Exhibit 99.1

Appendix A

TXU ENERGY COMPANY LLC AND SUBSIDIARIES

INDEX TO FINANCIAL INFORMATION

December 31, 2003

	Page
Glossary	ii
Selected Financial Data	A-1
Management’s Discussion and Analysis of Financial Condition and Results of Operations	A-2
Report of Independent Registered Public Accounting Firm	A-22
Financial Statements:
Statements of Consolidated Income and Comprehensive Income	A-23
Statements of Consolidated Cash Flows	A-24
Consolidated Balance Sheets	A-25
Statements of Consolidated Membership Interests	A-26
Notes to Financial Statements	A-27

i

GLOSSARY

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

1999 Restructuring Legislation	Legislation that restructured the electric utility industry in Texas to provide for competition
2002 Form 8-K	US Holdings’ Current Report on Form 8-K filed on February 26, 2003 for Energy with respect to its financial information for the year ended December 31, 2002, and Form 8-K filed September 16, 2003 to reflect the impact of adopting SFAS 145 on the financial information reported in the Form 8-K filed on February 26, 2003
2002 Form 10-K	US Holdings’ Annual Report on Form 10-K for the year ended December 31, 2002
2003 Form 10-K	Energy’s Annual Report on Form 10-K for the year ended December 31, 2003
APB Opinion 30	Accounting Principles Board Opinion No. 30, “Reporting the Results of Operations – Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”
Bcf	billion cubic feet
Commission	Public Utility Commission of Texas
EITF	Emerging Issues Task Force
EITF 98-10	EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”
EITF 01-8	EITF Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease”
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”
EITF 03-11	EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF No. 02-3”
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 (formerly Oncor 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
EPA	Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ERISA	Employee Retirement Income Security Act
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

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FIN 45	FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others – an Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FIN No. 34”
FIN 46	FIN No. 46, “Consolidation of Variable Interest Entities”
Fitch	Fitch Ratings, Ltd.
GWh	gigawatt-hours
historical service territory	US Holdings’ historical service territory, largely in north Texas, at the time of entering competition on January 1, 2002
IRS	Internal Revenue Service
kv	kilovolt
Moody’s	Moody’s Investors Services, Inc.
MW	megawatts
NRC	United States Nuclear Regulatory Commission
POLR	provider of last resort of electricity to certain customers under the Commission rules interpreting the 1999 Restructuring Legislation
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 40% 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&P	Standard & Poor’s, a division of the McGraw Hill Companies
Sarbanes-Oxley	Sarbanes – Oxley Act of 2002
SEC	United States Securities and Exchange Commission
Settlement Plan	regulatory settlement plan that received final approval by the Commission in January 2003
SFAS	Statement of Financial Accounting Standards issued by the FASB
SFAS 4	SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt”
SFAS 34	SFAS No. 34, “Capitalization of Interest Cost”
SFAS 71	SFAS No. 71, “Accounting for the Effect of Certain Types of Regulation”
SFAS 87	SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 101	SFAS No. 101, “Regulated Enterprises – Accounting for the Discontinuance of the Application of FASB Statement No. 71”
SFAS 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 121	SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of”
SFAS 132	SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”

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SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities a replacement of FASB Statement 125”
SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 144	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 145	SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement 13, and Technical Corrections”
SFAS 146	SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”
SFAS 149	SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
SFAS 150	SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”
SG&A	selling, general and administrative
SOP 98-1	American Institute of Certified Public Accountants Statement of Position 98-1, “Accounting for the Cost of Computer Software Developed or Obtained for Internal Use”
TCEQ	Texas Commission on Environmental Quality
TXU Business Services	TXU Business Services Company, a subsidiary of TXU Corp.
TXU Corp.	refers to TXU Corp. and/or its consolidated subsidiaries, depending on context
TXU Fuel	TXU Fuel Company, a subsidiary of Energy
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
TXU SESCO	TXU SESCO Company, a subsidiary of Energy, which serves as a REP in ten counties in the eastern and central parts of Texas
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.

iv

TXU ENERGY COMPANY LLC AND SUBSIDIARIES

SELECTED FINANCIAL DATA

	Year Ended December 31,
	2003			2002			2001			2000
	(Millions of Dollars, except ratios)
Total assets — end of year	$	14,572		$	15,789		$	13,905		$	14,775
Property, plant and equipment – net — end of year	$	10,345		$	10,341		$	10,530		$	10,650
Capital expenditures	$	163		$	284		$	327		$	254
Capitalization — end of year
Long-term debt, less amounts due currently	$	3,084		$	2,378		$	3,454		$	3,196
Exchangeable preferred membership interests		497			—			—			—
Membership interests		3,999			4,273			4,212			4,121
Total	$	7,580		$	6,651		$	7,666		$	7,317
Capitalization ratios — end of year
Long-term debt, less amounts due currently		40.7	%		35.8	%		45.1	%		43.7	%
Exchangeable preferred membership interests		6.6			—			—			—
Membership interests		52.7			64.2			54.9			56.3
Total		100.0	%		100.0	%		100.0	%		100.0	%
Embedded interest cost on long-term debt and exchangeable preferred membership interests—end of year (a)		7.2	%		6.8	%		4.5	%		5.9	%
Operating revenues	$	7,986		$	7,678		$	7,404		$	7,392
Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		497			322			591			581
Net income		421			270			507			576
Ratio of earnings to fixed charges		2.95			2.66			3.96			3.64

(a) Represents the annual interest and amortization of any discounts, premiums, issuance costs and any deferred gains/losses on reacquisitions divided by the carrying value of the debt plus or minus the unamortized balance of any discounts, premiums, issuance costs and gains/losses on reacquisitions at the end of the year.

Certain previously reported financial statistics have been reclassified to conform to current classifications.

Prior year amounts have been restated to reflect certain operations as discontinued operations. (See Note 3 to Financial Statements.)

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS

Use of the term “Energy”, unless otherwise noted, refers to TXU Energy Company LLC, a holding company, and/or its consolidated subsidiaries.

Energy is engaged in electricity generation, retail and wholesale energy sales and hedging and risk management activities.

Energy has no reportable segments.

Changes in Business

Discontinued Businesses –

See Note 3 to Financial Statements for detailed information about discontinued operations.

All dollar amounts in Management’s Discussion and Analysis of Financial Condition and Results of Operations and the tables therein, except per share amounts, are stated in millions of US dollars unless otherwise indicated.

MANAGEMENT’S CHALLENGES AND INITIATIVES

Management Change

On February 23, 2004, C. John Wilder was named president and chief executive of TXU Corp. Mr. Wilder was formerly executive vice president and chief financial officer of Entergy Corporation. Mr. Wilder is in the process of reviewing the operations of TXU Corp. and formulating strategic initiatives. This review is expected to take up to six months. Upon completion, TXU Corp. expects to fully describe the results of the review and subsequent actions intended to improve the financial performance of its operations.

Areas to be reviewed include:

• Performance in competitive markets, including profitability in new markets

• Cost structure, including organizational alignments and headcount

• Management of natural gas price risk

• Non-core business activities

If any new strategic initiatives are undertaken, TXU Corp.’s financial results could be materially affected.

Competitive Markets

In the Texas market, 2003 was the second full year of competitive activity, and that activity has impacted customer counts and sales volumes. The area representing the historical service territory prior to deregulation, largely in north Texas, consisted of approximately 2.8 million consumers (measured by meter counts) as of year-end of 2003. Energy currently has approximately 2.4 million customers in that territory and has acquired approximately 200,000 customers in other competitive areas in Texas. Total customer counts declined 4% in 2003 and 0.5% in 2002. Retail sales volumes declined 12% in 2003 and 9% in 2002, reflecting competitive activity in the business market segment and to a lesser extent in the residential market. While wholesale sales volumes have increased significantly, gross margins have been compressed by the loss of the higher-margin retail volumes. Energy intends to aggressively compete, in terms of price and customer service, in all segments of the retail market, both within and outside the historical service territory. In particular, Energy anticipates regaining volumes in the large business market, reflecting contracting activity in late 2003. Because of the customer service and marketing costs associated with entering markets outside of the historical service territory, Energy has experienced operating losses in these new markets. Energy expects to be profitable in these markets as the customer base grows and economies of scale are achieved, but uncertainties remain and objectives may not be achieved.

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Effect of Natural Gas

Wholesale electricity prices in the Texas market generally move with the price of natural gas because marginal demand is met with gas-fired generation plants. Natural gas prices increased significantly in 2003, but historically the price has moved up and down due to the effects of weather, industrial demand, supply availability and other economic factors. Consequently, sales price management and hedging activities are critical in achieving targeted gross margins. Energy continues to have price flexibility in the large business market and effective January 1, 2004, has price flexibility in the small business market including the historical service territory. With respect to residential customers in the historical service territory, Energy is subject to regulated “price-to-beat” rates, but such rates can be adjusted up or down twice a year at Energy’s option, subject to approval by the Commission, based on changes in natural gas prices. The challenge in adjusting these rates is determining the appropriate timing, considering past and projected movements in natural gas prices, such that targeted margins can be achieved while remaining competitive with other retailers who have price flexibility. Energy increased the price-to-beat rates twice in 2003, and these actions combined with unregulated price increases and hedging activities essentially offset higher costs of energy sold as compared to 2002.

In its portfolio management activities, Energy enters into physical and financial energy-related (power and natural gas) contracts to hedge gross margins. Energy hedges prices of anticipated power sales against falling natural gas prices and, to a lesser extent, hedges costs of energy sold against rising natural gas prices. The results of hedging and risk management activities can vary significantly from one reporting period to the next as a result of market price movements on the values of hedging instruments. Such activity represents an effective management tool to reduce cash gross margin risk over time. The challenge, among others, with these activities is managing the portfolio of positions in a market in which prices can move sharply in a short period of time.

One of Energy’s cost advantages, particularly in a time of rising natural gas prices, is its nuclear-powered and coal/lignite-fired generation assets. Variable costs of this “base load” generation, which provided approximately 50% of sales volumes in 2003, have in recent history been, and are expected to be, less than the costs of gas-fired generation. Consequently, maintaining the efficiency and reliability of the base load assets is of critical importance in managing gross margin risk. Completing scheduled maintenance outages at the nuclear-powered facility on a timely basis, for example, is a critical management process. Because of the correlation of power and natural gas prices in the Texas market, structural decreases or increases in natural gas prices that are sustained over a multi-year period result in a correspondingly lower or higher value of Energy’s base load generation assets.

Operating Costs and SG&A Expenses

With the transition from a fully regulated environment to competition in the retail and wholesale electricity markets, Energy continues to seek opportunities to enhance productivity, reduce complexity and improve the effectiveness of its operating processes. Such efforts are balanced against the need to support growth and maintain the reliability, efficiency, and security of its generation fleet. Cost reduction initiatives have resulted in lower headcounts, the exiting of marginal business activities and reduced discretionary spending. Total operating costs and SG&A expenses in Energy’s continuing operations declined $151 million, or 10%, in 2003. These costs include TXU Corp. corporate expenses allocated to Energy. While upward cost pressures are expected for competitive sales and marketing initiatives, customer care and support activities, and employee and retiree benefits, increasing productivity levels will continue to be a management priority.

CRITICAL ACCOUNTING POLICIES

Energy’s significant accounting policies are detailed in Note 1 to Financial Statements. Energy follows accounting principles generally accepted in the United States of America. In applying these accounting policies in the preparation of Energy’s consolidated financial statements, management is required to make estimates and assumptions about future events that affect the reporting and disclosure of assets and liabilities at the balance sheet dates and revenue and expense during the periods covered. The following is a summary of certain critical accounting policies of Energy that are impacted by judgments and uncertainties and for which different amounts might be reported under a different set of conditions or using different assumptions.

Financial Instruments and Mark-to-Market Accounting — Energy enters into financial instruments, including options, swaps, futures, forwards and other contractual commitments primarily to hedge market risks related to changes in commodity prices as well as changes in interest rates. These financial instruments are

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accounted for in accordance with SFAS 133 as well as, prior to October 26, 2002, EITF 98-10. The majority of financial instruments entered into by Energy and used in hedging activities are derivatives as defined in SFAS 133.

SFAS 133 requires the recognition of derivatives in the balance sheet, the measurement of those instruments at fair value and the recognition in earnings of changes in the fair value of derivatives. This recognition is referred to as “mark-to-market” accounting. SFAS 133 provides exceptions to this accounting if (a) the derivative is deemed to represent a transaction in the normal course of purchasing from a supplier and selling to a customer, or (b) the derivative is deemed to be a cash flow or fair value hedge. In accounting for cash flow hedges, derivative assets and liabilities are recorded on the balance sheet at fair value with an offset in other comprehensive income. Amounts are reclassified from other comprehensive income to earnings as the underlying transactions occur and realized gains and losses are recognized in earnings. Fair value hedges are recorded as derivative assets or liabilities with an offset to the carrying value of the related asset or liability. Any hedge ineffectiveness related to cash flow and fair value hedges is recorded in earnings.

Energy documents designated commodity, debt-related and other hedging relationships, including the strategy and objectives for entering into such hedge transactions and the related specific firm commitments or forecasted transactions. Energy applies hedge accounting in accordance with SFAS 133 for these non-trading transactions, providing the underlying transactions remain probable of occurring. Effectiveness is assessed based on changes in cash flows of the hedges as compared to changes in cash flows of the hedged items. In its risk management activities, Energy hedges future electricity revenues using natural gas instruments; such cross-commodity hedges are subject to ineffectiveness calculations that can result in mark-to-market gains and losses.

Pursuant to SFAS 133, the normal purchase or sale exception and the cash flow hedge designation are elections that can be made by management if certain strict criteria are met and documented. As these elections can reduce the volatility in earnings resulting from fluctuations in fair value, results of operations could be materially affected by such elections.

Interest rate swaps entered into in connection with indebtedness to manage interest rate risks are accounted for as cash flow hedges if the swap converts rates from variable to fixed and are accounted for as fair value hedges if the swap converts rates from fixed to variable.

EITF 98-10 required mark-to-market accounting for energy-related contracts, whether or not derivatives under SFAS 133, that were deemed to be entered into for trading purposes as defined by that rule. The majority of commodity contracts and energy-related financial instruments entered into by Energy to manage commodity price risk represented trading activities as defined by EITF 98-10 and were therefore marked-to-market. On October 25, 2002, the EITF rescinded EITF 98-10. Pursuant to this rescission, only financial instruments that are derivatives under SFAS 133 are subject to mark-to-market accounting.

In June 2002, in connection with the EITF’s consensus on EITF 02-3, additional guidance on recognizing gains and losses at the inception of a trading contract was provided. In November 2002, this guidance was extended to all derivatives. As a result, effective in 2003, Energy discontinued recording mark-to-market gains on inception of energy contracts. See discussion below in Results of Operations - “Commodity Contracts and Mark-to-Market Activities.”

Mark-to-market accounting recognizes changes in the value of financial instruments as reflected by market price fluctuations. In the energy market, the availability of quoted market prices is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and location of delivery. In computing the mark-to-market valuations, each market segment is split into liquid and illiquid periods. The liquid period varies by region and commodity. Generally, the liquid period is supported by broker quotes and frequent trading activity. In illiquid periods, little or no market information may exist, and the fair value is estimated through market modeling techniques.

For those periods where quoted market prices are not available, forward price curves are developed based on available information or through the use of industry accepted modeling techniques and practices based on market fundamentals (e.g., supply/demand, replacement cost, etc.). Energy does not recognize any income or loss from the illiquid periods unless credible price discovery exists.

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Energy recorded net unrealized losses arising from mark-to-market accounting, including hedge ineffectiveness, of $100 million and $113 million in 2003 and 2002, respectively. The 2003 amount excludes the cumulative effect of changes in accounting principles discussed in Note 2 to Financial Statements.

Revenue Recognition — Energy records revenue for retail and wholesale energy sales under the accrual method. Retail electric revenues are recognized when electricity is provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the value of electricity consumed from the meter reading date to the end of the period. The unbilled revenue is calculated at the end of the period based on estimated daily consumption after the meter read date to the end of the period. Estimated daily consumption is derived using historical customer profiles adjusted for weather and other measurable factors affecting consumption. Unbilled revenues reflected in accounts receivable totaled $388 million and $489 million at December 31, 2003 and 2002, respectively.

Realized and unrealized gains and losses from transacting in energy-related contracts, principally for the purpose of hedging margins on sales of energy, are reported as a component of revenues. As discussed above under “Financial Instruments and Mark-to-Market Accounting,” recognition of unrealized gains and losses involves a number of assumptions and estimates that could have a significant effect on reported revenues and earnings.

Accounting for Contingencies — The financial results of Energy may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events.

A significant contingency that Energy accounts for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debts expense is based on factors such as historical write-off experience, agings of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions and customers’ behaviors. With the opening of the Texas electricity market to competition, many historical measures used to estimate bad debt experience may be less reliable. The changing environment, including recent regulatory changes that allow REPs in their historical service territories to disconnect non-paying customers, and customer churn due to competitor actions has added a level of complexity to the estimation process. Bad debt expense totaled $114 million and $155 million for the years ended December 31, 2003 and 2002, respectively.

In connection with the opening of the Texas market to competition, the Texas Legislature established a retail clawback provision intended to incent affiliated REPs of utilities to actively compete for customers outside their historical service territories. A retail clawback liability arises unless 40% of the electricity consumed by residential and small business customers in the historical service territory is supplied by competing REPs after the first two years of competition. This threshold was reached for small business customers in 2003, but not for residential customers. The amount of the liability is equal to the number of such customers retained by Energy as of January 1, 2004, less the number of new customers from outside the historical service territory, multiplied by $90. The credit, which will be funded by Energy, will be applied to delivery fees charged by Electric Delivery to REPs, including Energy, over a two-year period beginning January 1, 2004. In 2002, Energy recorded a charge to cost of energy sold and delivery fees of $185 million ($120 million after-tax) to accrue an estimated retail clawback liability. In 2003, Energy reduced the liability to $173 million, with a credit to cost of energy sold and delivery fees of $12 million ($8 million after-tax), to reflect the calculation of the estimated liability applicable only to residential customers in accordance with the Settlement Plan.

ERCOT Settlements – ERCOT’s responsibilities include the balancing and settlement of electricity volumes and related ancillary services among the various participants in the deregulated Texas market. ERCOT settles balancing energy with market participants through a load and resource imbalance charge or credit for any differences between actual and scheduled volumes. Ancillary services and various fees are allocated to market participants based on each participant’s load.

Settlement information is due from ERCOT within two months after the operating day, and true-up settlements are due from ERCOT within twelve months after the operating day. The ERCOT settlement process has been delayed several times to address operational data management problems between ERCOT, the transmission and distribution service providers and the REPs. These operational data management issues are related to new processes and systems associated with opening the ERCOT market to competition, which have

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continued to improve. True-up settlements have been received for 2002, but true-up settlements for the year 2003 are currently scheduled to start on June 1, 2004. All periods continue to be subject to a dispute resolution process.

As a result of the delay in the ERCOT settlements and the normal time lags described above, Energy’s operating revenues and costs of energy sold contain estimates for load and resource imbalance charges or credits with ERCOT and for ancillary services and related fees that are subject to change and may result in charges or credits impacting future reported results of operations. The amounts recorded represent the best estimate of these settlements based on available information. During 2003, Energy recorded a net expense of $20 million to adjust amounts previously recorded for 2002 and 2001 ERCOT settlements.

Impairment of Long-Lived Assets — Energy evaluates long-lived assets for impairment whenever indications of impairment exist, in accordance with the requirement of SFAS 144. One of those indications is a current expectation that “more likely than not” a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. The determination of the existence of this and other indications of impairment involves judgments that are subjective in nature and in some cases requires the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of Energy’s property, plant and equipment, which includes a fleet of generation assets using different fuels and individual plants that have varying utilization rates, requires the use of significant judgments in determining the existence of impairment indications and grouping assets for impairment testing.

In 2002, Energy recorded an impairment charge of $237 million ($154 million after-tax) for the writedown of two generation plant construction projects as a result of weaker wholesale electricity market conditions and reduced planned developmental capital spending. Fair value was determined based on appraisals of property and equipment. The charge is reported in other deductions.

Goodwill and Intangible Assets – Energy evaluates goodwill for impairment at least annually (as of October 1) in accordance with SFAS 142. The impairment tests performed are based on discounted cash flow analyses. Such analyses require a significant number of estimates and assumptions regarding future earnings, working capital requirements, capital expenditures, discount rate, terminal year growth factor and other modeling factors. No goodwill impairment has been recognized for consolidated reporting units reflected in results from continuing operations.

Defined Benefit Pension Plans and Other Postretirement Benefit Plans— Energy is a participating employer in the 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. See Note 11 to Financial Statements for information regarding retirement plans and other postretirement benefits.

These costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to retiree plans and earnings on plan assets. TXU Corp.’s retiree plan assets are primarily made up of equity and fixed income investments. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods. Benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation.

In accordance with accounting rules, changes in benefit obligations associated with these factors may not be immediately recognized as costs on the income statement, but are recognized in future years over the remaining average service period of plan participants. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Costs allocated from the plans are also impacted by movement of employees between participating companies. Energy recorded allocated pension and other postretirement benefits expense of $58 million in 2003, $32 million in 2002 and $19 million in 2001. Energy’s funding requirements for these plans were $29 million, $20 million and $20 million in 2003, 2002 and 2001, respectively.

During 2003, key assumptions of the US pension and other postretirement benefit plans were revised, including decreasing the assumed discount rate in 2003 from 6.75% to 6.25% to reflect current interest rates. The expected rate of return on pension plan assets remained at 8.5%, but declined to 8.01% from 8.26% for the other postretirement benefit plan assets.

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Based on current assumptions, pension and other postretirement benefits expense for Energy is expected to increase $9 million to approximately $67 million in 2004, and Energy’s funding requirements for these plans are expected to increase $16 million to approximately $45 million.

As a result of the pension plan asset return experience, at December 31, 2002, TXU Corp. recognized a minimum pension liability as prescribed by SFAS 87. Energy’s allocated portion of the liability, which totaled $60 million ($39 million after-tax), was recorded as a reduction to shareholders’ equity through a charge to Other Comprehensive Income. At December 31, 2003, the minimum pension liability reflects a reduction of $37 million ($25 million after-tax) as a result of improved returns on the plan assets. The changes in the minimum pension liability do not affect net income.

TXU Corp. has elected not to defer accounting for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) as allowed for under FASB Staff Position 106-1. TXU Corp. believes that the plan in which Energy is a participant meets the actuarial equivalency as required by the Medicare Act and therefore a reduction in future postretirement benefit costs is expected. Further information related to the impact of the Medicare Act can be found in the 2003 TXU Corp. Form 10-K The Medicare Act had no effect on Energy’s results of operations for 2003, but is expected to reduce Energy’s postretirement benefits expense other than pensions by approximately $11 million in 2004.

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RESULTS OF OPERATIONS

Operating Data

	Year Ended December 31,
	2003			2002			2001(a)(b)
Operating statistics - volumes:
Retail electricity (GWh)
Residential		35,981			37,692
Small business (c)		12,986			15,907
Large business and other		30,955			36,982
Total retail electricity		79,922			90,581			99,151
Wholesale electricity (GWh)		36,810			29,353			6,409
Production and purchased power (GWh):
Nuclear and lignite/coal (base load)		59,028			54,738			57,828
Gas/oil and purchased power		63,164			70,118			52,925
Total production and purchased power		122,192			124,856			110,753
Customer counts:
Retail electricity customers (end of period & in thousands – based on number of meters):
Residential		2,207			2,302
Small business		321			333
Large business and other		69			78
Total retail electricity customers		2,597			2,713			2,728
Operating revenues (millions of dollars):
Retail electricity revenues:
Residential	$	3,311		$	3,108		$	3,255
Business and other		3,173			3,415			3,837
Total retail electricity revenues		6,484			6,523			7,092
Wholesale electricity revenues		1,258			841			96
Hedging and risk management activities		30			147			358
Other revenues		214			167			(142	)
Total operating revenues	$	7,986		$	7,678		$	7,404
Weather (average for service territory) (d) Percent of normal:
Cooling degree days		103.1	%		99.8	%		100.5	%
Heating degree days		94.0	%		102.0	%		97.5	%

(a) Data for 2001 is included above for the purpose of providing historical financial information about Energy after giving effect to the restructuring transactions and unbundling allocations described in Note 1 to Financial Statements. Allocations reflected in 2001 data did not necessarily result in amounts reported in individual line items that are comparable to actual results in 2002 and 2003. Had Energy existed as a separate entity in 2001, its results of operations and financial position could have differed materially from those reflected above.

(b) Retail volume and customer count data for 2001 not available by class.

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

(d) Weather data is obtained from Meteorlogix, an independent company that collects weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce).

The results of operations and the related management’s discussion of those results for all periods presented reflect the discontinuance of certain operations of Energy (see Note 3 to Financial Statements regarding discontinued operations) and the reclassifications of losses in 2001 on early extinguishments of debt from extraordinary loss to other deductions in accordance with SFAS 145. (See Note 1 to Financial Statements.)

A-8

Energy

2003 compared to 2002

Operating revenues increased $308 million, or 4%, to $8.0 billion in 2003. Total retail and wholesale electricity revenues rose $378 million, or 5%, to $7.7 billion. This growth reflected higher retail and wholesale pricing, partially offset by the effects of a mix shift to lower-price wholesale sales and a 3% decline in total sales volumes. Retail electricity revenues decreased $39 million, or 1%, to $6.5 billion reflecting a $768 million decline attributable to a 12% drop in sales volumes, driven by the effect of competitive activity in the business market, largely offset by a $730 million increase due to higher pricing. Higher prices reflected increased price-to-beat rates, due to approved fuel factor increases, and higher contract pricing in the competitive large business market, both resulting from higher natural gas prices. Retail electricity customer counts declined 4% from year-end 2002. Wholesale electricity revenues grew $417 million, or 50%, to $1.3 billion reflecting a $223 million increase attributable to a 25% rise in sales volumes and a $194 million increase due to the effect of increased natural gas prices on wholesale prices. Higher wholesale electricity sales volumes reflected a partial shift in the customer base from retail to wholesale services, particularly in the business market.

Net gains from hedging and risk management activities, which are reported in revenues and include both realized and unrealized gains and losses, declined $117 million to $30 million in 2003. Changes in these results reflect market price movements on commodity contracts entered into to hedge gross margin; the comparison to 2002 also reflects a decline in activities in markets outside of Texas. 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 rather taken together with the effects of pricing and cost changes on gross margin. Results from these activities include net unrealized losses arising from mark-to-market accounting of $100 million in 2003 and $113 million in 2002. 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 $39 million in revenues since that date. The increase in other revenues of $47 million to $214 million in 2003 was driven by this change.

Gross Margin

	Year Ended December 31,
	2003		% of Revenue		2002		% of Revenue
Operating revenues	$	7,986	100	%	$	7,678	100	%
Costs and expenses:
Cost of energy sold and delivery fees		5,117	64	%		4,771	62	%
Operating costs		685	9	%		698	9	%
Depreciation and amortization related to generation assets		368	4	%		408	5	%
Gross margin	$	1,816	23	%	$	1,801	24	%

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, whether generated or purchased.

The depreciation and amortization expense reported in the gross margin amounts above excludes $39 million and $42 million of such expense for the years ended December 31, 2003 and 2002, respectively, related to assets that are not directly used in the generation of electricity.

Gross margin increased $15 million, or 1%, to $1.8 billion in 2003. The gross margin comparison was favorably impacted by $197 million due to regulatory-related retail clawback accrual adjustments (a $185 million charge, $120 million after-tax, in 2002 and a $12 million credit in 2003), as described in Note 14 to Financial Statements, and $53 million in lower operating costs and depreciation and amortization. Adjusting for these effects, margin declined $235 million, driven by the effect of lower retail sales volumes. The combined effect of higher costs of energy sold and lower results from hedging and risk management activities was essentially offset by higher sales prices. Higher costs of energy sold were driven by higher natural gas prices, but were mitigated by increased sourcing of retail and wholesale sales demand from Energy’s base load (nuclear-powered and coal-fired) generation plants. Base load supply of sales demand increased by five percentage points to 51% in 2003. The balance of sales demand in 2003 was met with gas-fired generation and purchased power.

A-9

Operating costs decreased $13 million, or 2%, to $685 million in 2003. The decline reflected $20 million due to one scheduled outage for nuclear generation unit refueling and maintenance in 2003 compared to two in 2002 and $15 million from various cost reduction initiatives, partially offset by $27 million in higher employee benefits and insurance costs. Depreciation and amortization related to generation assets decreased $40 million, or 10%, to $368 million. Of this decline, $37 million represented the effect of adjusted depreciation rates related to the generation fleet effective April 2003. The adjusted rates reflect an extension in the estimated average depreciable life of the nuclear generation facility’s assets of approximately 11 years (to 2041) to better reflect its useful life, partially offset by higher depreciation rates for lignite and gas facilities to reflect investments in emissions equipment made in recent years.

A decrease in depreciation and amortization (including amounts shown in the gross margin table above) of $43 million, or 10%, to $407 million in 2003 was driven by the adjusted depreciation rates related to the generation fleet due primarily to an extension of the estimated depreciable life of the nuclear generation facility to better reflect its useful life.

SG&A expenses declined $138 million, or 18%, to $636 million in 2003. Lower staffing and related administrative expenses contributed approximately $95 million to the decrease, reflecting cost reduction and productivity enhancing initiatives and a focus on activities in the Texas market. Lower SG&A expenses also reflected a $40 million decline in bad debt expense. In the retail electricity business, the effect of enhanced credit and collection activities was largely offset by increased write-offs arising from disconnections now allowed under new regulatory rules and increased churn of non-paying customers. The decrease in bad debt expense primarily reflected the wind down of retail gas (business customer supply) activities outside of Texas and the recording of related reserves in 2002.

Other income increased $15 million to $48 million in 2003. Other income in both periods included approximately $30 million of amortization of a gain on the sale of two generation plants in 2002. The 2003 period also included a $9 million gain on the sale of contracts related to retail gas activities outside of Texas.

Other deductions decreased $232 million to $22 million in 2003, reflecting a $237 million ($154 million after-tax) writedown in 2002 of an investment in two generation plant construction projects. In addition, both periods include several individually immaterial items.

Interest expense and related charges increased $108 million, or 50%, to $323 million in 2003. The increase reflects $108 million due to higher average interest rates as short-term borrowings were replaced with higher-rate long-term financing. An $11 million full-year effect of the amortization of the discount on the exchangeable subordinated notes issued in 2002 (subsequently exchanged by Energy for exchangeable preferred membership interests), was largely offset by the effect of lower average borrowing levels.

The effective income tax rate increased to 31.7% in 2003 from 26.7% in 2002. The increase was driven by the effect of comparable (to 2002) tax benefit amounts of depletion allowances and amortization of investment tax credits on a higher income base in 2003. (See Note 10 to Financial Statements for analysis of the effective tax rate.)

Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles increased $175 million, or 54%, to $497 million in 2003. Results in 2002 included an impairment charge related to generation plant construction projects and an accrual for retail clawback of $154 million after-tax and $120 million after-tax, respectively. Excluding these items, earnings declined on gross margin compression due to lower retail sales volumes as well as higher interest expense, partially offset by lower SG&A expenses. Net pension and postretirement benefit costs reduced net income by $36 million in 2003 and by $21 million in 2002.

Loss from the discontinued strategic retail services and Pedricktown, New Jersey (power production) operations (see Note 3 to Financial Statements) was $18 million in 2003 and $52 million in 2002. The decline reflected reductions in headcount and other SG&A-related expenses.

A cumulative effect of changes in accounting principles, representing an after-tax charge of $58 million in 2003, reflects the impact on commodity contract mark-to-market accounting from rescission of EITF 98-10 and the recording of asset retirement obligations under SFAS 143. (See Note 2 to Financial Statements.)

A-10

Energy

2002 compared to 2001

Energy’s operating revenues increased $274 million, or 4%, to $7.7 billion in 2002. Total retail and wholesale electricity revenues rose $176 million, or 2%, to $7.4 billion driven by higher wholesale volumes. Wholesale electric revenues increased $745 million to $841 million, reflecting the substantial increase in wholesale sales volumes due to the opening of the Texas market to competition. Retail electric revenues declined $569 million, or 8%, to $6.5 billion, reflecting a $613 million reduction due to lower volumes partially offset by a $44 million increase due to higher average pricing. The price variance reflects a shift in customer mix, partially offset by the effect of lower rates. A 9% decline in overall retail electric sales volumes was primarily due to the effects of increased competitive activity in the small business and large business market. Year-end residential electricity customer counts, reflecting losses in the historical service territory and gains in new territories due to competition, were about even with the prior year. The increase in revenues also reflects certain revenues and related retail and generation expenses that were the responsibility of the Electric Delivery segment in 2001, but are included in Energy revenues in 2002.

Net gains from hedging and risk management activities, which are reported in revenues and include both realized and unrealized gains and losses, declined $211 million to $147 million in 2002. Changes in these results reflect market price movements on commodity contracts entered into to hedge gross margin. Results from these activities included net unrealized losses of $113 million in 2002 and net unrealized gains of $318 million in 2001 arising from mark-to-market accounting.

Gross Margin

	Year Ended December 31,
	2002		% of Revenue		2001		% of Revenue
Operating revenues	$	7,678	100	%	$	7,404	100	%
Costs and expenses:
Cost of energy sold and delivery fees		4,771	62	%		4,800	65	%
Operating costs		698	9	%		671	9	%
Depreciation and amortization related to generation assets		408	5	%		391	5	%
Gross margin	$	1,801	24	%	$	1,542	21	%

The depreciation and amortization expense included in gross margin excludes $42 million and $4 million of such expense for 2002 and 2001, respectively, related to assets that are not directly used in the generation of electricity.

Gross margin increased $259 million, or 17%, to $1.8 billion in 2002. The increase was driven by the net favorable effect of lower average costs of energy sold, higher retail pricing and lower results from hedging and risk management activities. Higher gross margin also reflected significant growth in wholesale electricity sales volumes in the newly deregulated ERCOT, largely offset by the effect of lower retail electricity volumes. Gross margin in 2002 was negatively affected by the accrual of $185 million ($120 million after-tax) for regulatory-related retail clawback, which is reported in cost of energy sold and delivery fees. Operating costs rose $27 million, or 4%, to $698 million primarily due to the costs of refueling two units, compared to one in 2001, at the nuclear-powered generation plant.

An increase in depreciation and amortization (including amounts shown in the gross margin table above), of $55 million, or 14%, to $450 million was primarily due to investments in computer systems required to operate in the newly deregulated market and expansion of office facilities.

An increase in SG&A expenses of $463 million, or 149%, to $774 million reflected the effect of retail customer support costs and bad debt expense of approximately $150 million that were the responsibility of the Electric Delivery segment in 2001. The increase in SG&A expenses also reflected $199 million in higher staffing and other administrative costs, related to expanded retail sales operations and hedging activities, and higher bad debt expense of $90 million, all due largely to the opening of the Texas electricity market to competition. With the completion of the transition to competition in Texas, the industry-wide decline in portfolio management activities, and the expected deferral of deregulation of energy markets in other states, Energy initiated several cost savings initiatives in 2002. Such actions resulted in $31 million in severance charges in 2002, which contributed to the increase in SG&A expense.

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Franchise and revenue-based taxes rose $106 million to $120 million due to state gross receipts taxes that were the responsibility of the Electric Delivery segment in 2001. Effective in 2002, state gross receipts taxes related to electricity revenues are an expense of the Energy segment, while local gross receipts taxes are an expense of the Electric Delivery segment.

Other income increased by $31 million to $33 million, reflecting amortization of $30 million of a gain on the sale in 2002 of two generation plants.

Other deductions increased by $58 million to $254 million, reflecting a $237 million ($154 million after-tax) writedown in 2002 of an investment in two generation plant construction projects. Amounts in 2001 included $149 million ($97 million after-tax) in losses on the early extinguishment of debt under the debt restructuring and refinancing plan pursuant to the requirements of the 1999 Restructuring Legislation, a $22 million regulatory asset write-off pursuant to a regulatory order and $18 million in various asset writedowns.

Interest income declined by $28 million, or 74%, to $10 million primarily due to the recovery of under-collected fuel revenue on which interest income had been accrued under regulation in 2001.

Interest expense and other charges decreased $9 million, or 4%, to $215 million reflecting lower average debt levels, partially offset by higher rates and a decrease in capitalized interest.

The effective tax rate decreased to 26.7% in 2002 from 29.5% in 2001. The decrease was driven by the effect of comparable (to 2001) tax benefit amounts of depletion allowances and amortization of investment tax credits on a lower income base in 2002.

Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles decreased $269 million, or 46%, to $322 million in 2002. The decline was driven by an increase in SG&A expenses and higher franchise and revenue-based taxes, partially offset by the improved gross margin (net of the $120 million effect of the retail clawback accrual). The $154 million effect of the generation plant construction project writedown was partially offset by the $97 million effect of losses on early extinguishment of debt in 2001. Net pension and postretirement benefit costs reduced net income by $20 million in 2002 and $12 million in 2001.

The loss from the discontinued strategic retail services business and the Pedricktown, New Jersey operations was $52 million in 2002 and $28 million in 2001. Results in 2002 included approximately $10 million after-tax in asset writedowns.

Energy recorded an extraordinary loss in 2001 of $56 million (net of income tax benefit of $62 million) consisting of net charges related to the Settlement Plan to resolve all major open items related to the transition to deregulation. (See Note 4 to Financial Statements).

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Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2003, 2002 and 2001. The net changes in these assets and liabilities, excluding “cumulative effect of change in accounting principle” and “other activity” as described below, represent the net effect of recording unrealized gains/(losses) under mark-to-market 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.

	2003			2002			2001
Balance of net commodity contract assets at beginning of year	$	316		$	371		$	27
Cumulative effect of change in accounting principle (1)		(75	)		—			—
Settlements of positions included in the opening balance (2)		(145	)		(225	)		(54	)
Unrealized mark-to-market valuations of positions held at end of period (3)		9			153			368
Other activity (4)		3			17			30
Balance of net commodity contract assets at end of year	$	108		$	316		$	371

(1) Represents a portion of the pre-tax cumulative effect of the rescission of EITF 98-10 (see Note 2 to Financial Statements).

(2) Represents unrealized mark-to-market valuations of these positions recognized in earnings as of the beginning of the period.

(3) There were no significant changes in fair value attributable to changes in valuation techniques. Includes $14 million in origination gains recognized in 2002 related to nonderivative wholesale contracts.

(4) Includes initial values of positions involving the receipt or payment of cash or other consideration, such as option premiums, the amortization of such values and the exit of certain retail gas activities in 2003. Also includes $71 million of contract-related liabilities to Enron Corporation reclassified to other current liabilities in 2002. 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 that are reflected in changes in cash flow hedges and other derivative assets and liabilities. The total net effect of recording unrealized gains and losses under mark-to-market accounting is summarized as follows (excludes cumulative effect of change in accounting principle):

	2003			2002			2001
Unrealized gains/(losses) in commodity contract portfolio	$	(136	)	$	(72	)	$	314
Ineffectiveness gains/(losses) related to cash flow hedges		36			(41	)		4
Total unrealized gains/(losses)	$	(100	)	$	(113	)	$	318

These amounts are included in the “hedging and risk management activities” component of revenues.

As a result of guidance provided in EITF 02-3, Energy has not recognized origination gains on energy contracts in 2003. Energy recognized origination gains on retail sales contracts of $40 million in 2002 and $88 million in 2001. Because of the short-term nature of these contracts, a portion of these gains would have been recognized on a settlement basis in the year the origination gain was recorded.

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Maturity Table — Of the net commodity contract asset balance above at December 31, 2003, the amount representing unrealized mark-to-market net gains that have been recognized in current and prior years’ earnings is $121 million. The offsetting net liability of $13 million included in the December 31, 2003 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 December 31, 2003, scheduled by contractual settlement dates of the underlying positions.

	Maturity dates of unrealized net mark-to-market balances at December 31, 2003
Source of fair value	Maturity less than 1 year			Maturity of 1-3 years			Maturity of 4-5 years			Maturity in Excess of 5 years			Total
Prices actively quoted	$	36		$	12		$	(2	)	$	—		$	46
Prices provided by other external sources		21			53			1			(2	)		73
Prices based on models		(2	)		4			—			—			2
Total	$	55		$	69		$	(1	)	$	(2	)	$	121
Percentage of total fair value		45	%		57	%		—	%		(2	)%		100	%

As the above table indicates, essentially all of the unrealized mark-to-market valuations at December 31, 2003 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 through 2008. 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:

	Year Ended December 31,
	2003			2002			2001
Cash flow hedge activity (net of tax):
Net change in fair value of hedges – gains/(losses):
Commodities	$	(137	)	$	(96	)	$	16
Financing – interest rate swaps		—			(63	)		—
		(137	)		(159	)		16
Losses realized in earnings (net of tax):
Commodities		162			15			—
Financing – interest rate swaps		5			2			—
		167			17			—
Net income (loss) effect of cash flow hedges reported in other comprehensive income	$	30		$	(142	)	$	16

Energy has historically used, and expects to continue to use, derivative financial instruments that are highly effective in offsetting future cash flow volatility in interest rates and energy commodity prices. The amounts included in accumulated other comprehensive income are expected to offset the impact of rate or price changes on forecasted transactions. Amounts in accumulated other comprehensive income include (i) the value of the cash flow hedges (for the effective portion), based on current market conditions and (ii) the value of dedesignated and terminated cash flow hedges at the time of such dedesignation, less amortization, providing the transaction that was hedged is still probable. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled.

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Other comprehensive income also included adjustments related to minimum pension liabilities. Minimum pension liability adjustments were a gain of $37 million ($25 million after-tax) in 2003 and a loss of $60 million ($39 million after-tax) in 2002. The gain in 2003 reflected the impact of improved returns on plan assets. The minimum pension liability represents the difference between the excess of the accumulated benefit obligation over the plans’ assets and the liability in the balance sheet. The recording of the liability did not affect Energy’s financial covenants in any of its credit agreements.

Gains and losses on cash flow hedges are realized in earnings as the underlying hedged transactions are settled.

Energy adopted SFAS 133 effective January 1, 2001, and recorded a $1 million charge to other comprehensive income to reflect the fair value of derivatives effective as cash flow hedges at transition.

See also Note 13 to Financial Statements.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows — Cash flows provided by operating activities for the year ended December 31, 2003 were $1.4 billion compared to $994 million and $1.2 billion for the years ended December 31, 2002 and 2001, respectively. The increase in cash flows provided by operating activities in 2003 of $375 million, or 38%, reflected favorable working capital (accounts receivable, accounts payable and inventories) changes of $483 million, partially offset by payments of $102 million related to counterparty default events and the termination and liquidation of outstanding positions. Lower cash earnings of $214 million (net income adjusted for the significant noncash items identified in the statement of cash flows) were largely offset by the effect of timing of interest and federal income tax payments. The improved working capital primarily reflects the effect of billing and collection delays in 2002, due to data compilation and reconciliation issues among ERCOT and the market participants in the newly deregulated market, and includes $75 million in increased funding under the accounts receivable sale program.

The decrease in cash flows in 2002 from 2001 of $176 million reflected the effect of a return in 2001 of $227 million in margin deposits related to hedging and risk management activities (in exchange for letters of credit).

Cash flows used in financing activities were $1.7 billion, $407 million and $773 million during 2003, 2002 and 2001, respectively. The activity in 2003 reflected use of proceeds from the issuance of long-term debt, operating cash flows and cash on hand to reduce short and long-term borrowings. Net cash used in issuances and repayments of borrowings, including advances from affiliates, totaled $827 million in 2003 compared to net cash provided of $550 million in 2002. The note payable to Electric Delivery related to a regulatory liability was paid off in 2003 (payments of $170 million in 2003 and $180 million in 2002). Distributions paid to US Holdings totaled $750 million and $777 million in 2003 and 2002, respectively. Activity in 2001 reflected $404 million in repurchase of US Holdings’ member interest and $369 million in net repayments of borrowings.

Cash flows used in investing activities were $202 million in 2003 and $403 million in 2001. Investing activities provided $36 million in 2002. Capital expenditures, including nuclear fuel, were $207 million in 2003, $336 million in 2002 and $366 million in 2001. Capital expenditures are expected to total $325 million in 2004; the increase is due to a change in timing of activity originally planned to occur in 2003. Proceeds from asset sales in 2003 included $14 million from the sale of retail gas activities outside of Texas. Proceeds from asset sales in 2002 of $443 million reflected the sale of two generation plants in Texas.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $62 million for 2003. This difference represents the amortization of nuclear fuel, which is reported as cost of energy sold in the statement of income, consistent with industry practice.

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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 year ended December 31, 2003, Energy issued, redeemed, reacquired or made scheduled principal payments on long-term debt as follows:

	Issuances		Retirements
Fixed rate senior notes	$	1,250	$	72
Pollution control revenue bonds		567		639
Other long-term debt		3		—
Total	$	1,820	$	711

See Note 8 to Financial Statements for further detail of debt issuance and retirements, financing arrangements and capitalization.

Credit Facilities — At December 31, 2003, TXU Corp. and its US subsidiaries had credit facilities totaling $2.8 billion and expiring in 2005 and 2008, of which $2.3 billion was unused. These credit facilities support issuances of letters of credit and are available to Energy and Electric Delivery for borrowings. (See Note 7 to Financial Statements for details of arrangements.)

Exchangeable Preferred Membership Interests — In July 2003, Energy exercised its right, in a noncash transaction, to exchange its $750 million 9% Exchangeable Subordinated Notes due November 22, 2012 for exchangeable preferred membership interests with identical economic and other terms. These securities are exchangeable into TXU Corp. common stock at an exchange price of $13.1242 per share. The market price of TXU Corp. common stock on December 31, 2003 was $23.64. Any exchange of these securities into common stock would result in a proportionate write-off of the related unamortized discount as a charge to earnings. If all the securities had been exchanged into common stock on December 31, 2003, Energy would have recognized a pre-tax charge of $253 million.

Capitalization — The capitalization ratios of Energy at December 31, 2003, consisted of long-term debt (less amounts due currently) of 41%, exchangeable preferred membership interests (net of unamortized discount balance of $253 million) of 6% and common membership interests of 53%.

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, US 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 totaled $504 million and $429 million for 2003 and 2002, respectively. The increase of $75 million primarily reflects billing and collection delays in 2002 due to data compilation and reconciliation issues among ERCOT and the market participants in the newly deregulated market. See Note 7 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 $18 million and $603 million at December 31, 2003 and 2002, respectively. The decline reflects repayments of borrowings.

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Credit Ratings of TXU Corp. and its US Subsidiaries — The current credit ratings for TXU Corp., US Holdings and certain of its US subsidiaries are presented below:

	TXU Corp.	US Holdings	Electric Delivery	Energy
	(Senior Unsecured)	(Senior Unsecured)	(Secured)	(Senior Unsecured)
S&P	BBB-	BBB-	BBB	BBB
Moody’s	Ba1	Baa3	Baa1	Baa2
Fitch	BBB-	BBB-	BBB+	BBB

Moody’s currently maintains a negative outlook for TXU Corp. and a stable outlook for US Holdings, Energy and Electric Delivery. Fitch currently maintains a stable outlook for each such entity. S&P currently maintains a negative outlook for each such entity.

These ratings are investment grade, except 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 and its subsidiaries 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. Energy’s exchangeable preferred membership interests also limit its incurrence of additional indebtedness unless a leverage ratio and interest coverage test are met on a pro forma basis. As of December 31, 2003, Energy and its subsidiaries were 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 $130 million at December 31, 2003) 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 ratings decline.

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 $145 million.

In addition, Energy has a number of other contractual arrangements where the counterparties would have the right to request Energy to post collateral if its credit rating was downgraded below investment grade by all three rating agencies. The amount Energy would post under these transactions depends in part on the value of the contracts at that time. As of December 31, 2003, based on current market conditions, the maximum Energy would post for these transactions is $247 million. Of this amount, $228 million relates to one specific counterparty.

Energy is also the obligor on leases aggregating $161 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.

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ERCOT also has rules in place to assure adequate credit worthiness for parties that schedule power on the ERCOT System. Under those rules, if Energy’s credit rating were downgraded to below investment grade by any specified rating agency, Energy could be required to post collateral of approximately $32 million.

Cross Default Provisions

Certain financing arrangements of Energy 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 US Holdings or any subsidiary thereof on financing arrangements of $50 million or more would result in a cross default under the $1.4 billion US Holdings five-year revolving credit facility, the $400 million US Holdings credit facility and $30 million of TXU Mining senior notes (which have a $1 million cross default threshold).

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 Energy/Electric Delivery $450 million revolving credit facility. Under this credit facility, 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 TXU Corp. on indebtedness of $50 million or more would result in a cross default under the new $500 million five-year revolving credit facility.

A default or similar event under the terms of the Energy exchangeable preferred membership interests that results in the acceleration (or other mandatory repayment prior to the mandatory redemption date) of such security or the failure to pay such security at the mandatory redemption date would result in a default under Energy’s $1.25 billion senior unsecured notes.

Energy has entered into certain mining and equipment leasing arrangements aggregating $118 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 $31 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.

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 stated in the contracts, which thresholds vary.

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

A-18

Long-term Contractual Obligations and Commitments— The following table summarizes the contractual cash obligations of Energy under specified contractual obligations in effect as of December 31, 2003 (see Notes 8 and 15 to Financial Statements for additional disclosures regarding terms of these obligations.)

	Payment Due
Contractual Cash Obligations	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years
Long-term debt and preferred membership interest – principal and interest/dividends	$	222	$	471	$	678	$	5,962
Operating leases and capital lease obligations		68		141		144		461
Purchase obligations(b)		2,349		1,255		545		502
Other liabilities on the balance sheet
Notes or other liabilities due Electric Delivery		25		72		72		268
Pension and postretirement liabilities - plan contributions(c)		45		95		91		45
Total contractual cash obligations	$	2,709	$	2,034	$	1,530	$	7,238

(a) Includes short-term non-cancelable leases.

(b) Amounts presented for variable priced contracts assumed the year-end 2003 price remained in effect for all periods except where contractual price adjustments or index-based prices were specified.

(c) Projections of cash contributions to qualified pension and other postretirement benefit plans for the years ended 2004-2009.

The table above includes the contractual cash obligations related to the discontinued Pedricktown, New Jersey power production business and should be read in conjunction with Energy’s Form 10-Q for the period ended September 30, 2004 filed with the SEC on November 15, 2004.

The following contractual obligations were excluded from the purchase obligations disclosure in the table above:

(1) individual contracts that have an annual cash requirement of less than $1 million. (However, multiple contracts with one counterparty that are individually less than $1 million have been aggregated.)

(2) contracts that are cancelable without payment of a substantial cancellation penalty.

(3) employment contracts with management.

Guarantees — See Note 15 to Financial Statements for details of guarantees.

Investing Activities

In April 2002, Energy acquired a cogeneration and wholesale energy production business in New Jersey for $36 million in cash. The acquisition included a 122 megawatt (MW) combined-cycle power production facility and various contracts, including electric supply and gas transportation agreements. The acquisition was accounted for as a purchase business combination, and its results of operations are reflected in the consolidated financial statements from the acquisition date. In the second quarter of 2004, Energy finalized a plan to sell the production facility and exit the related power supply and gas transportation agreements.

In May 2002, Energy acquired a 260 MW combined-cycle power generation facility in northwest Texas through a settlement agreement which dismissed a lawsuit previously filed related to the plant, and included a nominal cash payment. Energy previously purchased all of the electrical output of this plant under a long-term contract.

In April 2002, Energy completed the sale of two electricity generation plants in the Dallas-Fort Worth area with total capacity of 2,334 MW for $443 million in cash. Concurrent with the sale, Energy entered into a tolling agreement to purchase power during the summer months through 2006. The terms of the tolling agreement include above-market pricing, representing a fair value liability of $190 million. A pretax gain on the sale of $146 million, net of the effects of the tolling agreement, was deferred and is being recognized in other income during summer months over the five-year term of the tolling agreement. Both the value of the tolling agreement and the deferred gain are reported in other liabilities in the balance sheet. The amount of the gain recognized in other income in 2003 was approximately $30 million.

A-19

Energy may pursue potential investment opportunities if it concludes that such investments are consistent with its business strategies and will dispose of nonstrategic assets to allow redeployment of resources into faster growing opportunities in an effort to enhance the long-term return to its shareholders.

Future Capital Requirements — Capital expenditures are estimated at $325 million for 2004, substantially all of which are for major repairs and organic growth of existing operations.

Consistent with industry practices, Energy has decided to replace the four steam generators in one of two generation units of the Comanche Peak nuclear plant in order to maintain the operating efficiency of the unit. An agreement for the manufacture and delivery of the equipment was completed in October 2003, and delivery is scheduled for late 2006. Estimated project capital requirements, including purchase and installation, are $175 million to $225 million. Cash outflows are expected to occur in 2004 through 2007, with the significant majority after 2004.

COMMITMENTS AND CONTINGENCIES

See Note 15 to Financial Statements for commitments and contingencies.

OFF BALANCE SHEET ARRANGEMENTS

See discussion above under Sale of Receivables and in Note 7 to Financial Statements.

REGULATION AND RATES

Information Request From CFTC — In October 2003, TXU Corp. received an informal request for information from the US Commodity Futures Trading Commission (CFTC) seeking voluntary production of information concerning disclosure of price and volume information furnished by TXU Portfolio Management Company LP to energy industry publications. The request seeks information for the period from January 1, 1999 to the present. TXU Corp. has cooperated with the CFTC, and is in the process of completing its response to such information request. TXU Corp. believes that TXU Portfolio Management Company LP was not engaged in any reporting of price or volume information that would in any way justify any action by the CFTC.

1999 Restructuring Legislation and Settlement Plan — On December 31, 2001, US Holdings filed the Settlement Plan with the Commission. It resolved all major pending issues related to US Holdings’ transition to electricity competition pursuant to the 1999 Restructuring Legislation. The Settlement Plan does not remove regulatory oversight of Electric Delivery’s business nor does it eliminate Energy’s price-to-beat rates and related fuel adjustments. The Settlement Plan became final and non-appealable in January 2003. See Note 14 to Financial Statements for the major elements of the Settlement Plan, the most significant of which on a go-forward basis are the retail clawback credit and the issuance of securitization bonds to recover regulatory asset stranded costs.

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 (and to offer, along with other pricing alternatives, this rate to small business customers) in the historical service territory. The 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. Energy increased its price-to-beat rate in March and August of 2003.

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:

• to use a stakeholder process to develop a new wholesale market model;

• to operate a voluntary day-ahead energy market;

• to directly assign all congestion rents to the resources that caused the congestion;

• to use nodal energy prices for resources;

• to provide information for energy trading hubs by aggregating nodes;

• to use zonal prices for loads; and

• to provide congestion revenue rights (but not physical rights).

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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. Energy is currently unable to predict the cost or impact of implementing any proposed change to the current wholesale market design.

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.

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, (x) 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, (xviii) 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.

A-21

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TXU Energy Company LLC:

We have audited the accompanying consolidated balance sheets of TXU Energy Company LLC and subsidiaries (Energy) as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, cash flows and membership interests for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of Energy’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the Notes to Financial Statements, Energy changed its method of accounting for certain contracts with the rescission of Emerging Issues Task Force Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.”

As discussed in Note 6 to the Notes to Financial Statements, in 2002 Energy adopted the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”

DELOITTE & TOUCHE LLP

Dallas, Texas

March 11, 2004 (December 10, 2004 as to Note 17)

A-22

TXU ENERGY COMPANY LLC

STATEMENTS OF CONSOLIDATED INCOME

	Year Ended December 31,
	2003			2002			2001
	Millions of Dollars
Operating revenues	$	7,986		$	7,678		$	7,404
Costs and expenses:
Cost of energy sold and delivery fees		5,117			4,771			4,800
Operating costs		685			698			671
Depreciation and amortization		407			450			395
Selling, general and administrative expenses		636			774			311
Franchise and revenue-based taxes		124			120			14
Other income		(48	)		(33	)		(2	)
Other deductions		22			254			196
Interest income		(8	)		(10	)		(38	)
Interest expense and related charges		323			215			224
Total costs and expenses		7,258			7,239			6,571
Income from continuing operations before income taxes, extraordinary loss and cumulative effect of changes in accounting principles		728			439			833
Income tax expense		231			117			242
Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		497			322			591
Loss from discontinued operations, net of tax effect		(18	)		(52	)		(28	)
Extraordinary loss, net of income tax		—			—			(56	)
Cumulative effect of changes in accounting principles, net of tax effect		(58	)		—			—
Net income	$	421		$	270		$	507

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

	Year Ended December 31,
	2003			2002			2001
	Millions of Dollars
Net income	$	421		$	270		$	507
Other comprehensive income (loss) —
Net change during period, net of tax effects:
Minimum pension liability adjustments (net of tax expense of $12 and benefit of $21)		25			(39	)		—
Cash flow hedges:
Net change in fair value of derivatives (net of tax benefit of $74 and $86, and expense of $9)		(137	)		(159	)		16
Amounts realized in earnings during the period (net of tax expense of $90 and $9)		167			17			—
Total		55			(181	)		16
Comprehensive income	$	476		$	89		$	523

See Notes to Financial Statements.

A-23

TXU ENERGY COMPANY LLC

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31,
	2003			2002			2001
	Millions of Dollars
Cash flows — operating activities
Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles	$	497		$	322		$	591
Adjustments to reconcile income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles to cash provided by operating activities:
Depreciation and amortization		469			499			508
Deferred income taxes and investment tax credits – net		10			(93	)		(209	)
Losses on early extinguishment of debt		—			—			149
Net gain from sale of assets		(45	)		(30	)		—
Reduction of revenues for earnings in excess of regulatory earnings cap		—			—			34
Net effect of unrealized mark-to-market valuations of commodity contracts		100			113			(318	)
Asset impairment charge		—			237			—
Retail clawback accrual increase (decrease)		(12	)		185			—
Over/(under) recovery of gas costs		—			—			568
Changes in operating assets and liabilities:
Affiliate accounts receivable/payable – net		(41	)		201			24
Accounts receivable – trade		386			(447	)		228
Inventories		(58	)		(96	)		(4	)
Accounts payable – trade		(30	)		116			(632	)
Margin deposits		25			(6	)		227
Commodity contract assets and liabilities – net		24			(45	)		(30	)
Other assets		(214	)		4			(33	)
Other liabilities		258			34			67
Cash provided by operating activities		1,369			994			1,170
Cash flows — financing activities
Issuances of long-term debt		1,820			811			2,788
Retirements/repurchases of debt		(711	)		(1,683	)		(2,428	)
Increase (decrease) in notes payable to banks		(282	)		282			—
Net change in advances from affiliates		(1,618	)		1,169			(568	)
Decrease in note payable to Electric Delivery related to a regulatory liability		(170	)		(180	)		—
Distribution paid to parent		(750	)		(777	)		—
Repurchase of member interests		—			—			(404	)
Debt premium, discount, financing and reacquisition expenses		(36	)		(29	)		(161	)
Cash used in financing activities		(1,747	)		(407	)		(773	)
Cash flows — investing activities
Capital expenditures		(163	)		(284	)		(327	)
Nuclear fuel		(44	)		(52	)		(39	)
Proceeds from sale of assets		24			443			—
Other		(19	)		(71	)		(37	)
Cash provided by (used in) investing activities		(202	)		36			(403	)
Cash provided by (used in) discontinued operations		(5	)		(40	)		7
Net change in cash and cash equivalents		(585	)		583			1
Cash and cash equivalents – beginning balance		603			20			19
Cash and cash equivalents – ending balance	$	18		$	603		$	20

See Notes to Financial Statements

A-24

TXU ENERGY COMPANY LLC

CONSOLIDATED BALANCE SHEETS

	December 31,
	2003		2002
	Millions of Dollars
ASSETS
Current assets:
Cash and cash equivalents	$	18	$	603
Advances to affiliates		289		—
Accounts receivable – trade		943		1,328
Inventories		386		351
Commodity contract assets		959		1,298
Other current assets		225		265
Total current assets		2,820		3,845
Investments		479		398
Property, plant and equipment — net		10,345		10,341
Goodwill		533		533
Commodity contract assets		121		476
Cash flow hedges and other derivative assets		88		14
Assets held for sale		59		76
Other noncurrent assets		127		106
Total assets	$	14,572	$	15,789
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Notes payable – banks	$	—	$	282
Long-term debt due currently		1		73
Advances from affiliates		—		1,329
Accounts payable – trade:
Affiliates (principally Electric Delivery)		211		248
All other		712		754
Notes or other liabilities due Electric Delivery		13		170
Commodity contract liabilities		913		1,138
Accrued taxes		276		164
Other current liabilities		564		640
Total current liabilities		2,690		4,798
Accumulated deferred income taxes		1,966		1,931
Investment tax credits		360		376
Commodity contract liabilities		59		320
Cash flow hedges and other derivative liabilities		140		150
Notes or other liabilities due Electric Delivery		424		437
Liabilities held for sale		11		4
Other noncurrent liabilities and deferred credits		1,342		1,122
Long-term debt, less amounts due currently		3,084		2,378
Exchangeable preferred membership interest, net of $253 discount		497		—
Total liabilities		10,573		11,516
Contingencies (Note 15)
Membership interests		3,999		4,273
Total liabilities and membership interests	$	14,572	$	15,789

See Notes to Financial Statements.

A-25

TXU ENERGY COMPANY LLC

STATEMENTS OF CONSOLIDATED MEMBERSHIP INTERESTS

	Year Ended December 31,
	2003			2002			2001
	Millions of Dollars
Membership interests:
Capital accounts:
Balance at beginning of year	$	4,438		$	4,196		$	4,121
Net income		421			270			507
Reduction in membership interest – amount of repurchases of common stock of US Holdings allocated to Energy		—			—			(404	)
Distribution paid to parent		(750	)		(777	)		—
Non-cash capital contribution related to issuance of exchangeable subordinated notes		—			266			—
Non-cash goodwill capital contribution		—			468			—
Conversion of capital from (to) advances		—			15			(28	)
Balance at end of year		4,109			4,438			4,196
Accumulated other comprehensive income, net of tax effects:
Minimum Pension Liability Adjustment:
Balance at beginning of year		(39	)		—			—
Change during the year		25			(39	)		—
Balance at end of year		(14	)		(39	)		—
Cash flow hedges (SFAS No. 133):
Balance at beginning of year		(126	)		16			—
Change during the year		30			(142	)		16
Balance at end of year		(96	)		(126	)		16
Total membership interests	$	3,999		$	4,273		$	4,212

See Notes to Financial Statements.

A-26

TXU ENERGY COMPANY LLC

NOTES TO FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS

Description of Business— Energy is engaged in electricity generation, retail and wholesale energy sales and hedging and risk management activities.

Energy is managed as an integrated business; consequently, there are no reportable business segments.

Discontinued Business —

See Note 3 for detailed information about discontinued operations.

Business Restructuring — The 1999 Restructuring Legislation restructured the electric utility industry in Texas and provided for a transition to competition in the generation and retail sale of electricity. TXU Corp. disaggregated its electric utility business, as required by the legislation, and restructured certain of its US businesses as of January 1, 2002 resulting in two new business operations:

• Electric Delivery – a utility regulated by the Commission that holds electricity transmission and distribution assets and engages in electricity delivery services.

• Energy – a competitive business that holds the power generation assets and engages in wholesale and retail energy sales and hedging/risk management activities.

The relationships of these entities and their rights and obligations with respect to their collective assets and liabilities are contractually described in a master separation agreement executed in December 2001.

The operating assets of Electric Delivery and Energy are located principally in the north-central, eastern and western parts of Texas.

A settlement of outstanding issues and other proceedings related to implementation of the 1999 Restructuring Legislation received final and non-appealable approval by the Commission in January 2003. See Note 14 for further discussion.

In addition, as of January 1, 2002, certain other businesses within the TXU Corp. system were transferred to Energy, including TXU Gas’ hedging and risk management business and its unregulated retail commercial/industrial (business) gas supply operation, as well as the fuel transportation and coal mining subsidiaries that primarily service the generation operations.

Other Business Changes — In April 2002, Energy acquired a cogeneration and wholesale energy production business in New Jersey for $36 million in cash. The acquisition included a 122 megawatt (MW) combined-cycle power production facility and various contracts, including electric supply and gas transportation agreements. The acquisition was accounted for as a purchase business combination. The results of the business are reported in discontinued operations as discussed in Note 3.

In May 2002, Energy acquired a 260 MW combined-cycle power generation facility in northwest Texas through a settlement agreement which dismissed a lawsuit previously filed related to the plant, and included a nominal cash payment. Energy previously purchased all of the electrical output of this plant under a long-term contract.

In April 2002, Energy completed the sale of two electricity generation plants in the Dallas-Fort Worth area with total capacity of 2,334 MW for $443 million in cash. Concurrent with the sale, Energy entered into a tolling agreement to purchase power during the summer months through 2006. The terms of the tolling agreement include above-market pricing, representing a fair value liability of $190 million. A pretax gain on the sale of $146 million, net of the effects of the tolling agreement, was deferred and is being recognized in other income during summer months over the five-year term of the tolling agreement. Both the value of the tolling agreement and the deferred gain are reported in other liabilities in the balance sheet. The amount of the gain recognized in other income in 2003 was approximately $30 million.

A-27

Basis of Presentation — The consolidated financial statements of Energy have been prepared in accordance with accounting principles generally accepted in the US and, except for the discontinuance of certain businesses and the adoption of EITF 02-3 and SFAS 143, as discussed in Note 2, on the same basis as the audited financial statements included in its 2002 Form 8-K. 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. The financial statements reflect reclassification of prior period amounts to conform to the current period presentation. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

The 2001 financial information includes information derived from the historical financial statements of US Holdings. Reasonable allocation methodologies were used to unbundle the financial statements of US Holdings between its generation and transmission and distribution (delivery) operations. Allocation of revenues reflected consideration of return on invested capital, which continues to be regulated for the delivery operations. US Holdings maintained expense accounts for each of its component operations. Costs of energy and expenses related to operations and maintenance and depreciation and amortization, as well as assets, such as property, plant and equipment, materials and supplies and fuel, were specifically identified by component operation and disaggregated. Various allocation methodologies were used to disaggregate revenues, common expenses, assets and liabilities between US Holdings’ generation and delivery operations. Further, certain financial information was deemed to be not reasonably allocable because of the changed nature of Energy’s and Electric Delivery’s operations subsequent to the opening of the market to competition, as compared to US Holdings’ previous operations. Such activities and related financial information consisted primarily of costs related to retail customer support activities, including billing and related bad debts expense, as well as regulated revenues associated with these costs. Financial information related to these activities was reported in Electric Delivery’s results of operations for the 2001 period. Interest and other financing costs were determined based upon debt allocated. Allocations reflected in the financial information for 2001 did not necessarily result in amounts reported in individual line items that are comparable to actual results in 2002 and 2003. Had the unbundled operations of US Holdings actually existed in 2001 as separate entities in a deregulated environment, their results of operations could have differed materially from those included in the historical financial statements included herein.

The following information regarding the impact of adopting SFAS 145 was previously provided in the 2002 Form 8-K.

Losses on Extinguishments of Debt — As a result of the adoption of SFAS 145 as of January 1, 2003, any gain or loss on the early extinguishment of debt that was classified as an extraordinary item in prior periods in accordance with SFAS 4 is required to be reclassified if it does not meet the criteria of an extraordinary item as defined by APB Opinion 30.

As a result of US Holdings’ debt restructuring and refinancings in the fourth quarter of 2001, Energy recorded a loss on the early extinguishment of debt of $97 million (net of income tax benefit of $52 million).

In accordance with SFAS 145, the income statement for the year ended December 31, 2001 reflects the classification of these losses, previously reported as extraordinary, as shown below:

2001:
Extraordinary loss, net of tax – as reported	$	(153	)
Reclassifications to:
Other deductions		149
Income tax expense		(52	)
Extraordinary loss, net of tax – as adjusted	$	(56	)

The reclassifications had no effect on net income. The discussion of extraordinary loss in Note 4, income tax information in Note 10, and quarterly results and components of other deductions in Note 16 reflect the reclassifications.

A-28

Use of Estimates — The preparation of Energy’s financial statements requires management to make estimates and assumptions about future events that affect the reporting and disclosure of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including mark-to-market valuation adjustments. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made as a result of changes in previous estimates or assumptions during the current year.

Financial Instruments and Mark-to-Market Accounting — Energy enters into financial instruments, including options, swaps, futures, forwards and other contractual commitments primarily to manage energy price risk and interest rate risks. These financial instruments are accounted for in accordance with SFAS 133 as well as, prior to October 26, 2002, EITF 98-10. See Note 2 for the effects of EITF 02-3, under which only financial instruments that are derivatives are subject to mark-to-market accounting.

SFAS 133 requires the recognition of derivatives in the balance sheet, the measurement of those instruments at fair value and the recognition in earnings of changes in the fair value of derivatives. This recognition is referred to as “mark-to-market” accounting. SFAS 133 provides exceptions to this accounting if (a) the derivative is deemed to represent a transaction in the normal course of purchasing from a supplier and selling to a customer, or (b) the derivative is deemed to be a cash flow or fair value hedge. In accounting for cash flow hedges, derivative assets and liabilities are recorded on the balance sheet at fair value with an offset in other comprehensive income. Amounts are reclassified from other comprehensive income to earnings as the underlying transactions occur and realized gains and losses are recognized in earnings. Fair value hedges are recorded as derivative assets or liabilities with an offset to the carrying value of the related asset or liability. Any hedge ineffectiveness related to cash flow and fair value hedges is recorded in earnings.

Energy documents designated commodity, debt-related and other hedging relationships, including the strategy and objectives for entering into such hedge transactions and the related specific firm commitments or forecasted transactions. Energy applies hedge accounting in accordance with SFAS 133 for these non-trading transactions, providing the underlying transactions remain probable of occurring. Effectiveness is assessed based on changes in cash flows of the hedges as compared to changes in cash flows of the hedged items. In its risk management activities, Energy hedges future electricity revenues using natural gas instruments; such cross-commodity hedges are subject to ineffectiveness calculations that can result in mark-to-market gains and losses.

Interest rate swaps entered into in connection with indebtedness to manage interest rate risks are accounted for as cash flow hedges if the swap converts rates from variable to fixed and are accounted for as fair value hedges if the swap converts rates from fixed to variable.

Revenue Recognition — Energy records revenue for retail and wholesale energy sales under the accrual method. Retail electric revenues are recognized when the commodity is provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the value of the commodity consumed from the meter reading date to the end of the period. The unbilled revenue is estimated at the end of the period based on estimated daily consumption after the meter read date to the end of the period. Estimated daily consumption is derived using historical customer profiles adjusted for weather and other measurable factors affecting consumption.

Realized and unrealized gains and losses (including hedge ineffectiveness) from transacting in energy-related contracts, principally for the purpose of hedging margins on sales of energy, are reported as a component of revenues.

The historical financial statements for 2001 included adjustments made to revenues for over/under recovered fuel costs. To the extent fuel costs incurred exceeded regulated fuel factor amounts included in customer billings, Energy recorded revenues on the basis of its ability and intent to obtain regulatory approval for rate surcharges on future customer billings to recover such amounts. Conversely, to the extent fuel costs incurred were less than amounts included in customer billings, revenues were reduced. Following deregulation of the Texas market on January 1, 2002, any changes to the fuel factor component of the price-to-beat rates are recognized in revenues when power is provided to customers.

Other than the purchase of fuel for gas-fired generation, the significant majority of Energy’s physical natural gas purchases and sales represent economic hedging activities; consequently, such transactions have been reported net as a component of revenues. As a result of the issuance of EITF 03-11, sales of natural gas to retail business customers are reported gross effective October 1, 2003.

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Accounting for Contingencies – The financial results of Energy may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. These determinations are based on management’s interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events.

Investments — Deposits in a nuclear decommissioning trust fund are carried at fair value in the balance sheet, with the cumulative increase in fair value recorded as a liability to reflect the statutory nature of the trust. Investments in unconsolidated business entities over which Energy has significant influence but does not maintain effective control, generally representing ownership of at least 20% and not more than 50% of common equity, are accounted for under the equity method. Assets related to employee benefit plans are held to satisfy deferred compensation liabilities and are recorded at market value. (See Note 5 – Investments.)

Property, Plant and Equipment —The cost of generation property additions prior to July 1, 1999 includes labor and materials, applicable overhead and payroll-related costs and an allowance for funds used during construction. Generation property additions subsequent to July 1, 1999, and other property are stated at cost.

Depreciation of Energy’s property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation also includes an amount for decommissioning costs for the nuclear-powered electricity generation plant (Comanche Peak), which is being accrued over the lives of the units. Consolidated depreciation as a percent of average depreciable property for Energy approximated 2.2% for 2003, 2.6% for 2002 and 2.7% for 2001. See discussion below under Changes in Accounting Standards regarding SFAS 143.

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 investments in emissions control equipment. The net impact of these changes was a reduction in depreciation expense of $37 million (pre-tax) and an increase in net income of $24 million for the year ended December 31, 2003.

The nuclear-powered generation units were originally estimated to have a useful life of 40 years, based on the life of the operating licenses granted by the NRC. Over the last several years, the NRC has granted 20-year extensions to the initial 40-year terms for several commercial power reactors. Based on these extensions and current expectations of industry practice, the useful life of the nuclear-powered generation units is now estimated to be 60 years. TXU Corp. expects to file a license extension request in accordance with timing and other provisions established by the NRC.

Energy capitalizes computer software costs in accordance with SOP 98-1. These costs are being amortized over periods ranging from three to ten years. (See Note 6 under Intangible Assets for more information.)

Interest Capitalized and Allowance For Funds Used During Construction (AFUDC) — AFUDC is a cost accounting procedure whereby amounts based upon interest charges on borrowed funds and a return on equity capital used to finance construction are added to utility plant and equipment being constructed. Prior to July 1, 1999, AFUDC was capitalized for all expenditures for ongoing construction work in progress and nuclear fuel in process not otherwise included in rate base by regulatory authorities. As a result of the 1999 Restructuring Legislation, only interest is capitalized during any generation construction since 1999. Interest on qualifying projects for businesses that no longer apply SFAS 71 is capitalized in accordance with SFAS 34. See Note 16 for detail of amounts. The amount of interest capitalized in 2003 and 2002 was $7 million and $6 million, respectively.

Impairment of Long-Lived Assets — Energy evaluates the carrying value of long-lived assets to be held and used when events and circumstances warrant such a review. The carrying value of long-lived assets would be considered impaired when the projected undiscounted cash flows are less than the carrying value. In that event, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by available market valuations or, if applicable, discounted cash flows.

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In 2002, Energy recorded an impairment charge of $237 million ($154 million after-tax) for the writedown of two generation plant construction projects as a result of weaker wholesale electricity market conditions and reduced planned developmental capital spending. Fair value was determined based on appraisals of property and equipment. The charge is reported in other deductions.

Goodwill and Intangible Assets — Energy evaluates goodwill for impairment at least annually (as of October 1) in accordance with SFAS 142. The impairment tests performed are based on discounted cash flow analyses. No goodwill impairment has been recognized.

Major Maintenance— Major maintenance outage costs related to nuclear fuel reloads, as well as the costs of other major maintenance programs, are charged to expense as incurred.

Amortization of Nuclear Fuel — The amortization of nuclear fuel in the reactors is calculated on the units-of-production method and is included in cost of energy sold.

Defined Benefit Pension Plans and Other Postretirement Benefit Plans— Energy is a participating employer in the 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. See Note 11 for information regarding retirement plans and other postretirement benefits.

Franchise and Revenue-Based Taxes — Franchise and revenue-based taxes such as gross receipts taxes are not a “pass through” item such as sales and excise taxes. Gross receipts taxes are assessed to Energy and its subsidiaries by state and local governmental bodies, based on revenues, as a cost of doing business. Energy records gross receipts tax as an expense. Rates charged to customers by Energy are intended to recover the taxes, but Energy is not acting as an agent to collect the taxes from customers.

Income Taxes — TXU Corp. and its US subsidiaries file a consolidated federal income tax return, and federal income taxes are allocated to subsidiaries based upon their respective taxable income or loss. Investment tax credits are amortized to income over the estimated service lives of the properties. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities.

Cash Equivalents — For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.

Changes in Accounting Standards — In October 2002, the EITF, through EITF 02-3, rescinded EITF 98-10, which required mark-to-market accounting for all trading activities. SFAS 143, regarding asset retirement obligations, became effective on January 1, 2003. As a result of the implementation of these two accounting standards, Energy recorded a cumulative effect of changes in accounting principles as of January 1, 2003. (See Note 2 for a discussion of the impacts of these two accounting standards.)

As a result of guidance provided in EITF 02-3, in 2003 Energy discontinued recognizing origination gains on energy contracts. For 2002 and 2001, Energy recognized $40 million and $88 million in origination gains on retail sales contracts, respectively. Because of the short-term nature of these contracts, a portion of these gains would have been recognized on a settlement basis in the year the origination gain was recorded.

SFAS 146 became effective on January 1, 2003. SFAS 146 requires that a liability for costs associated with an exit or disposal activity be recognized only when the liability is incurred and measured initially at fair value. The adoption of SFAS 146 did not materially impact results of operations for 2003.

FIN 45 was issued in November 2002 and requires recording the fair value of guarantees upon issuance or modification after December 31, 2002. The interpretation also requires expanded disclosures of guarantees (see Note 15 under Guarantees). The adoption of FIN 45 did not materially impact results of operations for 2003.

FIN 46, which was issued in January 2003, provides guidance related to identifying variable interest entities and determining whether such entities should be consolidated. On October 8, 2003, the FASB decided to defer implementation of FIN 46 until the fourth quarter of 2003. This deferral only applies to variable interest entities that existed prior to February 1, 2003. The implementation of FIN 46 in the fourth quarter 2003 did not impact results of operations.

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SFAS 149 was issued in April 2003 and became effective for contracts entered into or modified after June 30, 2003. SFAS 149 clarifies what contracts may be eligible for the normal purchase and sale exception, the definition of a derivative and the treatment in the statement of cash flows when a derivative contains a financing component. Also, EITF 03-11 was issued in July 2003 and became effective October 1, 2003 and, among other things, discussed the nature of certain power contracts. As a result of the issuance of SFAS 149 and EITF 03-11, certain commodity contract hedges were replaced with another type of hedge that is subject to effectiveness testing. The adoption of these changes did not materially impact results of operations for 2003.

EITF 03-11 also addressed the presentation in the income statement of physically settled commodity derivatives, providing guidance as to whether such transactions should be reported on a net or gross (sales and cost of sales) basis. Effective October 1, 2003, Energy began reporting certain retail sales of natural gas to business customers on a gross basis. The effect of this change was an increase in revenues, and cost of energy sold of $34 million for the period since that date. Net income was unaffected by the change.

SFAS 150 was issued in May 2003 and became effective June 1, 2003 for new financial instruments and July 1, 2003 for existing financial instruments. SFAS 150 requires that mandatorily redeemable preferred securities be classified as liabilities beginning July 1, 2003. In July 2003, Energy exercised its right to exchange its $750 million 9% Exchangeable Subordinated Notes due 2012 for exchangeable preferred membership interests with identical economic and other terms (see Note 8). Because the exchangeability feature of these preferred securities provides for the holders to exchange the securities with TXU Corp. for TXU Corp. common stock, the securities are deemed to be mandatorily redeemable by Energy. Therefore, in accordance with SFAS 150, the December 31, 2003 balance sheet reflects the classification of these securities (net of $253 million in unamortized discount) as liabilities.

EITF 01-8 was issued in May 2003 and is effective prospectively for arrangements that are new, modified or committed to beginning July 1, 2003. This guidance requires that certain types of arrangements be accounted for as leases, including tolling and power supply contracts, take-or-pay contracts and service contracts involving the use of specific property and equipment. The adoption of this change did not materially impact results of operations for 2003.

2. CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

The following summarizes the effect on results for 2003 for 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.

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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

The asset retirement liability at December 31, 2003 was $599 million, comprised of a $554 million liability as a result of adoption of SFAS 143, $36 million of accretion during the twelve months of 2003 and $2 million in new asset retirement obligations, reduced by $19 million in reclamation payments. The asset retirement obligations were adjusted upward by $26 million, or 5%, due to revisions in estimated cash flows.

With respect to nuclear decommissioning costs, Energy believes that the adoption of SFAS 143 results primarily in timing differences in the recognition of asset retirement costs that Energy is currently recovering through the regulatory process.

On a pro forma basis, assuming SFAS 143 had been adopted at the beginning of the period, earnings for 2002 would have increased by $6.5 million after-tax, and the liability for asset retirement obligations as of December 31, 2001 and 2002 would have been $522 million and $554 million, respectively. Earnings for the year ended December 31, 2001 would not have been impacted by the adoption of SFAS 143.

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3. DISCONTINUED OPERATIONS

The following summarizes the historical consolidated financial information of the various businesses to be sold:

	Strategic Retail Services			Pedrick- town			Total
2003
Operating revenues	$	60		$	22		$	82
Operating costs and expenses		60			28			88
Other deductions (income) — net		11			—			11
Interest income		(1	)		—			(1	)
Interest expense and related charges		1			—			1
Operating loss before income taxes		(11	)		(6	)		(17	)
Income tax benefit		(4	)		(2	)		(6	)
Charges related to exit (after-tax)		7			—			7
Loss from discontinued operations	$	(14	)	$	(4	)	$	(18	)
2002
Operating revenues	$	47		$	18		$	65
Operating costs and expenses		122			22			144
Interest expense and related charges		1			—			1
Operating loss before income taxes		(76	)		(4	)		(80	)
Income tax benefit		(27	)		(1	)		(28	)
Loss from discontinued operations	$	(49	)	$	(3	)	$	(52	)
2001
Operating revenues	$	54		$	—		$	54
Operating costs and expenses		94			—			94
Other deductions (income) — net		2			—			2
Interest expense and related charges		1			—			1
Operating loss before income taxes		(43	)		—			(43	)
Income tax benefit		(15	)		—			(15	)
Loss from discontinued operations	$	(28	)	$	—		$	(28	)

Strategic Retail Services — In December 2003, Energy finalized a plan to sell its strategic retail services business, which is engaged principally in providing energy management services to businesses and other organizations. Results of discontinued operations reflect a charge in the fourth quarter of 2003 of $10.3 million ($6.7 million after-tax) to impair long-lived assets and accrue liabilities under operating leases from which there will be no future benefit as a result of the decision to exit the business.

Pedricktown — In the second quarter of 2004, Energy finalized a plan to sell the Pedricktown power production facility and exit the related power supply and gas transportation agreements. Energy had acquired the cogeneration and wholesale energy production business in Pedricktown, New Jersey for $36 million in cash in April 2003. The business included a 122 megawatt (MW) combined-cycle power production facility and various contracts, including electric supply and gas transportation agreements.

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

	December 31, 2003
	Strategic Retail Services		Pedrick- town		Total
Current assets	$	3	$	1	$	4
Investments		4		—		4
Property, plant and equipment		5		37		42
Other noncurrent assets		2		7		9
Assets held for sale	$	14	$	45	$	59
Current liabilities	$	—	$	2	$	2
Noncurrent liabilities		—		9		9
Liabilities held for sale	$	—	$	11	$	11

4. EXTRAORDINARY LOSS

As a result of the implementation of SFAS 145, losses related to early extinguishment of debt that were previously reported as extraordinary items have been reclassified (see Note 1 under Losses on Extinguishments of Debt).

In the fourth quarter of 2001, US Holdings and the Commission reached agreement on the Settlement Plan, which resolved a number of issues related to transition to retail competition. As a result, Energy recorded an extraordinary loss of $56 million (net of income tax benefit of $62 million). The loss was classified as an extraordinary item in accordance with SFAS 101. The Settlement Plan addressed, among other items, unrecovered fuel cost, stranded costs and other generation-related regulatory assets, and the above-market pricing of certain power purchase contracts. See also Note 14.

5. INVESTMENTS

The following information is a summary of the investment balance as of December 31, 2003 and 2002 (in millions):

	December 31,
	2003		2002
Nuclear decommissioning trust	$	323	$	266
Land		87		88
Assets related to employee benefit plans		40		28
Miscellaneous other		29		16
Total investments	$	479	$	398

Nuclear Decommissioning Trust — Deposits in a trust fund for costs to decommission the Comanche Peak nuclear-powered generation plant are carried at fair value, with the cumulative increase in fair value recorded as a liability. (Also see Note 15 – under Nuclear Decommissioning). Decommissioning costs are being recovered from Electric Delivery’s customers as a transmission and distribution charge over the life of the plant and deposited in the trust fund. Activity in the trust fund was as follows:

	December 31, 2003
	Cost		Unrealized gain		Unrealized (loss)			Fair market value
Debt securities	$	139	$	6	$	(2	)	$	143
Equity securities		126		66		(12	)		180
	$	265	$	72	$	(14	)	$	323

	December 31, 2002
	Cost		Unrealized gain		Unrealized (loss)			Fair market value
Debt securities	$	128	$	10	$	(1	)	$	137
Equity securities		111		37		(19	)		129
	$	239	$	47	$	(20	)	$	266

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Debt securities held at December 31, 2003 mature as follows: $56 million in one to five years, $51 million in five to ten years and $36 million after ten years.

Analysis of Certain Investments with Unrealized Losses at December 31, 2003:

	Investments That Have Been in a Continuous Unrealized Loss Position for:
	Less than 12 months					12 months or longer					Total
Description of Securities	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Nuclear Decommissioning Trust:
Debt Securities	$	12	$	—		$	19	$	(2	)	$	31	$	(2	)
Equity Securities		4		(1	)		24		(11	)		28		(12	)
Total	$	16	$	(1	)	$	43	$	(13	)	$	59	$	(14	)

The assets that have experienced unrealized losses are all high-quality securities that are part of the long-term investment strategy and are expected to recover within a reasonable period of time. Therefore they are not deemed to be other-than-temporary impairments.

6. GOODWILL AND OTHER INTANGIBLE ASSETS

Intangible Assets— SFAS 142 became effective for Energy on January 1, 2002. SFAS 142 requires, among other things, the allocation of goodwill to reporting units based upon the current fair value of the reporting units, and the discontinuance of goodwill amortization. The amortization of Energy’s existing goodwill ($1 million annually) ceased effective January 1, 2002. SFAS 142 also requires additional disclosures regarding intangible assets (other than goodwill) that are amortized or not amortized:

	As of December 31, 2003						As of December 31, 2002
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Amortized intangible assets (included in property, plant and equipment):
Capitalized software	$	241	$	112	$	129	$	220	$	78	$	142
Land easements		11		8		3		12		9		3
Mineral rights and other		31		22		9		31		20		11
Total	$	283	$	142	$	141	$	263	$	107	$	156

Aggregate Energy amortization expense for intangible assets, excluding goodwill, for the years ended December 31, 2003, 2002 and 2001 was $37 million, $44 million and $4 million, respectively. At December 31, 2003, the weighted average useful lives of capitalized software, land easements and mineral rights noted above were 6 years, 58 years and 40 years, respectively. Estimated amounts of amortization expense for the next five years are as follows:

Year
2004	$	37
2005		25
2006		20
2007		16
2008		13

At December 31, 2003 and 2002, goodwill of $533 million was stated net of previously recorded accumulated amortization of $60 million. In connection with the transfer of certain businesses from TXU Gas to Energy as part of the business restructuring described in Note 1, $468 million of goodwill arising from TXU Corp.’s 1997 acquisition of ENSERCH Corporation was allocated to these businesses and is reflected in the balance sheet of Energy.

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7. SHORT-TERM FINANCING

Credit Facilities— At December 31, 2003, credit facilities available to TXU Corp. and its US subsidiaries were as follows:

			At December 31, 2003
Facility	Expiration Date	Authorized Borrowers	Facility Limit		Letters of Credit		Cash Borrowings		Availability
Five-Year Revolving Credit Facility	February 2005	US Holdings	$	1,400	$	44	$	—	$	1,356
Revolving Credit Facility	February 2005	Energy, Electric Delivery		450		—		—		450
Three-Year Revolving Credit Facility	May 2005	US Holdings (a)		400		—		—		400
Five-Year Revolving Credit Facility	August 2008	TXU Corp.		500		422		—		78
Total			$	2,750	$	466	$	—	$	2,284

(a) Previously TXU Corp.

In April 2003, Energy and Electric Delivery entered into a joint $450 million revolving credit facility to be used for working capital and other general corporate purposes. Up to $450 million of letters of credit may be issued under the facility.

The US Holdings, Energy and Electric Delivery facilities provide back-up for any future issuance of commercial paper by Energy and Electric Delivery. At December 31, 2003, there was no such outstanding commercial paper.

In addition to providing back-up of commercial paper issuance by Energy and Electric Delivery, the credit facilities above are for general corporate and working capital purposes, including providing collateral support for Energy’s hedging and risk management activities.

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, US 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 December 31, 2003, the maximum amount of undivided interests that could be sold by TXU Receivables Company was $600 million.

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 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 Company, a direct subsidiary of TXU Corp. The program fees (losses on sale), which consist primarily of interest costs on the underlying financing, were $10 million and $20 million for 2003 and 2002, respectively, and approximated 2.6% and 3.7% for 2003 and 2002, 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 $6 million and $8 million for 2003 and 2002, respectively, compensates TXU Business Services Company for its services as collection agent, including maintaining the detailed accounts receivable collection records.

The December 31, 2003 balance sheet reflects $933 million face amount of trade accounts receivable reduced by $504 million of undivided interests sold by TXU Receivables Company. Funding under the program increased $75 million for the year ended December 31, 2003, primarily due to the effect of improved collection

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trends. Funding under the program for the year ended December 31, 2002 decreased $1 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 years ended December 31, 2003 and 2002 were as follows:

	Year Ended December 31,
	2003			2002
	(millions of dollars)
Cash collections on accounts receivable	$	6,791		$	5,611
Face amount of new receivables purchased		(6,350	)		(6,300	)
Discount from face amount of purchased receivables		16			28
Servicing fees paid		(6	)		(8	)
Program fees paid		(10	)		(20	)
Increase (decrease) in subordinated notes payable		(516	)		690
Energy’s operating cash flows (provided) used under the program	$	(75	)	$	1

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.

In June 2003, the program was amended to provide temporarily higher delinquency and default compliance ratios and temporary relief from the loss reserve formula, which allowed for increased funding under the program. The June amendment reflected the billing and collection delays previously experienced as a result of new systems and processes in Energy and ERCOT for clearing customers’ switching and billing data upon the transition to competition. In August 2003, the program was amended to extend the term to July 2004, as well as to extend the period providing temporarily higher delinquency and default compliance ratios through December 31, 2003. The higher delinquency and default compliance ratios were not extended after December 31, 2003 as no relief from program delinquency and default compliance ratios is expected to be required.

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. The billing delays have been largely resolved. 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. Prior to the August 2003 amendment extending the program, originator eligibility was predicated on the maintenance of an investment grade credit rating.

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8. LONG-TERM DEBT

Long-Term Debt— At December 31, 2003 and 2002, the long-term debt of Energy and its consolidated subsidiaries consisted of the following:

	December 31,
	2003		2002
Pollution Control Revenue Bonds:
Brazos River Authority:
Floating Taxable Series 1993 due June 1, 2023	$	—	$	44
3.000% 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)		118		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
4.950% Fixed Series 2001A due October 1, 2030, remarketing date April 1, 2004(a)		121		121
4.750% 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)		274		274
1.250% Floating Series 2001D due May 1, 2033		271		271
Floating Taxable Series 2001F due December 31, 2036		—		39
Floating Taxable Series 2001G due December 1, 2036		—		72
Floating Taxable Series 2001H due December 1, 2036		—		31
1.180% Floating Taxable Series 2001I due December 1, 2036(b)		63		63
1.250% Floating Series 2002A due May 1, 2037(b)		61		61
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)		44		—
6.300% Fixed Series 2003B due July 1, 2032		39		—
6.750% Fixed Series 2003C due October 1, 2038		72		—
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014(a)		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
4.000% Fixed Series 2001C due May 1, 2028, remarketing date November 1, 2003(a)		—		70
Floating Taxable Series 2001D due December 31, 2036		—		12
Floating Taxable Series 2001E due December 31, 2036		—		45
5.800% Fixed Series 2003A due July 1, 2022		12		—
6.150% Fixed Series 2003B due August 1, 2022		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:
7.000% Fixed Senior Notes - TXU Mining due May 1, 2003		—		72
6.875% Fixed Senior Notes - TXU Mining due August 1, 2005		30		30
9.000% Fixed Exchangeable Subordinated Notes due November 22, 2012		—		750
6.125% Fixed Senior Notes due March 15, 2008		250		—
7.000% Fixed Senior Notes due March 15, 2013 (c)		1,000		—
Capital lease obligations		13		10
Other		7		8
Unamortized premium and discount and fair value adjustments		10		(264	)
Total Energy		3,085		2,451
Less amount due currently		1		73
Total long-term debt	$	3,084	$	2,378

(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 December 31, 2003. 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 $500 million principal amount.

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New Debt Issuances in 2003:

In March 2003, Energy issued $1.25 billion aggregate principal amount of senior unsecured notes in two series in a private placement with registration rights. One series in the amount of $250 million is due March 15, 2008, and bears interest at the annual rate of 6.125%, and the other series in the amount of $1 billion is due March 15, 2013, and bears interest at the annual rate of 7%. In August 2003, Energy entered into interest rate swap transactions through 2013, which are being accounted for as fair value hedges, to effectively convert $500 million of the notes to floating interest rates.

Debt Repayments in 2003:

In May 2003, $72 million principal amount of the 7% TXU Mining fixed rate senior notes were repaid at maturity.

Debt Remarketings and Other Activity:

In November 2003, the Brazos River Authority Series 2001D pollution control revenue bonds (aggregate principal amount of $271 million) were remarketed and converted from a multiannual mode to a weekly rate mode, and the Sabine River Authority Series 2001C pollution control revenue bonds (aggregate principal amount of $70 million) were purchased upon mandatory tender. Energy intends to remarket these bonds in the first quarter of 2004.

In October 2003, the Brazos River Authority issued $72 million aggregate principal amount of Series 2003C pollution control revenue bonds and $31 million aggregate principal amount of Series 2003D pollution control revenue bonds for Energy. The Series 2003C bonds will bear interest at an annual rate of 6.75% until maturity in 2038. The Series 2003D bonds will bear interest at an annual rate of 5.40% until their mandatory tender date in 2014, at which time they will be remarketed. Proceeds from the issuance of the Series 2003C and Series 2003D bonds were used to refund the $72 million aggregate principal amount of Brazos River Authority Taxable Series 2001G and the $31 million aggregate principal amount of Series 2001H variable rate pollution control revenue bonds, both due December 1, 2036. The Sabine River Authority also issued $45 million aggregate principal amount of Series 2003B pollution control revenue bonds for Energy. The Series 2003B bonds will bear interest at an annual rate of 6.15% until maturity in 2022, however they become callable in 2013. Proceeds from the issuance of the Series 2003B bonds were used to refund the $45 million aggregate principal amount of Sabine River Authority Taxable Series 2001E variable rate pollution control revenue bonds due December 1, 2036.

In July 2003, the Brazos River Authority issued $39 million aggregate principal amount of Series 2003B pollution control revenue bonds for Energy. The bonds will bear interest at an annual rate of 6.30% until maturity in 2032. Proceeds from the issuance of the bonds were used to refund the $39 million aggregate principal amount of Brazos River Authority Taxable Series 2001F variable rate pollution control revenue bonds due December 31, 2036. The Sabine River Authority also issued $12 million aggregate principal amount of Series 2003A pollution control revenue bonds for Energy. The bonds will bear interest at an annual rate of 5.80% until maturity in 2022. Proceeds from the issuance of these bonds were used to refund the $12 million aggregate principal amount of Sabine River Authority Taxable Series 2001D pollution control revenue bonds due December 31, 2036.

In May 2003, the Brazos River Authority Series 1994A and the Trinity River Authority Series 2000A pollution control revenue bonds (aggregate principal amount of $53 million) were purchased upon mandatory tender. In July 2003, the bonds were remarketed and converted from a floating rate mode to a multiannual mode at an annual rate of 3.00% and 6.25%, respectively. The rate on the 1994A bonds will remain in effect until their mandatory remarketing date of May 1, 2005. The rate on the 2000A bonds will remain in effect until their maturity in 2028.

In April 2003, the Brazos River Authority Series 1999A pollution control revenue bonds, with an aggregate principal amount of $111 million, were remarketed. The bonds now bear interest at a fixed annual rate of 7.70% and are callable beginning on April 1, 2013 at a price of 101% until March 31, 2014 and at 100% thereafter.

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In March 2003, the Brazos River Authority Series 1999B and 1999C pollution control revenue bonds (aggregate principal amount of $66 million) were converted from a floating rate mode to a multiannual mode at an annual rate of 6.75% and a fixed rate of 7.70%, respectively. The rate on the 1999B bonds will remain in effect until 2013 at which time they will be remarketed. The rate on the 1999C bonds is fixed to maturity in 2032, however they become callable in 2013.

In March 2003, the Brazos River Authority issued $44 million aggregate principal amount of pollution control revenue bonds Series 2003A for Energy. The bonds will bear interest at an annual rate of 6.75% until the mandatory tender date of April 1, 2013. On April 1, 2013, the bonds will be remarketed. Proceeds from the issuance of the bonds were used to repay the $44 million principal amount of Brazos River Authority Series 1993 pollution control revenue bonds due June 1, 2023.

The pollution control series variable rate debt of Energy requires periodic remarketing. Because Energy intends to remarket these obligations, and has the ability and intent to refinance if necessary, they have been classified as long-term debt.

Debt Issuances and Retirements in 2002:

In 2002, Energy and its consolidated subsidiaries issued $750 million of 9% Exchangeable Subordinated Notes, which were exchanged for preferred membership interests (see Note 9). In 2002, Energy redeemed at par the remaining $635 million principal amount of its floating rate debentures and TXU Mining redeemed $123 million of its senior notes.

Maturities — Maturity requirements for the years 2004 through 2008 under long-term debt outstanding at December 31, 2003, were as follows:

Year
2004	$	—
2005		30
2006		—
2007		—
2008		251
Thereafter		2,781
Capital lease		13
Unamortized discount		10
	$	3,085

9. MEMBERSHIP INTERESTS

In November 2003, Energy approved a cash distribution of $175 million to be paid to US Holdings in January 2004. Energy paid total cash distributions of $750 million to US Holdings in 2003 ($175 million in October and July, and $200 million in April and January 2003) and $777 million in 2002.

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 preferred membership interests may be exchanged at the option of the holders, subject to certain restrictions, at any time for up to approximately 57 million shares of TXU Corp. common stock at an exchange price of $13.1242 per share. The number of shares of TXU Corp. common stock that may be issuable upon the exercise of the exchange right is determined by dividing the aggregate liquidation value of preferred membership interests to be exchanged by the exchange price. The exchange price and the number of shares to be issued are subject to anti-dilution adjustments. At issuance of the notes that were exchanged for the preferred membership interests, Energy recognized a 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, recorded as a credit to capital. 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 interests is 11.5%. At the time of any exchange of the preferred membership interests for common stock, the unamortized discount will be proportionately written off as a charge to earnings. If all the membership interests had been exchanged into common stock on December 31, 2003, the pre-tax charge would have been $253 million. These securities are classified as liabilities in accordance with SFAS 150. See Note 1 under Changes in Accounting Standards.

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The original purchasers of the notes that were exchanged for the preferred membership interests were granted the right to nominate one member to the board of directors of TXU Corp., and such nominee has been elected to fill a vacancy. The original purchasers forfeit this right if they cease to hold at least 30% of their original investment in the form of common stock and/or preferred membership interests. In any event, this right expires on the later of (i) November 2012 or, (ii) the date no membership interests remain outstanding. The holders of the preferred membership interests are restricted from actions that would increase their control of TXU Corp.

In connection with the transfer of certain businesses to Energy, as part of the business restructuring described in Note 1, $468 million of goodwill arising from TXU Corp.’s 1997 acquisition of ENSERCH Corporation was allocated to these businesses in 2002 and is reflected in the balance sheet of Energy. The offsetting credit is reflected in capital. In addition, $15 million of advances from affiliates were converted to capital during 2002.

10. INCOME TAXES

The components of income tax expense are as follows:

	Year Ended December 31,
	2003			2002			2001
Current:
US Federal	$	211		$	229		$	424
State		9			3			39
Non-US		—			1			(5	)
Total		220			233			458
Deferred:
US Federal		27			(100	)		(195	)
State		—			4			(3	)
Non-US		1			—			(1	)
Total		28			(96	)		(199	)
Investment tax credits		(17	)		(20	)		(17	)
Total	$	231		$	117		$	242

Reconciliation of income taxes computed at the US federal statutory rate to provision for income taxes:

	Year Ended December 31,
	2003			2002			2001
Income from continuing operations before income taxes, extraordinary loss and cumulative effect of changes in accounting principles	$	728		$	439		$	833
Income taxes (benefit) at the federal statutory rate of 35%	$	255		$	154		$	292
Depletion allowance		(25	)		(25	)		(25	)
Amortization of investment tax credits		(16	)		(20	)		(17	)
Preferred securities cost		6			—			—
Redirected depreciation		—			—			(18	)
State income taxes, net of federal tax benefit		6			5			24
Other		5			3			(14	)
Provision for income taxes	$	231		$	117		$	242
Effective tax rate		32	%		27	%		30	%

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The components of Energy’s deferred tax assets and liabilities are as follows:

	December 31,
	2003							2002
	Total		Current			Noncurrent		Total		Current			Noncurrent
Deferred Tax Assets
Unamortized investment tax credits	$	126	$	—		$	126	$	132	$	—		$	132
Bad debt reserve		20		20			—		30		30			—
Impairment of assets		168		—			168		181		—			181
Nuclear decommissioning asset retirement obligation		150		—			150		—		—			—
Retail clawback liability		61		—			61		65		—			65
Alternative minimum tax		335		—			335		307		—			307
Employee benefits		113		—			113		109		—			109
Deferred benefit of state income taxes		14		13			1		11		10			1
Other		183		52			131		196		28			168
Total deferred tax assets		1,170		85			1,085		1,031		68			963
Deferred Tax Liabilities
Depreciation differences and capitalized construction costs		2,930		—			2,930		2,756		—			2,756
Software development costs		82		—			82		90		—			90
Deferred state income tax		2		—			2		2		—			2
Other		40		3			37		46		—			46
Total deferred tax liability		3,054		3			3,051		2,894		—			2,894
Net Deferred Tax Liability (Asset )	$	1,884	$	(82	)	$	1,966	$	1,863	$	(68	)	$	1,931

At December 31, 2003, Energy had approximately $335 million of alternative minimum tax credit carryforwards available to offset future tax payments. These tax credit carryforwards do not have expiration dates.

Energy’s income tax returns are subject to examination by applicable tax authorities. The IRS is currently examining the returns of TXU Corp. and its subsidiaries for the tax years ended 1993 through 2002. In management’s opinion, an adequate provision has been made for any future taxes that may be owed as a result of any examinations.

11. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS

Energy is a participating employer in the TXU Retirement Plan (Retirement Plan), a defined benefit pension plan sponsored by TXU Corp. The Retirement Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code) and is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). Employees are eligible to participate in the Retirement Plan upon their completion of one year of service and the attainment of age 21. All benefits are funded by the participating employers. The Retirement Plan provides benefits to participants under one of two formulas: (i) a cash balance formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits, or (ii) a traditional defined benefit formula based on years of service and the average earnings of the three years of highest earnings.

All eligible employees hired after January 1, 2002, will participate under the cash balance formula. Certain employees who, prior to January 1, 2002, participated under the traditional defined benefit formula, continue their participation under that formula. Under the cash balance formula, future increases in earnings will not apply to prior service costs. It is TXU Corp.’s policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations. Such contributions, when made, are intended to provide not only for benefits attributed to service to date, but also those expected to be earned in the future.

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The allocated net periodic pension cost (benefit) applicable to Energy was $17 million for 2003, $3 million for 2002 and ($5) million for 2001. Contributions were $13 million, $9 million and $1 million in 2003, 2002 and 2001, respectively.

In addition to the Retirement Plan and the Thrift Plan, Energy participates with TXU Corp. and certain other affiliated subsidiaries of TXU Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service. The estimated net periodic postretirement benefits cost other than pensions applicable to Energy was $38 million for 2003, $26 million for 2002 and $25 million for 2001. Contributions paid by Energy to fund postretirement benefits other than pensions were $16 million, $11 million and $19 million in 2003, 2002 and 2001, respectively.

In addition, Energy employees are eligible to participate in a qualified savings plan, the TXU Thrift Plan (Thrift Plan). This plan is a participant-directed defined contribution profit sharing plan qualified under Section 401(a) of the Code, and is subject to the provisions of ERISA. The Thrift Plan includes an employee stock ownership component. Under the terms of the Thrift Plan, as amended effective in January 1, 2002, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the maximum amount of their regular salary or wages permitted under law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the cash balance formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the traditional defined benefit formula of the Retirement Plan. Employer matching contributions are invested in TXU Corp. common stock. Energy’s contributions to the Thrift Plan, aggregated $13 million in 2003, $14 million in 2002, and $7 million in 2001.

12. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of Energy’s significant financial instruments were as follows:

	December 31, 2003				December 31, 2002
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
On balance sheet liabilities:
Long-term debt (including current maturities)(a)	$	3,072	$	3,273	$	1,955	$	1,912
Exchangeable preferred membership interests, net of discount(b)		497		1,580		486		1,076
Financial guarantees		2		1		—		—
Off balance sheet liabilities:
Financial guarantees		—		12		—		81

(a) Excludes capital leases.

(b) Exchanged for preferred membership interest in 2003. Amount presented net of discount.

In accordance with SFAS 133, financial instruments that are derivatives are recorded on the balance sheet at fair value.

The fair values of on balance sheet instruments are estimated at the lesser of either the call price or the market value as determined by quoted market prices, where available, or, where not available, at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risk.

The fair values of each financial guarantee is based on the difference between the credit spread of the entity responsible for the underlying obligation and a financial counterparty applied, on a net present value basis, to the notional amount of the guarantee.

The carrying amounts for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments. The fair values of other financial instruments for which carrying amounts and fair values have not been presented are not materially different than their related carrying amounts.

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13. DERIVATIVE FINANCIAL INSTRUMENTS

For derivative instruments designated as cash flow hedges, Energy recognized a net unrealized ineffectiveness gain of $6 million ($4 million after-tax) in 2003 and a net loss of $41 million ($27 million after-tax) in 2002. The ineffectiveness gains and losses in 2003 and 2002 related to commodity hedges and were reported as a component of revenues. In 2001, Energy experienced net hedge ineffectiveness of $4 million ($3 million after-tax), recorded as an increase in revenues.

The net effect of unrealized mark-to-market ineffectiveness 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 $36 million in net gains in 2003 and $41 million in net losses in 2002.

The maximum length of time Energy hedges its exposure to the variability of future cash flows for forecasted energy-related transactions is approximately four years.

Cash flow hedge amounts reported in accumulated other comprehensive income will be recognized in earnings as the related forecasted transactions are settled or are deemed to be no longer probable of occurring. No amounts were reclassified into earnings in 2003, 2002, or 2001 as a result of the discontinuance of cash flow hedges because of the probability a hedged forecasted transaction would not occur.

As of December 31, 2003, Energy expects that $42 million ($27 million after-tax) in accumulated other comprehensive loss will be recognized in earnings over the next twelve months. This amount represents the projected value of the hedges over the next twelve months relative to what would be recorded if the hedge transactions had not been entered into. The amount expected to be reclassified is not a forecasted loss incremental to normal operations, but rather it demonstrates the extent to which volatility in earnings (which would otherwise exist) is mitigated through the use of cash flow hedges. The following table summarizes balances currently recognized in accumulated other comprehensive gain/(loss):

	Accumulated Other Comprehensive Loss Year Ended December 31, 2003
	Energy-related		All other		Total
Dedesignated hedges (amounts fixed)	$	56	$	29	$	85
Hedges subject to market price fluctuations		—		11		11
Total	$	56	$	40	$	96

14. TEXAS ELECTRIC INDUSTRY RESTRUCTURING

As a result of the 1999 Restructuring Legislation, on January 1, 2002, US Holdings and certain other electric utilities in Texas disaggregated (unbundled) their business activities into a power generation company, a retail electric provider (REP) and a transmission and distribution (electricity delivery) utility. Unbundled electricity delivery utilities within ERCOT, such as Electric Delivery, remain regulated by the Commission.

Effective January 1, 2002, REPs affiliated with electricity delivery utilities are required to charge “price-to-beat” rates established by the Commission to residential and small business customers located in their historical service territories. Energy, as a REP affiliated with an electricity delivery utility, could not charge prices to customers in either of those classes in the historical service territory that are different from the price-to-beat rate, adjusted for fuel factor changes, until the earlier of January 1, 2005 or the date on which 40% of the electricity consumed by customers in a class is supplied by competing REPs. Thereafter, Energy may offer rates different from the price-to-beat rate to customers in that class, but it must also continue to make the price-to-beat rate available for residential and small business customers until January 1, 2007. Twice a year, Energy may request that the Commission adjust the fuel factor component of the price-to-beat rate up or down based on changes in the market price of natural gas. In March and August of 2003, the Commission approved price-to-beat rate increases requested by Energy.

In December 2003, the Commission found that Energy had met the 40% requirement to be allowed to offer alternatives to the price-to-beat rate for small business customers in the historical service territory.

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Also, effective January 1, 2002, power generation companies affiliated with electricity delivery utilities may charge unregulated prices in connection with ERCOT wholesale power transactions.

Regulatory Settlement Plan

On December 31, 2001, US Holdings filed a Settlement Plan with the Commission. It resolved all major pending issues related to US Holdings’ transition to competition pursuant to the 1999 Restructuring Legislation. The Settlement Plan does not remove regulatory oversight of Electric Delivery’s business nor does it eliminate Energy’s price-to-beat rates and related fuel adjustments. The Settlement Plan became final and non-appealable in January 2003.

The major elements of the Settlement Plan are:

Excess Mitigation Credit — Over the two-year period ended December 31, 2003, Electric Delivery implemented a stranded cost excess mitigation credit in the amount of $389 million (originally estimated to be $350 million), plus $26 million in interest, applied as a reduction to delivery fees charged to all REPs, including Energy. The credit was funded by Energy in the form of a note payable to Electric Delivery.

Regulatory Asset Securitization — US Holdings received a financing order authorizing the issuance of securitization bonds in the aggregate principal amount of $1.3 billion to recover regulatory asset stranded costs and other qualified costs. Accordingly, TXU Electric Delivery Transition Bond Company LLC, a bankruptcy remote financing subsidiary of Electric Delivery, issued an initial $500 million of securitization bonds in 2003 and is expected to issue $790 million in the first half of 2004. The principal and interest payments of the bonds are secured through a delivery fee surcharge (transition charge) to all REPs, including Energy.

Retail Clawback Credit — The Settlement Plan provides that a retail clawback credit will be implemented unless 40% of the electricity consumed by residential and small business customers in the historical service territory is supplied by competing REPs after the first two years of competition. This threshold was reached for small business customers, as discussed above, but not for residential customers. The amount of the credit is equal to the number of residential customers retained by Energy in the historical service territory as of January 1, 2004, less the number of new customers Energy has added outside of the historical service territory as of January 1, 2004, multiplied by $90. The credit, which will be funded by Energy, will be applied to delivery fees charged by Electric Delivery to REPs, including Energy, over a two-year period beginning January 1, 2004. In 2002, Energy recorded a charge to cost of energy sold of $185 million ($120 million after-tax) to accrue an estimated retail clawback liability. In 2003, Energy reduced the liability to $173 million, with a credit to earnings of $12 million ($8 million after-tax) to reflect the calculation of the estimated liability applicable only to residential customers in accordance with the Settlement Plan. As the amount of the credit will be based on numbers of customers over the related two-year period, the liability is subject to future adjustments.

Stranded Costs and Fuel Cost Recovery— Energy’s stranded costs, not including regulatory assets, are fixed at zero. US Holdings will not seek to recover its unrecovered fuel costs which existed at December 31, 2001. Also, it will not conduct a final fuel cost reconciliation, which would have covered the period from July 1998 until the beginning of competition in January 2002.

See Note 4 for a discussion of extraordinary charges recorded in 2001 in connection with the Settlement Plan.

15. COMMITMENTS AND CONTINGENCIES

Request from CFTC — In October 2003, TXU Corp. received an informal request for information from the US Commodity Futures Trading Commission (CFTC) seeking voluntary production of information concerning disclosure of price and volume information furnished by TXU Portfolio Management Company LP to energy industry publications. The request seeks information for the period from January 1, 1999 to the present. TXU Corp. intends to cooperate with the CFTC, and the Company is preparing to respond to such information request. While TXU Corp. is just beginning to compile the data requested, TXU Corp. believes that TXU Portfolio Management Company LP has properly reported such information to industry publications.

Clean Air Act — The Federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on SO₂ and NO_x emissions produced by electricity generation plants. Energy’s capital requirements have not been significantly affected by the requirements of the Clean Air Act. In addition,

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all permits required for the air pollution control provisions of the 1999 Restructuring Legislation have been applied for and Energy has initiated a construction program to install control equipment to achieve the required reductions.

Power Purchase Contracts — Certain contracts to purchase electricity provide for capacity payments to ensure availability and provide for adjustments based on the actual power taken under the contracts. Capacity payments paid under these contracts for the years ended December 31, 2003, 2002 and 2001 were $230 million, $296 million and $189 million, respectively.

Expected future capacity payments under existing agreements are estimated as follows:

2004	$	238
2005		162
2006		117
2007		18
2008		—
Thereafter		—
Total capacity payments	$	535

At December 31, 2003, Energy had commitments for pipeline transportation and storage reservation fees as shown in the table below:

2004	$	24
2005		7
2006		6
2007		4
2008		1
Thereafter		6
Total pipeline transportation and storage reservation fees	$	48

On the basis of Energy’s current expectations of demand from its electricity customers as compared with its capacity payments, management does not consider it likely that any material payments will become due for electricity not taken beyond capacity payments.

Coal Contracts — Energy has coal purchase agreements and coal transportation agreements. Commitments under these contracts for the next five years and thereafter are as follows:

2004	$	78
2005		23
2006		18
2007		—
2008		—
Thereafter		—
Total	$	119

Leases — Energy has entered into operating leases covering various facilities and properties including generation plant facilities, combustion turbines, transportation equipment, mining equipment, data processing equipment and office space. Certain of these leases contain renewal and purchase options and residual value guarantees. Lease costs charged to operating expense totaled $124 million, $134 million and $117 million for 2003, 2002 and 2001, respectively.

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As of December 31, 2003, future minimum lease payments under both capital leases and operating leases (with initial or remaining noncancellable lease terms in excess of one year) were as follows:

Year	Capital Leases		Operating Leases
2004	$	2	$	66
2005		2		70
2006		3		66
2007		3		70
2008		2		69
Thereafter		5		456
Total future minimum lease payments		17	$	797
Less amounts representing interest		2
Present value of future minimum lease payments		15
Less current portion		2
Long-term capital lease obligation	$	13

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 that obligate it to guarantee the residual values of the leased facilities. At December 31, 2003, the aggregate maximum amount of residual values guaranteed was approximately $208 million with an estimated residual recovery of approximately $140 million. The average life of the lease portfolio is approximately six years.

Debt obligations of the parent— Energy has provided a guarantee of the obligations under TXU Corp.’s finance lease (approximately $130 million at December 31, 2003) for its headquarters building.

Shared saving guarantees — As part of the operations of the strategic retail services business, which Energy intends to sell, 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 $8 million and the maximum total potential payout is approximately $56 million. The fair value of guarantees issued during the year ended December 31, 2003 was $1.8 million with a maximum potential payout of $42 million. The average remaining life of the portfolio is approximately nine years. These guarantees will be transferred or eliminated as part of expected transactions for the sale of strategic retail services operations.

Letters of credit — Energy has entered into various agreements that require letters of credit for financial assurance purposes. Approximately $403 million of letters of credit were outstanding at December 31, 2003 to support existing floating rate pollution control revenue bond debt of approximately $395 million. The letters of credit are available to fund the payment of such debt obligations. These letters of credit have expiration dates in 2008.

Energy has outstanding letters of credit in the amount of $37 million to support hedging and risk management margin requirements in the normal course of business. As of December 31, 2003, approximately 82% 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 $32 million to support performance under various contracts and legal obligations contracts in the normal course of business. The term of the surety bond obligations is approximately one year.

Nuclear Insurance — With regard to liability coverage, the Price-Anderson Act (Act) provides financial protection for the public in the event of a significant nuclear power plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $10.6 billion currently and requires nuclear power plant operators to provide financial protection for this amount. The Act is being considered by the United States Congress for modification and extension. The terms of a modification, if any, are not presently known and therefore TXU Corp. is unable, at this time, to determine any impact it may have on nuclear liability coverage. As

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required, TXU Corp. provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As the first layer of financial protection, TXU Corp. has $300 million of liability insurance from American Nuclear Insurers (ANI), which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).

Under the SFP, each operating licensed reactor in the US is subject to an assessment of up to $100.6 million, subject to increases for inflation every five years, in the event of a nuclear incident at any nuclear plant in the US. Assessments are limited to $10 million per operating licensed reactor per year per incident. All assessments under the SFP are subject to a 3% insurance premium tax, which is not included in the above amounts.

With respect to nuclear decontamination and property damage insurance, NRC regulations require that nuclear plant license-holders maintain not less than $1.1 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. TXU Corp. maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $3.4 billion, above which TXU Corp. is self-insured. The primary layer of coverage of $500 million is provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company. The remaining coverage includes premature decommissioning coverage and is provided by NEIL in the amount of $2.25 billion and $610 million from other insurance markets and foreign nuclear insurance pools. TXU Corp. is subject to a maximum annual assessment from NEIL of $26.7 million.

TXU Corp. maintains Extra Expense Insurance through NEIL to cover the additional costs of obtaining replacement power from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week period. The total maximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident. Under this coverage, TXU Corp. is subject to a maximum annual assessment of $8.6 million.

There have been some revisions made to the nuclear property and nuclear liability insurance policies regarding the maximum recoveries available for multiple terrorism occurrences. Under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.24 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply. Under the ANI liability policy, the liability arising out of terrorist acts will be subject to one industry aggregate limit of $300 million which could be reinstated at ANI’s option depending on prevailing risk circumstances and the balance in the Industry Credit Rating Plan reserve fund. Under the US Terrorism Risk Insurance Act of 2002, the US government provides reinsurance with respect to acts of terrorism in the US for losses caused by an individual or individuals acting on behalf of foreign parties. In such circumstances, the NEIL and ANI terrorism aggregates would not apply.

Nuclear Decommissioning — Through December 31, 2001, decommissioning costs were recovered from consumers based upon a 1992 site-specific study through rates placed in effect under Energy’s January 1993 rate increase request. Effective January 1, 2002, decommissioning costs are recovered through a tariff charged to REPs by Electric Delivery based upon a 1997 site-specific study, adjusted for trust fund assets, as a component of delivery fees effective under US Holdings’ 2001 Unbundled Cost of Service filing. Amounts recovered through regulated rates are deposited in external trust funds (see Note 5 under Investments). With the adoption of FAS 143, the liability for the decommissioning costs was recorded at discounted net present value.

See Note 1 (under Changes in Accounting Standards) for a discussion of the impact of SFAS 143 on accounting for nuclear decommissioning costs.

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Also see Note 1 (under Property, Plant and Equipment) for a discussion of an extension of the nuclear plant license.

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 on February 3, 2004 that joined additional, unaffiliated defendants. Three retail electric providers have 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 have filed a motion to intervene in the action alleging claims substantially identical to TCE’s, both on their behalf and on behalf of a putative class of all former customers of TCE. Energy believes that it has not committed any violation of the antitrust laws and 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. Energy is unable to estimate any possible loss or predict the outcome of this action.

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. 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. TXU Corp. 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, TXU Corp. does not believe that there is any merit to the plaintiff’s claims under Sarbanes-Oxley. Accordingly, TXU Corp., Energy and TXU Portfolio Management intend to vigorously defend the litigation. While TXU Corp., Energy and TXU Portfolio Management dispute the plaintiff’s claims, TXU Corp. is unable to predict the outcome of this litigation or the possible loss in the event of an adverse judgment.

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 has been transferred to the Beaumont Division of the Eastern District of Texas. 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. On September 15, 2003, defendants filed a motion to dismiss the lawsuit and a motion to transfer the case to the Northern District of Texas, Dallas Division. TXU Corp. 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 the plaintiff. Therefore, TXU Corp. believes that plaintiff’s claims are without merit and plans to vigorously defend the lawsuit. TXU Corp. is 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 Energy, should not have a material effect upon its financial position, results of operations or cash flows.

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16. SUPPLEMENTARY FINANCIAL INFORMATION

The operations of Energy are unregulated, as the Texas market is now open to competition. However, retail pricing to residential customers in the historical service territory continues to be subject to certain price controls as discussed in Note 14.

Other Income and Deductions —

	Year Ended December 31,
	2003		2002		2001
Other income
Net gain on sale of properties and businesses	$	45	$	30	$	1
Other		3		3		1
Total other income	$	48	$	33	$	2
Other deductions
Loss on sale of properties	$	—	$	2	$	8
Loss on retirement of debt		3		—		149
Regulatory asset write-off		—		—		22
Asset impairment		2		237		—
Other		17		15		17
Total other deductions	$	22	$	254	$	196

Credit Risk — Credit risk relates to the risk of loss associated with non-performance by counterparties. Energy maintains credit risk policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of a potential counterparty’s financial condition, credit rating, and other quantitative and qualitative credit criteria and specify authorized risk mitigation tools, including but not limited to use of standardized agreements that allow for netting of positive and negative exposures associated with a single counterparty. Energy has standardized documented processes for monitoring and managing its credit exposure, including methodologies to analyze counterparties’ financial strength, measurement of current and potential future credit exposures and standardized contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to preset limits and stress tested to assess potential credit exposure. This evaluation results in establishing credit limits or collateral requirements prior to entering into an agreement with a counterparty that creates credit exposure to Energy. Additionally, Energy has established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Any prospective material adverse change in the payment history or financial condition of a counterparty or downgrade of its credit quality will result in the reassessment of the credit limit with that counterparty. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.

Credit Exposure — Energy’s gross exposure to credit risk as of December 31, 2003 was $2.1 billion, representing trade accounts receivable (net of allowance of uncollectible accounts receivable of $51 million), as well as commodity contract assets and other derivative assets that arise primarily from hedging activities.

A large share of gross assets subject to credit risk represents accounts receivable from the retail sale of electricity to residential and small business customers. The risk of material loss (after consideration of allowances) from non-performance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from non-payment by these customers based on historical experience and market or operational conditions.

Most of the remaining trade accounts receivable are with large business customers and hedging counterparties. These counterparties include major energy companies, financial institutions, gas and electric utilities, independent power producers, oil and gas producers and energy trading companies.

The exposure to credit risk from these customers and counterparties, excluding credit collateral, as of December 31, 2003, is $1.1 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 $965 million. Of this amount, approximately 86% of the associated exposure is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and Energy’s internal credit evaluation process. Those customers and counterparties

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without an S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate an S&P equivalent rating. Energy routinely monitors and manages its credit exposure to these customers and counterparties on this basis.

Energy had no exposure to any one customer or counterparty greater than 10% of the net exposure of $965 million at December 31, 2003. Additionally, approximately 71% 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.

Interest Expense and Related Charges —

	Year Ended December 31,
	2003			2002			2001
Interest	$	306		$	213		$	229
Amortization of debt expense		24			8			7
Capitalized interest		(7	)		(6	)		(12	)
Total interest expense and related charges	$	323		$	215		$	224

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

• Energy incurs electricity delivery fees charged by Electric Delivery. For the years ended December 31, 2003 and 2002, these fees totaled $1.5 billion in each year.

• In accordance with the Business Separation Agreement, Energy records interest expense payable to Electric Delivery with respect to Electric Delivery’s generation-related regulatory assets that are subject to securitization. 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 years ended December 31, 2003 and 2002, this interest expense totaled $43 million and $28 million, respectively.

• Under the terms of the settlement plan, Electric Delivery issued an initial $500 million of securitization bonds in 2003 and is expected to issue $790 million in the first half of 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 ($13 million of which is due currently) that will be extinguished as Electric Delivery pays the related income taxes.

• Energy had a note payable to Electric Delivery, in the original amount of $350 million, related to the excess mitigation credit established in accordance with the Settlement Plan. Electric Delivery implemented the credit as a reduction to delivery fees charged to all REPs, including Energy, for a two-year period beginning January 1, 2002. For the years ended December 31, 2003 and 2002, the principal payments made on the note payable totaled $170 million and $180 million, respectively, and the interest expense totaled $6 million and $21 million, respectively.

• Average daily short-term advances from affiliates during 2003 and 2002 were $343 million and $417 million, respectively, and interest expense incurred on the advances was $8 million and $10 million, respectively. These amounts include the average short-term advances from affiliates during 2003 and 2002 and the interest incurred on the advances for the discontinued strategic retail services and Pedricktown, New Jersey (power production) businesses. The weighted average interest rate for 2003 and 2002 was 2.8% and 2.7%, respectively.

• TXU Business Services Company, a subsidiary of TXU Corp., charges Energy for financial, accounting, information technology, environmental, procurement and personnel services and other administrative services at cost. For 2003 and 2002, these costs totaled $223 million and $286 million, respectively, and are included in selling, general and administrative expenses.

• Energy receives payments from TXU Gas, a subsidiary of TXU Corp., under a service agreement that began in 2002 covering customer billing and customer support services provided for TXU Gas. These revenues totaled $29 million and $28 million in 2003 and 2002, respectively and are included in other revenues.

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Accounts Receivable — At December 31, 2003 and 2002, accounts receivable of $943 million and $1.3 billion, respectively, are stated net of uncollectible accounts of $51 million and $71 million, respectively. During 2003, bad debt expense was $114 million, account writeoffs were $121 million and other activity decreased the allowance for uncollectible accounts by $13 million. During 2002, bad debt expense was $155 million, account write-offs were $101 million and other activity decreased the allowance for uncollectible accounts by $6 million. Allowances related to receivables sold are reported in current liabilities and totaled $39 million and $19 million at December 31, 2003 and 2002, respectively. See Note 7 regarding sale of receivables.

Accounts receivable included $388 million and $489 million of unbilled revenues at December 31, 2003 and 2002, respectively.

Commodity Contract Assets At December 31, 2003 and 2002, current and noncurrent commodity contract assets totaling $1.1 billion and $1.8 billion, respectively, are stated net of applicable credit (collection) and performance reserves totaling $18 million and $43 million, respectively. Performance reserves are provided for direct, incremental costs to settle the contracts.

Inventories by Major Category —

	December 31,
	2003		2002
Materials and supplies	$	225	$	223
Fuel stock		78		71
Gas stored underground		83		57
Total inventories	$	386	$	351

Inventories reflect a $22 million reduction in 2003 as a result of the rescission of EITF 98-10 as discussed in Note 2.

Property, Plant and Equipment —

	December 31,
	2003		2002
Electricity generation	$	15,861	$	15,635
Other		739		460
Total		16,600		16,095
Less accumulated depreciation		6,642		6,177
Net of accumulated depreciation		9,958		9,918
Construction work in progress		256		286
Nuclear fuel (net of accumulated amortization: 2003 — $934; 2002 — $847)		131		137
Net property, plant and equipment	$	10,345	$	10,341

Supplemental Cash Flow Information —

	Year Ended December 31,
	2003		2002			2001
Cash payments:
Interest (net of amounts capitalized)	$	262	$	204		$	240
Income taxes	$	93	$	157		$	366
Non-cash investing and financing activities:
Non-cash advances	$	—	$	—		$	89
Conversion of capital (from) to advances	$	—	$	(15	)	$	28
Non-cash capital contribution related to issuance of exchangeable subordinated notes	$	—	$	266		$	—

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Quarterly Information (unaudited) — The results of operations by quarter are summarized below and reflect the discontinuance of the strategic retail service business operations.

In the opinion of Energy, all other adjustments (consisting of normal recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of expectations for a full year’s operations because of seasonal and other factors.

	Quarter Ended
	March 31			June 30			Sept. 30			Dec. 31
2003:
Operating revenues	$	1,790		$	2,016		$	2,437		$	1,743
Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles	$	36		$	154		$	250		$	58
Loss from discontinued operations, net of tax effect	$	(1	)	$	—		$	(1	)	$	(16	)
Cumulative effect of changes in accounting principles, net of tax effect	$	(58	)	$	—		$	—		$	—
Net income (loss)	$	(23	)	$	154		$	249		$	41
2002:
Operating revenues	$	1,790		$	2,003		$	2,403		$	1,482
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles	$	190		$	200		$	241		$	(309	)
Loss from discontinued operations, net of tax effect	$	(3	)	$	(16	)	$	(14	)	$	(18	)
Net income (loss)	$	187		$	183		$	227		$	(327	)

Included in fourth quarter 2003 income from discontinued operations were impairment and other exit charges totaling $10.3 million ($6.7 million after-tax). Included in fourth quarter 2002 results of continuing operations were $185 million ($120 million after-tax) accrual for regulatory-related retail clawback and a $237 million ($154 million after-tax) writedown of an investment in generation plant construction projects.

Reconciliation of Previously Reported Quarterly Information – The following table presents the changes to previously reported quarterly amounts (as reported in the 2003 Annual Report on Form 10-K) to reflect discontinued operations (see Note 3). Net income was not affected by these changes.

	Quarter Ended
	March 31			June 30			Sept. 30			Dec. 31
	Increase (Decrease) From Previously Reported
2003:
Operating revenues	$	(1	)	$	(1	)	$	(5	)	$	(2	)
Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		2			—			1			2
Loss from discontinued operations, net of tax effect		(2	)		—			(1	)		(1	)
2002:
Operating revenues	$	—		$	(4	)	$	(8	)	$	(1	)
Income from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		—			2			(1	)		2
Loss from discontinued operations, net of tax effect		—			(1	)		1			(2	)

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17. SUBSEQUENT EVENT

In the second quarter of 2004, Energy finalized plans to dispose of the Pedricktown, New Jersey (power production) business. Negotiations for the sale of the Pedricktown facility are ongoing and a transaction is expected to be completed no later than the second quarter of 2005. The financial statements have been reclassified to reflect this business as a discontinued operation. Except as required to reflect the effects of the reclassification discussed above, the financial statements have not been otherwise modified or updated.

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