fuel, which is reported as cost of energy sold in the statement of income consistent with industry practice.

Financing Activities Over the next twelve months, Energy and its subsidiaries will need to fund ongoing working capital requirements and maturities of debt. Energy and its subsidiaries have funded or intend to fund these requirements through cash on hand, cash flows from operations, the sale of assets, short-term credit facilities and the issuance of long-term debt or other securities.

Long-Term Debt Activity -- During the nine months ended September 30, 2004, Energy issued, redeemed, reacquired or made scheduled principal payments on long-term debt as follows:

Issuances Retirements Pollution control revenue bonds .................. $ - $ 222 Senior notes ................... 800 -

Other ..................... - 7 Total ......................................... $ 800 $ 229 See Note 4 to Financial Statements for further detail of debt issuance and retirements, financing arrangements and capitalization.

Capitalization -- The capitalization ratios of Energy at September 30, 2004, consisted of long-term debt (less amounts due currently) of 46%, preferred membership interests held by TXU Corp. (net of unamortized discount balance of

$242 million) of 7% and membership interests of 47%.

Short-term Borrowings --At September 30, 2004, Energy had outstanding short-term borrowings consisting of bank borrowings under the three-year revolving credit facility of $565 million at a weighted average interest rate of 4.2'%. At December 31. 2003, Energy had no short-term borrowings outstanding.

Credit Facilities -- Energy and Electric Delivery have ongoing credit facilities totaling $2.5 billion of which $565 million had been borrowed by Energy at September 30, 2004 under the three-year revolving credit facility expiring in June 2007. These credit facilities and a TXU Corp. $500 million five-year revolving credit facility are used for working capital and general corporate purposes and support issuances of letters of credit. See Note 4 to Financial Statements for details of the arrangements.

36

Sale of Receivables -- TXU Corp. has established an accounts receivable securitization program. The activity under this program is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy remote direct subsidiary of TXU Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions. All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding to Energy under the program at September 30, 2004 and December 31, 2003 totaled $629 million and $504 million, respectively. See Note 4 to Financial Statements for a more complete description of the program including the financial impact on earnings and cash flows for the periods presented and the contingencies that could result in termination of the program....

Cash and Cash Equivalents -- Cash on hand totaled $5 million and $18 million at September 30, 2004 and December 31, 2003, respectively.

Credit Ratings -- The current credit ratings for TXU Corp. and certain of its subsidiaries are presented below:

TXU Corp. US Holdings Electric Delivery Electric Delivery Energy (Senior Unsecured) (Senior Unsecured) (Secured) (Senior Unsecured) (Senior Unsecured) s BEB- 'BB-- BB EBB- EBB Moody's .al Baa3 Baal Baa2 Eaa2 Fitch .BB- BBB- A-/BBBs BBB+ BB Moody's and Fitch currently maintain a stable outlook for TXU Corp., US Holdings, Energy and Electric Delivery. Electric Delivery first mortgage bonds are rated A- and its senior secured notes are rated BBB+ by Fitch. S&P currently maintains a negative outlook for each'such'entity.

These ratings are investment grade,-eexcept for Moody's rating of TXU Corp.'s senior unsecured debt, which is one notch below investment grade.

A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward at any time by a rating agency if such rating agency decides that circumstances warrant.such a change.

Financial Covenants, Credit Rating Provisions 'and Cross Default Provisions The terms of certain financing arrangements of'Energy contain financial covenants that require maintenance of specified fixed charge'coverage ratios, membership interests to total capitalization ratios and leverage ratios and/or contain minimum net worth covenants. As of September 30, 2004, Energy was in compliance with all such applicable covenants.

Certain financing and other arrangements of Energy and its subsidiaries contain provisions that are specifically affected by changes in credit ratings and also include cross default provisions. The material credit rating and cross default provisions are described below. ' '"'

Other agreements of Energy, including some of the credit facilities discussed above, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the credit ratings of Energy or its subsidiaries. ' ' '

Credit Rating Covenants Energy has provided a guarantee of the obligations under TXU Corp.'s lease (approximately $120 million at September. 30, 2004) for its headquarters building. In the event-of a downgrade of'Energy's credit'rating to below investment grade, a letter of credit would need to be provided within 30 days of any such rating decline.

37

-- - -l Energy has entered into certain commodity contracts and lease arrangements that in some instances give the other party the right, but not the obligation, to request Energy to post collateral in the event that its credit rating falls below investment grade. Based on its current commodity contract positions, if Energy were downgraded below investment grade by any specified rating agency, counterparties would have the option to request Energy to post additional collateral of approximately $182 million.

In addition, Energy has a number of other contractual arrangements under which the counterparties would have the right to request Energy to post collateral. The amount Energy would post under these transactions depends in part on the value of the contracts at that time and Energy's rating by each of the three rating agencies. As of September 30, 2004, based on current contract values, the maximum Energy would post for these transactions is $170 million. Of this amount, $150 million relates to one specific counterparty that would require Energy to post collateral if all three rating agencies downgraded Energy to below investment grade.

Energy is also the obligor on leases aggregating $158 million. Under the terms of those leases, if Energy's credit rating were downgraded to below investment grade by any specified rating agency, Energy could be required to sell the assets, assign the leases to a new obligor that is investment grade, post a letter of credit or defease the leases.

Cross Default Provisions Certain financing arrangements contain provisions that would 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 would result in an acceleration of payments due. Such provisions are referred to as 'cross default, provisions.

A default by TXU Corp. on indebtedness with a principal amount in excess of $50 million would result in a cross default under its $500 million five-year revolving credit facility expiring August 2008, which facility is also made available to Energy.

A default by TXU Corp., Energy or Electric Delivery in respect of indebtedness in a principal amount in excess of $50 million would result in a cross default under TXU Corp.'s new $2.3 billion, 364 day credit facility.

A default by Energy or Electric Delivery or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million would result in a cross default for such party under the $2.5 billion joint credit facilities expiring in June 2005, 2007 and 2009. Under these credit facilities, a default by Energy or any subsidiary thereof would cause the maturity of outstanding balances under such facility to be accelerated as to Energy but not as to Electric Delivery. Also, under this credit facility, a default by Electric Delivery or any subsidiary thereof would cause the maturity of outstanding balances under such facility to be accelerated as to Electric Delivery but not as to Energy.

A default by US Holdings or any subsidiary thereof on financing arrangements of $50 million or more would result in a cross default under the

$30 million of TXU Mining (a subsidiary of Energy) senior notes, which have a $1 million cross default threshold.

A default by Energy in respect of indebtedness in a principal amount in excess of $50 million would result in a cross default under its new $500 million five year credit facility.

Energy has entered into certain mining and equipment leasing arrangements aggregating $109 million that would terminate upon the default of any other obligations of Energy owed to the lessor. In the event of a default by TXU Mining on indebtedness in excess of $1 million, a cross default would result under the $30 million TXU Mining leveraged lease and the lease could terminate.

The accounts receivable program also contains a cross default provision with a threshold of $50 million applicable to each of the originators under the program. TXU Receivables Company and TXU Business Services each have a cross default threshold of $50,000. If either an originator, TXU Business Services or TXU Receivables Company defaults on indebtedness of the applicable threshold.

the facility could terminate.

38

Energy enters into energy-related contracts, the master forms of which contain provisions whereby an event of default-would occur if Energy were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. -

Energy and its subsidiaries have other arrangements, including leases with cross default provisions, the triggering of which would not result in a significant effect on liquidity. --  :

Long-term Contractual Obligations and Commitments -- The table below reflects updates of amounts presented in Energy's 2003 Form 10-K to reflect the obligation under the business services outsourcing agreement with Capgemini, changes in purchase obligations, and the repayment of debt and other instruments as discussed in Note 1 to Financial Statements.

Contractual Cash Obligations One to Three to More

- Less Than Three Five Than Five One Year Years Years Years Long-term debt and preferred membershipinterest -

Principal and interest/dividends .$ 281 $1,266 $ 687 $5,358 Lease obligations .................. 74 145 144 412 Purchase obligations ...... 2,265

............1,598 489 455 Business services outsourcing obligations . .... 182 334 334 793 Pension and other postretirement liabilities 45 89 89 45 Total contractual cash obligations ... $2,847 $3,432 $1,743 $7,063 OFF BALANCE SHEET ARRANGEMENTS TXU Corp.'s accounts receivable securitization program is discussed in Note 4 to Financial Statements.

COMMITMENTS AND CONTINGENCIES Guarantees -- See Note 6 to Financial Statements for details of contingencies, including guarantees.

REGULATION AND RATES - '

Price-to-Beat Rates - Under the 1999 Restructuring Legislation, Energy is required to continue to charge a price-to-beat rate established by the Commission to residential customers in the historical service territory. Energy must continue to make price-to-beat rates available to small business customers, however, it may offer rates other than price-to-beat, since it met the requirements of the 40% threshold target calculation in December 2003. The price-to-beat rate can be adjusted upward or downward twice a year, subject to approval by the Commission, for changes in the market price of natural gas.

In March 2004, Energy filed a request with'the Commission to increase the fuel factor component of its price-to-beat rates: This request was approved May 13, 2004. In accordance with the Commission's order, the new rate became effective on May 20, 2004. This adjustment raised the'average monthly residential electric bill of a customer using 1,000 kilowatt hours by 3.4% or

$3.39 per month. -

In June 2004, Energy filed its second request for this year with the Commission to increase the fuel'factor component of its price-to-beat rates.

This request was approved July 28, 2004 and became effective on August 4, 2004.

The filing reflects an increase of 12.7% in the market price of natural gas since the March 2004 filing. This adjustment raised the average monthly residential electric bill of a customer using 1,000 kilowatt hours by 5.7% or

$5.87 per month. .  ! ,

Other Commission Matters -- On May 27, 2004, the Commission opened an investigation to gather information regarding Electric Delivery's and its affiliates' compliance with the Commission's affiliate code of conduct rules.

Conversations with the Commission indicate that this investigation was prompted in large part by the utility's change in its legal corporate name from Oncor Electric Delivery Company back to TXU Electric Delivery Company. Those 39

discussions indicate a reasonable expectation that the Commission will focus its investigation on Energy's implementation of a disclaimer rule that requires Energy to place a disclaimer in certain advertisements and on business cards to explain the distinction between Energy and Electric Delivery.

Energy, along with several ERCOT wholesale market participants, has filed an appeal at the Court of Appeals for the Third District of Texas (Austin) contesting certain aspects of a recently adopted Commission rule regarding enforcement standards applicable to the wholesale power market. Energy believes that certain portions of the rule as adopted are unconstitutionally vague and other portions may exact an unconstitutional taking of private property without just compensation. There is no statutory deadline by which the court must act on the appeal.

In August 2004, Energy proposed a tiered pricing program for out-of-territory customers (i.e., those customers outside of Energy's traditional North Texas service area) that would provide the lowest prices to customers that Energy has determined will pose the lowest risk of poor payment behavior, and higher prices to customers who will pose a higher risk of poor payment behavior. Energy's proposed tiered pricing program would have made use of credit information obtained from a credit reporting agency to make the payment risk determination. On September 8, 2004, the Texas Office of Public Utility Counsel (COPC") filed a complaint at the Commission alleging generally that the use of credit information is unlawfully discriminatory. Subsequently, on September 14, 2004, Energy filed its response to the OPC complaint and in that response, in addition to asserting that the proposed pricing plan is lawful, notified the Commission that, pursuant to the Commission Staff's request, Energy would suspend implementation of the proposed tiered pricing program for at least 45 days, so that Energy could engage in discussions with Commission Staff, OPC, and others regarding other tools to address the pressing issue of mounting bad debt (uncollectibles). OPC requested, and the Commission granted, the dismissal of the complaint without prejudice to refiling. These discussions began shortly thereafter and are continuing.

ERCOT Market Issues The Texas Public Utility Regulatory Act ("PURA-) and the Commission are subject to sunset review' by the Texas Legislature in the 2005 legislative session. Sunset review entails, generally, a comprehensive review of the need for and efficacy of an administrative agency (e.g., the Commission), along with an evaluation of the advisability of any changes to that agency's authorizing legislation (e.g., PURA). As part of the sunset review process, the legislative Sunset Advisory Commission has recommended that the Legislature re-authorize the Commission for at least 6 years, and has recommended other changes to PURA that are not expected to have a material adverse impact upon the Company's operations. The Legislature could consider and enact other changes to PURA and the Company cannot predict whether any such changes might have a material adverse impact on its operations.

In addition to sunset review, the Texas Legislature and other Texas governmental entities have initiated investigations into alleged improprieties regarding some contracting practices of ERCOT, the non-governmental entity that has operational control of the electric grid for much of Texas. To date, these activities have not resulted in actions that are expected to have a material impact on Energy's operations, but Energy cannot predict whether the culmination of these or other governmental activities that may affect the ERCO0 market may result in any such material adverse effect.

Wholesale market design In August 2003, the Commission adopted a rule that, if fully implemented, would alter the wholesale market design in ERCOT.

The rule requires ERCOT:

o to use a stakeholder process to develop a new wholesale market mode; o to operate a voluntary day-ahead energy market; o to directly assign all congestion rents to the resources that caused the congestion; o to use nodal energy prices for resources; o to provide information for energy trading hubs by aggregating nodes; o to use zonal prices for loads; and o to provide congestion revenue rights (but not physical rights).

Under the rule, the proposed market design and associated cost-benefit analysis is to be filed with the Commission by November 1, 2004 and is to be implemented by October 1, 2006. On September 17, 2004, the Commission opened a rulhmaking project to possibly delay the filing date of the proposed market design from November 1, 2004 to March 1, 2005. On October 28, the Commission 40

adopted a rule change that would delay the filing date for the proposed market design until March 18, 2005. Additionally, the Commission approved an extension until December 31, 2004 for the filing of the cost-benefit analysis. TXU Energy is currently unable to predict the cost or impact of implementing any proposed change to the current wholesale market design.

Environmental Matters -- On October 1,.2004,-TXU Corp. released an independent study by NERA Economic Consulting in collaboration with Marc Goldsmith & Associates. The study evaluated TXU Corp.'s processes for following and evaluating air emissions and climate policies and reviewed the company's actions regarding previous major air emissions policies and compliance.

Additionally, the study considered the financial consequences and related risks to TXU Corp. of prospective air emissions and climate change policies, including an assessment of the financial effects of reducing emissions now in anticipation of future requirements. The study concluded-that TXU Corp. has the appropriate processes and procedures in place and uses appropriate economic methodologies to evaluate financial consequences of-environmental regulatory policy changes and scenarios. The study also concluded that absent certain specific circumstances, TXU Corp.'s shareholders would not benefit if the company devoted major financial resources now to reduce its carbon dioxide emissions in advance of uncertain future emission regulations. In addition, ,the study concluded that TXU Corp.'s efforts have consistently resulted-in compliance-with air emission limits. The study is available on TXU Corp.'s website at http://www.txucorp.com/envcom/default.asp.: - -

Summary -- Although Energy cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions, no changes are expected in trends or commitments, other than those discussed in this report, which might significantly alter its basic financial position, results of operations or cash flows. -

CHANGES IN ACCOUNTING STANDARDS See Note 1 to Financial Statements for discussion of changes in accounting standards.

RISK FACTORS THAT MAY AFFECT FUTURE RESULTS- -

The following risk factors are being presented in consideration of industry practice with respect to disclosure of suchtinformation in filings under the Securities Exchange Act of 1934, as amended.-

Some important factors, in addition to others specifically addressed in this MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, that could have a material impact on Energy's operations, financial results and financial condition, and could cause Energy's actual results or outcomes to differ materially from any projected outcome contained in any forward-looking statement in this report, include: -

The implementation of performance improvement initiatives identified by management may not produce the desired results and may result in disruptions arising from employee displacements and the rapid-pace of changes to organizational structure and operating-practices and processes.

ERCOT is the independent system operator that is responsible for maintaining reliable operation of the bulk electric power supply system in the ERCOT region. Its responsibilities include the clearing and settlement of electricity volumes and related ancillary services among the various participants in the deregulated Texas market. Because of new processes and systems associated with the opening of the market to competition, which continue to be improved, there have been delays in finalizing these settlements. As a result, Energy is subject to settlement adjustments from ERCOT related to prior periods, which may result in charges or credits impacting future reported results of operations. - -

Energy's businesses operate in changing market environments influenced by various legislative and regulatory initiatives regarding deregulation, regulation or restructuring of the energy industry, including deregulation of the production and sale of electricity. Energy will-need to adapt to these -

changes and may face increasing competitive pressure.

41

. --- I ,, - -

- I Energy's businesses are subject to changes in laws (including PURA. the Federal Power Act, as amended, the Atomic Energy Act, as amended, the Public Utility Regulatory Policies Act of 1978. as amended, the Clean Air Act, as amended, and the Public Utility Holding Company Act of 1935, as amended) and changing governmental policy and regulatory actions (including those of the Commission, the FERC, the EPA and the NRC) with respect to matters including, but not limited to, market structure and design, operation of nuclear power facilities, construction and operation of other power generation facilities.

recovery of purchased gas costs, decommissioning costs, and present or prospective wholesale and retail competition. In particular, PURA and the Commission are subject to 'sunset review" by Texas Legislature in the upcoming 2005 legislative session. See 'ERCOT Market Issues' and "Wholesale Market Design" above.

Energy, along with other market participants, is subject to oversight by the Commission. In that connection, Energy and other market participants may be subject to various competition-related rules and regulations, including but not limited to possible price-mitigation rules, as well as rules related to market behavior.

Energy is not guaranteed any rate of return on its capital investments in unregulated businesses. Energy markets and trades power, including power from its own production facilities, as part of its wholesale energy sales business and portfolio management operation. Energy's results of operations are likely to depend, in large part, upon prevailing retail rates, which are set, in part, by regulatory authorities, and market prices for electricity, gas and coal in its regional market and other competitive markets. Market prices may fluctuate substantially over relatively short periods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply.

During periods of over-supply, prices might be depressed. Also, at times there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.

Some of the fuel for Energy's power production facilities is purchased under short-term contracts or on the spot market. Prices of fuel, including natural gas, may also be volatile, and the price Energy can obtain for power sales may not change at the same rate as changes in fuel costs. In addition, Energy purchases and sells natural gas and other energy related commodities, and volatility in these markets may affect Energy's costs incurred in meeting its obligations.

Volatility in market prices for fuel and electricity may result from:

o severe or unexpected weather conditions, o seasonality, o changes in electricity usage, o illiquidity in the wholesale power or other markets, o transmission or transportation constraints, inoperability or inefficiencies, o availability of competitively priced alternative energy sources, o changes in supply and demand for energy commodities, o changes in power production capacity, o outages at Energy's power production facilities or those of its competitors, o changes in production and storage levels of natural gas, lignite, coal and crude oil and refined products, o natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and o federal, state, local and foreign energy, environmental and other regulation and legislation.

All but one of Energy's facilities for power production are located in the ERCOT region, a market with limited interconnections to other markets.

Electricity prices in the ERCOT region are correlated to gas prices because gas--fired plant is the marginal cost unit during the majority of the year in the ERCOT region. Accordingly, the contribution to earnings and the value of Energy's base load power production is dependent in significant part upon the price of gas. Energy cannot fully hedge the risk associated with dependency on gas because of the expected useful life of Energy's power production assets and the size of its position relative to market liquidity.

To manage its near-term financial exposure related to commodity price fluctuations, Energy routinely enters into contracts to hedge portions of its purchase and sale commitments, weather positions, fuel requirements and inventories of natural gas, lignite, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Energy routinely utilizes fixed-price forward physical purchase and 42

sales contracts, futures, financial swaps andjoption contracts traded in the over-the-counter markets or-on exchanges. However, Energy can normally cover only a small portion of the exposure of its assets and positions to market price volatility, and the coverage will vary over-time. To the extent Energy has unhedged positions, fluctuating commodity prices can materially impact Energy's results of operations and financial position, either favorably or unfavorably.

Although Energy devotes a considerable amount of management time and effort to the establishment of risk management procedures as well as the ongoing review of the implementation of these procedures, the procedures it has in place may not always be followed or may not always function as planned and cannot eliminate all the risks associated with these activities. As a result of these and other factors, Energy cannot predict with precision the impact that risk management decisions may have on its business, results of operations or financial position.

Energy might not be able to satisfy all of its guarantees and indemnification obligations, including those related to hedging and risk management activities, if they were to come due at the same time.

Energy's hedging and risk management activities are exposed to the risk that counterparties that owe Energy money, energy or other commodities as a result of market transactions will not perform their obligations. The likelihood that certain counterparties may fail to perform their obligations has increased due to financial difficulties, brought on by various factors including improper or illegal accounting and business practices, affecting some participants in the industry. Some of these financial difficulties have been so severe that certain industry participants have filed for bankruptcy protection or are facing the possibility of doing so. Should the counterparties to these arrangements fail to perform, Energy might be forced to acquire alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, Energy might incur losses in addition to amounts, if any, already paid to the counterparties. ERCOT market participants.are also exposed to risks that another ERCOT market participant may default in its obligations to pay ERCOT for power taken in the ancillary services market, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants.

The current credit ratings for Energy's long-term debt are investment grade. A rating reflects only the view of a rating agency, and it is not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward at any time by a rating agency if such rating agency decides that circumstances warrant such a change. If S&P, Moody's or Pitch were to downgrade Energy's ratings, borrowing costs would increase and the potential pool of investors and funding sources would likely decrease. If the downgrade were below investment grade, liquidity demands would be triggered by the terms of a number of commodity contracts, leases and other agreements.

Most of Energy's large customers, suppliers and counterparties require sufficient creditworthiness in order to enter into transactions. If Energy's ratings were to decline to below investment grade,-costs to operate the power business would increase because counterparties may require the posting of collateral in the form of cash-related instruments, or counterparties may decline to do business with Energy.

In addition, as discussed in Energy's Annual Report on Form 10-K for the year ended December 31, 2003, the terms of certain of Energyes financing and other arrangements contain provisions that are specifically affected by changes in credit ratings and could require the posting of collateral, the repayment of indebtedness or the payment of other amounts.-,

The operation of power production facilities involves many risks, including start up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency, the occurrence of any of which could result fin lost revenues and/or increased expenses. A significant portion of Energy's facilities was constructed many years ago. In particular, older generating equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep it operating at-peak efficiency. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive market, (b) any unexpected failure to produce power, including failure caused by 43

breakdown or forced outage, and (c) repairing damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events.

Further, Energy's ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, Energy could be subject to additional costs and/or the write-off of its investment in the project or improvement.

Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses, including the cost of replacement power. Likewise, Energy's ability to obtain insurance, and the cost of and coverage provided by such insurance, could be affected by events outside its control.

The ownership and operation of nuclear facilities, including Energy's ownership and operation of the Comanche Peak generation plant, involve certain risks. These risks include: mechanical or structural problems; inadequacy or lapses in maintenance protocols; the impairment of reactor operation and safety systems due to human error; the costs of storage, handling and disposal of nuclear materials; limitations on the amounts and types of insurance coverage commercially available: and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. The following are among the more significant of these risks:

o Operational Risk - Operations at any nuclear power production plant could degrade to the point where the plant would have to be shut down. Over the next three years, certain equipment at Comanche Peak is expected to be replaced. The cost of these actions is currently expected to be material and could result in extended outages. If this were to happen, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant may be shut down. Furthermore, a shut-down or failure at any other nuclear plant could cause regulators to require a shut-down or reduced availability at Comanche Peak.

o Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Comanche Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively.

Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

o Nuclear Accident Risk - Although the safety record of Comanche Peak and other nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the US and elsewhere.

The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident could exceed Energy's resources, including insurance coverage.

Energy is subject to extensive environmental regulation by governmental authorities. In operating its facilities, Energy is required to comply with numerous environmental laws and regulations, and to obtain numerous governmental permits. Energy may incur significant additional costs to comply with these requirements. If Energy fails to comply with these requirements, it could be subject to civil or criminal liability and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to Energy or its facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions.

Energy may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if Energy fails to obtain, maintain or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. Further, at some of Energy's older facilities, including base load lignite and coal plants, it may be uneconomical for Energy to install the necessary equipment, which may cause Energy to shut down those facilities.

44

In addition, Energy may be responsible for any on-site liabilities associated with the environmental condition of facilities that it has acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and sales of assets, Energy may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could fail to meet its indemnification obligations to Energy.

Energy is obligated to offer the price-to-beat rate to requesting residential and small business customers in-its historical service territory within Texas through January 1, 2007. Energy is not permitted to offer electricity to the residential customers in the historical service territory at a price other than the price-to-beat rate until January 1, 2005, unless before that date the Commission determines that 40* or more of the amount of electric power consumed by residential customers in that area is committed to be served by REPs other than Energy. Because Energy will not have the same level of residential customer price flexibility as competitors in the historical service territory, Energy could lose a significant number of these customers to other providers. - - .

Other REPs are allowed to offer electricity to Energy's residential customers at any price. The margin or "headroom, available in the price-to-beat rate for any REP equals the difference between the price-to-beat rate and the sum of delivery charges and the price that REP pays for power. Headroom may be a positive or a negative number. The higher .the amount of positive headroom for competitive REPs in a given market, the more incentive those REPs would have to compete in providing retail electric services in that market, which may result in Energy losing customers to competitive REPs.

The results of Energy's retail electric operations in the historical service territory is largely dependent upon-the amount of headroom available to Energy and the competitive PEPs in Energy's.price-to-beat rate. Since headroom is dependent, in part, on power production and purchase costs, Energy does not know nor can it estimate the amount of headroom that it or other REPs will have in Energy's price-to-beat rate or in the price-to-beat rate for the affiliated REP in each of the other Texas retail electric markets.

There is no assurance that future adjustments to Energy's price-to-beat rate will be adequate to cover future increases in its costs of electricity to serve its price-to-beat rate customers or that Energy's price-to-beat rate will not result in negative headroom in the-future.

In most retail electric markets outside the historical service territory, Energy's principal competitor may be the retail affiliate of the local incumbent utility company. The incumbent retail affiliates have the advantage of long-standing relationships with their customers. In addition to competition from the incumbent utilities and their affiliates, Energy may face competition from a number of other energy service providers, or other energy industry participants, who may develop businesses that will compete with Energy and nationally branded providers of consumer products and services. Some of these competitors or potential competitors may be larger and better capitalized than Energy. If there is inadequate margin in these retail electric markets, it may not be profitable for Energy to enter these markets.

Energy depends on transmission and distribution facilities owned and operated by other utilities, as well as ElectricDelivery's facilities, to deliver the electricity it produces and sells to consumers, as well as to other REPs. If transmission capacity is inadequate,.Energy's ability to sell and deliver electricity may be hindered, it may have to forgo sales or it may have to buy more expensive wholesale electricity that is available in the capacity-constrained area. In particular, during some periods transmission access is constrained to some areas of the Dallas-Fort Worth metroplex. Energy expects to have a significant number of customers inside these constrained areas. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower headroom. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to Energy's customers could negatively impact the satisfaction of its customers with its service. - - -

Energy offers its customers a bundle of services that include, at a minimum, the electric commodity itself plus transmission, distribution and related services. The prices Energy charges for this bundle of services or for the various components of the bundle, either of which may be fixed by contract with the customer for a period of time, could fall below Energy's underlying cost to obtain the commodities or services. -

The information systems and processes necessary to support risk management, sales, customer service and energy procurement and supply in competitive retail markets in Texas and elsewhere are new, complex and extensive. These systems and processes require ongoing refinement, which may prove more expensive than planned and may not work as planned. Delays in the perfection of these systems and processes and any related increase in costs could have a material adverse impact on Energy's business and results of operations.

45

I- __L Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines and photovoltaic (solar) cells. It is possible that advances in these or other alternative technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with electricity production from traditional power plants like Energy's. While demand for electric energy services is generally increasing throughout the US, the rate of construction and development of new, more efficient power production facilities may exceed increases in demand in some regional electric markets. Consequently, where Energy has facilities, the market value of Energy's power production facilities could be significantly reduced. Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of Energy's facilities. Changes in technology could also alter the channels through which retail electric customers buy electricity.

Energy is a holding company and conducts its operations primarily through wholly-owned subsidiaries. Substantially all of Energy's consolidated assets are held by these subsidiaries. Accordingly, Energy's cash flows and ability to meet its obligations and to pay distributions are largely dependent upon the earnings of its subsidiaries and the distribution or other payment of such earnings to Energy in the form of distributions, loans or advances, and repayment of loans or advances from Energy. The subsidiaries are separate and distinct legal entities and have no obligation to provide Energy with funds for its payment obligations, whether by distributions, loans or otherwise.

The inability to raise capital on favorable terms, particularly during times of uncertainty in the financial markets, could impact Energy's ability to sustain and grow its businesses, which are capital intensive, and would increase its capital costs. Energy relies on access to financial markets as a significant source of liquidity for capital requirements not satisfied by cash on hand or operating cash flows. Energy's access to the financial markets could be adversely impacted by various factors, such as:

o changes in credit markets that reduce available credit or the ability to renew existing liquidity facilities on acceptable terms; o inability to access commercial paper markets; o a deterioration of Energy's credit or a reduction in Energy's credit ratings; o extreme volatility in Energy's markets that increases margin or credit requirements; o a material breakdown in Energy's risk management procedures; o prolonged delays in billing and payment resulting from delays in switching customers from one REP to another; and o the occurrence of material adverse changes in Energy's businesses that restrict Energy's ability to access its liquidity facilities.

A lack of necessary capital and cash reserves could adversely impact the evaluation of Energy's credit worthiness by counterparties and rating agencies, and would likely increase its capital costs. Further, concerns on the part of counterparties regarding Energy's liquidity and credit could limit its portfolio management activities.

As a result of the energy crisis in California during 2001, the recent volatility of natural gas prices in North America, the bankruptcy filing by Enron Corporation, accounting irregularities of public companies, and investigations by governmental authorities into energy trading activities, companies in the regulated and non-regulated utility businesses have been under a generally increased amount of public and regulatory scrutiny. Accounting irregularities at certain companies in the industry have caused regulators and legislators to review current accounting practices and financial disclosures.

The capital markets and ratings agencies also have increased their level of scrutiny. Additionally, allegations against various energy trading companies of Ground trip' or 'wash, transactions, which involve the simultaneous buying and selling of the same amount of power at the same price and delivery location and provide no true economic benefit, power market manipulation and inaccurate power and commodity price reporting have had a negative effect on the industry. Energy believes that it is complying with all applicable laws, but it is difficult or impossible to predict or control what effect events and investigations in the energy industry may have on Energy's financial condition or access to the capital markets. Additionally, it is unclear what laws and regulations may develop, and Energy cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or its operations specifically. Any such new accounting standards could negatively impact reported financial results.

46

The issues and associated risks and uncertainties described above are not the only ones Energy may face. Additional issues may arise or become material as the energy industry evolves.

FORWARD-LOOKING STATEMENTS This report and other presentations made by Energy and its subsidiaries (collectively, Energy) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Although Energy believes that in making any such statement its expectations are based on reasonable assumptions, any such statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause the actual results of Energy to differ materially from those projected in such forward-looking statements: (i) prevailing governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission, the Commission, the NRC, particularly with respect to allowed rates of return, industry, market and rate structure, purchased power and investment recovery, operations of nuclear generating facilities, acquisitions and disposal of assets and facilities, operation and construction of plant facilities, decommissioning costs, present or prospective wholesale and retail competition, changes in tax laws and policies and changes in and compliance with environmental and safety laws and policies, {ii) general industry trends, (iii) weather conditions and other natural phenomena, and acts of sabotage, wars or terrorist activities, (iv) unanticipated population growth or decline, and changes in market demand and demographic patterns, (v) competition for retail and wholesale customers, (vi) pricing and transportation of crude-oil, natural gas'and other commodities, (vii) unanticipated changes in interest'rates; commodity prices or rates of inflation, (viii) unanticipated changes in operating expenses, liquidity needs and capital expenditures, (ix) commercial bank market and capital market conditions, Cx) competition for new energy development opportunities, (xi) legal and administrative proceedings and settlements, (xii) inability of the various counterparties to meet their obligations with respect to Energy's financial instruments, (xiii) changes in technology used and services offered by Energy, and (xiv) significant-changes in Energy's relationship with its employees and the potential adverse effects if labor disputes or grievances were to occur, (xv) power costs and availability; (xvi) changes in business strategy, development plans or vendor relationships, (xvii) availability of qualified personnel, Cxviii) implementation of new accounting standards, (xix) global financial and credit market conditions, and credit rating agency actions and (xx) access to adequate transmission facilities to meet changing demands.

Any forward-looking statement speaks only as of the date on which such statement is made, and Energy undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for Energy to predict all of such factors, nor can it assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Except as presented below, the information required hereunder is not significantly different from the information set forth in Item 7A. Quantitative and Qualitative Disclosures About Market Risk included in the 2003 Form 10-K and is therefore not presented herein.

COMMODITY PRICE RISK Energy continuously reviews its disclosed risk analysis metrics. In the course of this review, it was determined that the'Portfolio VaR metric would no longer be disclosed as it is not a meaningful measure of actionable commodity price risk. Other metrics that 'measure the effect of such risk on earnings, cash flows and the value of its mark-to-market'contract portfolio continue to be disclosed. Energy may in the future add or eliminate other metrics in its disclosures of risks. '.

47

- II VaR for Energy Contracts Subject to Mark-to-Market Accounting -- This measurement estimates the potential loss in value, due to changes in market conditions, of all energy-related contracts subject to mark-to-market accounting, based on a specific confidence level and an assumed holding period.

Assumptions in determining this VaR include using a 95% confidence level and a five-day holding period. A probabilistic 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.

September 30, December 31, 2004 2003 Period-end MtM VaR ..................................................... $ 15 $ 15 Average Month-end MtM VaR: over the nine and twelve month periods ...... $ 19 $ 25 Other Risk Measures -- The metrics appearing below provide information regarding the effect of changes in energy market conditions on earnings and cash flow.

Earnings at Risk (EaR) -- EaR measures the estimated potential loss of expected pretax earnings for the year presented due to changes in market conditions. EaR metrics include the owned generation assets, estimates of retail load and all contractual positions except for accrual positions expected to be settled beyond the fiscal year. Assumptions include using a 95% confidence level over a five-day holding period under normal market conditions.

Cash Flow at Risk (CFaR) -- CFaR measures the estimated potential loss of expected cash flow over the next six months, due to changes in market conditions. CFaR metrics include all owned generation assets, estimates of retail load and all contractual positions that impact cash flow during the next six months. Assumptions include using a 99% confidence level over a six-month holding period under normal market conditions.

September 30, December 31, 2004 2003 EaR .............................................................. $ 6 S 15 CFaR . ............................................................ 5 57 S 67 INTEREST RATE RISK See Note 4 to Financial Statements for a discussion of the issuance and retirement of debt since December 31, 2003.

CREDIT RISK Concentration of Credit Risk -- As of September 30, 2004, the exposure to credit risk from large business customers and hedging counterparties, excluding credit collateral, is $1.0 billion, net of standardized master netting contracts and agreements that provide the right of offset of positive and negative credit exposures with individual customers and counterparties. When considering collateral currently held by Energy (cash, letters of credit and other security interests), the net credit exposure is $914 million. Of this amount, approximately 83% is with investment grade customers and counterparties, as determined by using publicly available information including major rating agencies' published ratings and Energy's internal credit evaluation process.

Those customers and counterparties without an SaP 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 an S&P equivalent rating.

Energy routinely monitors and manages its credit exposure to these customers and counterparties on this basis.

48

The following table presents the distribution of credit exposure as of September 30, 2004, for trade accounts receivable from large business customers, commodity contract assets and other derivative assets that arise primarily from hedging activities, by investment grade and noninvestment grade, credit quality and maturity.

Exposure by Maturity Exposure before Greater Credit Credit 2 years or Between than 5 Collateral Collateral Net Exposure less 2-5 years years Total Investment grade S 805 $ 43 $ 762 $ 628 $ 72 S 62 $ 762 Noninvestment grade 205 53 152 127 14 11 152 Totals $1,010 $ 96 $ 914 5 755 $ 86 $ 73 $ 914 Investment grade 80% 44% 83%

Noninvestment grade 20% 56% 17%

Energy has exposure in the amount of $108 million to one customer or counterparty that is 12% of the net exposure of $914 million at September 30, 2004. Energy holds a $75 million guaranty from this counterparty's investment grade parent and is currently negotiating the increase of such guaranty amount.

Additionally, approximately 83% of the credit exposure, net of collateral held, has a maturity date of two years or less. Energy does not anticipate any material adverse effect on its financial'position or results of operations as a result of non-performance by any customer or counterparty.

ITEM 4. CONTROLS AND PROCEDURES An evaluation was performed under the supervision and with the participation of Energy's 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 as of the end of the current period included in this quarterly report. This evaluation took into consideration the strategic initiatives described in Note 1 to Financial Statements. Based on the evaluation performed, Energy's 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 Energy's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect; Energy's internal control over financial reporting.

49

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

ITEM 6. EXHIBITS (a) Exhibits provided as part of Part II are:

Previously Filed-With File As Exhibits Number Exhibit 10(a) 1-12833 10 (c) -- Credit agreement, dated November 4, 2004, by and between TXU Form 10-Q Energy Company LLC and Wachovia Bank, National Association (filed November 5, 2004)

(31) Rule 13a - 14(a)/15d - 14(a) Certifications.

31(a) Certification of Paul O'Malley, principal executive officer of TXU Energy Company LLC, pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b) Certification of Kirk R. Oliver, principal financial officer of TXU Energy Company LLC, pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32) Section 1350 Certifications.

32 (a) Certification of Paul O'Malley, principal executive officer of TXU Energy Company LLC, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32 (b) Certification of Kirk R. Oliver, principal financial officer of TXU Energy Company LLC, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(99) Additional Exhibits 99 Condensed Statements of Consolidated Income -

Twelve Months Ended September 30, 2004.

• Incorporated herein by reference.

50

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.

TXU ENERGY COMPANY LLC By /s/ Stanley J. Szlauderbach Stanley J. Szlauderbach Assistant Controller and Interim Controller Date: November 12, 2004 51

</TEXT>

</DOCUMENTN

. i' . -

Exhibit 31(a)

TXU ENERGY COMPANY LLC Certificate Pursuant to Section 302 of Sarbanes - Oxley Act of 2002 CERTIFICATION OF CEO I, Paul O'Malley, Chairman of the Board, President and Chief Executive of TXU Energy Company LLC, certify that:

1. I have reviewed this quarterly report on Form 10-Q of TXU Energy Company LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact 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(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-l5(e)) 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. 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

c. 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 S. The registrant's other certifying officer(s) 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!: November 12, 2004

/S/ Paul O'Malley Signature: Paul O'Malley

Title:

Chairman of the Board, President and Chief Executive

</TDFXT T

</DOCUMENT,

Exhibit 31(b)

TXU ENERGY COMPANY LLC Certificate Pursuant to Section 302 of Sarbanes - Oxley Act of 2002 CERTIFICATION OF CFO I, Kirk R. Oliver, Executive Vice President and Chief Financial Officer of TXU Energy Company LLC, certify that:

1. I have reviewed this quarterly report on Form 20-Q of TXU Energy Company LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact 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(s) and.I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and l5d-15(e)) 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. 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

c. 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(s) 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: November 12, 2004 /a/ Kirk R. Oliver Signature: Kirk R. Oliver

Title:

Executive Vice President and Chief Financial Officer

</TEXT>

</DOCUMENT>

- II Exhibit 32(a)

TXU ENERGY COMPANY LLC Certificate Pursuant to Section 906 of Sarbanes - Oxley Act of 2002 CERTIFICATION OF CEO The undersigned, Paul O'Malley, Chairman of the Board, President and Chief Executive of TXU Energy Company LLC (the "Company"). DOES HEREBY CERTIFY that:

1. The Company's Quarterly Report on Form 10-Q for the period ended September 30, 2004 (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 operation of the Company.

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 12th day of November, 2004.

Isf Paul O'Malley Name: Paul O'Malley

Title:

Chairman of the Board. President and Chief Executive A signed original of this written statement required by Section 906 has been provided to TXU Energy Company LLC and will be retained by TXU Energy Company LLC and furnished to the Securities and Exchange Commission or its staff upon request.

</TEXT>

</DOCUMENT>

Exhibit 32(b)

TXU ENERGY COMPANY LLC Certificate Pursuant to Section 906 of Sarbanes - Oxley Act of 2002 CERTIFICATION OF CFO The undersigned, Kirk R. Oliver, Executive Vice President and Chief Financial Officer of TXU Energy Company LLC (the -Company'), DOES HEREBY CERTIFY that:

1. The Company's Quarterly Report on Form 10-Q for the period ended September 30, 2004 (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 operation of the Company.

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 12th day of November, 2004.

/s/ Kirk R. Oliver Name: Kirk R. Oliver

Title:

Executive Vice President and Chief Financial Officer A signed original of this written statement required by Section 906 has been provided to TXU Energy Company LLC and will be retained by TXU Energy Company LLC and furnished to the Securities and Exchange Commission or its staff upon request.

</TEXT>

</DOCUMENT>

_-- ll -

EXHItBIT 99 TXU ENERGY COMPANY LLC CONDENSED STATEMENT OF CONSOLIDATED INCOME (Unaudited)

Twelve Months Ended September 30, 2004 (million: of dollars)

Operating revenues........................................................................ $ 8,332 Operating expenses:

Cost of energy sold and delivery fees.................................................. 5,237 Operating costs........................................................................ 694 Depreciation and amortization.......................................................... 369 Selling, general and administrative expenses....................................... 670 Franchise and revenue-based taxes...................................................... 120 Other income........................................................................... (55)

Other deductions....................................................................... 314 Interest income........................................................................ (26)

Interest expense and related charges. ...................................... 340 Total costs and expenses;............................................................. 7,663 Income from continuing operations before income taxes..................................... 669 Income tax expense........................................................................ 204 Income from continuing operations......................................................... 465 Los.; from discontinued operations, net of tax benefit..................................... (48)

Net income................................................................................ $ 417

= --....

</TEXT, s/DOCUMENT, Crcatcti by I OKWi7zard TCchnologgy www. 10KWi7ard.corm