Texas Competitive Electric 10-Q Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

( √ ) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006

— OR —

( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

_____________________

Commission File Number 333-108876

TXU Energy Company LLC

(Exact Name of Registrant as Specified in its Charter)

A Delaware Limited Liability Company	75-2967817
(State of Organization)	(I.R.S. Employer Identification No.)
1601 Bryan Street, Dallas, TX 75201-3411	(214) 812-4600
(Address of Principal Executive Offices)(Zip Code)	Registrant’s Telephone Number)

_____________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes√ No____

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ____ Accelerated filer ____ Non-Accelerated filer √

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes___ No√

As of November 9, 2006, all outstanding common membership interests in TXU Energy Company LLC were held by TXU US Holdings Company.

TXU Energy Company LLC meets the conditions set forth in General Instructions (H) (1) (a) and (b) of Form 10-Q and is therefore filing this report with the reduced disclosure format.

TABLE OF CONTENTS
	Page
Glossary	ii
Part I.Financial Information
Item 1.Financial Statements Condensed Statements of Consolidated Income - Three and Nine Months Ended September 30, 2006 and 2005	1
Condensed Statements of Consolidated Comprehensive Income - Three and Nine Months Ended September 30, 2006 and 2005	2
Condensed Statements of Consolidated Cash Flows - Nine Months Ended September 30, 2006 and 2005	3
Condensed Consolidated Balance Sheets - September 30, 2006 and December 31, 2005	4
Notes to Condensed Consolidated Financial Statements	5
Report of Independent Registered Public Accounting Firm	23
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.Controls and Procedures	51
Part II.Other Information
Item 1. Legal Proceedings	52
Item 1A.Risk Factors	52
Item 6.Exhibits	53
Signature	54

TXU Energy Company LLC files periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K which are generally made available to the public, free of charge, on the TXU Corp. website at http://www.txucorp.com, shortly after they have been filed with the Securities and Exchange Commission. To the extent any of those reports are not posted on the TXU Corp. website, TXU Energy Company LLC will provide copies of such reports upon request. The information on TXU Corp.’s website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-Q.

i

GLOSSARY

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

1999 Restructuring Legislation	legislation that restructured the electric utility industry in Texas to provide for retail competition
2005 Form 10-K	TXU Energy Company’s Annual Report on Form 10-K for the year ended December 31, 2005
Capgemini	Capgemini Energy LP, a subsidiary of Cap Gemini North America Inc. that provides business support services to TXU Energy Company and TXU Electric Delivery
Commission	Public Utility Commission of Texas
EITF	Emerging Issues Task Force
EITF 02-3	EITF Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”
EPA	US 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
FASB	Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting
FERC	US Federal Energy Regulatory Commission
FIN	Financial Accounting Standards Board Interpretation
FIN 45	FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - An Interpretation FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34”
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes”
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
FSP AUG AIR-1	FASB Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities”
GW	gigawatts
GWh	gigawatt-hours
historical service territory	the territory, largely in north Texas, being served by TXU Corp.’s regulated electric utility subsidiary at the time of entering retail competition on January 1, 2002
IRS	US Internal Revenue Service
kWh	kilowatt-hours

ii

market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. The market heat rate is based on the price offer of the marginal supplier (generally gas plants) in generating electricity and is calculated by dividing the wholesale market price of power by the market price of natural gas.
MMBtu	million British thermal units
Moody’s	Moody’s Investors Services, Inc. (a credit rating agency)
MW	megawatts
MWh	megawatt-hours
NRC	US Nuclear Regulatory Commission
price-to-beat rate	residential and small business customer electricity rates established by the Commission that (i) were required to be charged in a REP’s historical service territories until the earlier of January 1, 2005 or the date when 40% of the electricity consumed by such customer classes is supplied by competing REPs, adjusted periodically for changes in fuel costs, and (ii) are required to be made available to those customers until January 1, 2007
PURA	Texas Public Utility Regulatory Act
reference plant	eight new power generation units to be built by subsidiaries of TXU Corp. with a proprietary standardized “reference” plant design and construction planning process
REP	retail electric provider
S&P	Standard & Poor’s Ratings Services, a division of the McGraw Hill Inc. Companies (a credit rating agency)
SEC	US 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 34	SFAS No. 34, “Capitalization of Interest Cost”
SFAS 87	SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 88	SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and Termination Benefits”
SFAS 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 123R	SFAS No. 123R (revised 2004), "Share-Based Payment"
SFAS 132R	SFAS No. 132R (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement 125”

iii

SFAS 144	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 158	SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”
SG&A	selling, general and administrative
Short-cut method	refers to the short-cut method under SFAS 133 that allows entities to assume no hedge ineffectiveness in a hedging relationship of interest rate risk if certain conditions are met
TCEQ	Texas Commission on Environmental Quality
TXU Big Brown	TXU Big Brown Company LP, a Texas limited partnership and subsidiary of TXU Energy Company, which owns two lignite/coal-fired generation units in Texas
TXU Corp.	refers to TXU Corp., a holding company, and/or its consolidated subsidiaries, depending on context
TXU DevCo	Refers to TXU Generation Development Company LLC, a Delaware limited liability company and holding company subsidiary of TXU Corp., which has been established for the purpose of developing and constructing new lignite/coal-fired generation facilities in Texas. While an affiliate of TXU Energy Company, TXU DevCo is not a subsidiary of, or a parent company to, TXU Energy Company.
TXU Electric Delivery	refers to TXU Electric Delivery Company, a subsidiary of TXU Corp., and/or its consolidated bankruptcy-remote financing subsidiary, TXU Electric Delivery Transition Bond Company LLC, depending on context
TXU Energy Company	Refers to TXU Energy Company LLC, a subsidiary of US Holdings, and/or its consolidated subsidiaries, depending on context, engaged in electricity generation and wholesale and retail energy markets activities. This Form 10-Q and other SEC filings of TXU Energy Company occasionally make references to TXU Energy Company when describing actions, rights or obligations of its subsidiaries. These references reflect the fact that the subsidiaries are consolidated with TXU Energy Company for financial reporting purposes. However, these references should not be interpreted to imply that TXU Energy Company is actually undertaking the action or has the rights or obligations of its subsidiaries.
TXU Energy Retail	Refers to TXU Energy Retail Company LP, a subsidiary of TXU Energy Company engaged in the retail sale of power to residential and business customers.
TXU Portfolio Management	TXU Portfolio Management Company LP, a subsidiary of TXU Energy Company
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. and parent of TXU Energy Company

iv

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

TXU ENERGY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(millions of dollars)
Operating revenues	$	3,091		$	2,994		$	7,569		$	7,091
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,342			1,835			3,075			4,173
Operating costs		142			151			447			482
Depreciation and amortization		82			78			251			234
Selling, general and administrative expenses		137			139			383			367
Franchise and revenue-based taxes		31			27			84			77
Other income (Note 11)		(9	)		(19	)		(11	)		(28	)
Other deductions (Note 11)		4			6			198			19
Interest income		(61	)		(21	)		(137	)		(42	)
Interest expense and related charges (Note 13)		108			102			310			287
Total costs and expenses		1,776			2,298			4,600			5,569
Income from continuing operations before income taxes		1,315			696			2,969			1,522
Income tax expense		431			237			1,022			515
Income from continuing operations		884			459			1,947			1,007
Loss from discontinued operations, net of tax benefit (Note 3)		─			(2	)		─			(6	)
Net income	$	884		$	457		$	1,947		$	1,001

See Notes to Financial Statements.

1

TXU ENERGY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
	(millions of dollars)
Components related to continuing operations:
Income from continuing operations	$	884	$	459		$	1,947	$	1,007
Other comprehensive income:
Minimum pension liability adjustment (net of tax expense of $-, $-, $- and $4)		─		─			─		7
Cash flow hedges:
Net change in fair value of derivatives held at end of period (net of tax (expense) benefit of ($184), $38, ($205) and $31) (See Note 10)		342		(71	)		381		(58	)
Derivative value net losses reported in net income that relate to hedged transactions recognized in the period (net of tax benefit of $6, $10, $11 and $29)		11		17			21		52
Total effect of cash flow hedges		353		(54	)		402		(6	)
Comprehensive income from continuing operations		1,237		405			2,349		1,008
Comprehensive loss from discontinued operations		─		(2	)		─		(6	)
Comprehensive income	$	1,237	$	403		$	2,349	$	1,002

See Notes to Financial Statements.

2

TXU ENERGY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2006			2005
	(millions of dollars)
Cash flows - operating activities:
Income from continuing operations	$	1,947		$	1,007
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		302			279
Deferred income taxes and investment tax credits - net		(21	)		(56	)
Net effect of unrealized mark-to-market valuations		(287	)		87
Impairment of natural gas-fired generation plants		196			─
Bad debt expense		52			37
Net gain on sale of assets		(9	)		(13	)
Amortization of losses on dedesignated cash flow hedges		8			7
Net equity loss from unconsolidated affiliate		8			5
Stock-based incentive compensation expense		6			9
Credit related to impaired leases		(4	)		(12	)
Inventory write-off related to natural gas-fired generation plants		3			─
Change in retail clawback liability		─			(48	)
Charge related to coal contract counterparty claim		─			12
Changes in operating assets and liabilities		1,729			56
Cash provided by operating activities from continuing operations		3,930			1,370
Cash flows - financing activities:
Issuances of long-term debt		100			71
Retirements of debt		(605	)		(71	)
Change in short-term borrowings:
Commercial paper		54			─
Banks		(145	)		250
Decrease in income tax-related note payable to TXU Electric Delivery		(31	)		(40	)
Distributions paid to parent		(858	)		(525	)
Excess tax benefits on stock-based incentive compensation		13			7
Debt premium, discount, financing and reacquisition expenses		(13	)		(14	)
Cash used in financing activities from continuing operations		(1,485	)		(322	)
Cash flows - investing activities:
Advances to affiliates		(1,864	)		(661	)
Capital expenditures		(411	)		(189	)
Nuclear fuel		(77	)		(57	)
Proceeds from sale of assets		11			36
Proceeds from pollution control revenue bonds deposited with trustee		(99	)		─
Proceeds from sales of nuclear decommissioning trust fund securities		165			127
Investments in nuclear decommissioning trust fund securities		(177	)		(138	)
Other		2			2
Cash used in investing activities from continuing operations		(2,450	)		(880	)
Discontinued operations:
Cash used in operating activities		─			(3	)
Cash used in financing activities		─			─
Cash used in investing activities		─			─
Cash used in discontinued operations		─			(3	)
Net change in cash and cash equivalents		(5	)		165
Cash and cash equivalents - beginning balance		12			70
Cash and cash equivalents - ending balance	$	7		$	235

See Notes to Financial Statements.

3

TXU ENERGY COMPANY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,		December 31,
	2006		2005
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	7	$	12
Restricted cash		3		8
Trade accounts receivable — net		947		1,178
Advances to parent		1,858		694
Note receivable from parent		1,500		1,500
Income taxes receivable from parent		─		361
Inventories		314		309
Commodity contract assets		428		1,603
Cash flow hedge and other derivative assets		677		63
Margin deposits related to commodity positions		30		247
Other current assets		304		244
Total current assets		6,068		6,219
Restricted cash		101		─
Investments		519		501
Advances to parent		700		─
Property, plant and equipment — net		9,959		9,958
Goodwill		517		517
Commodity contract assets		168		338
Cash flow hedge and other derivative assets		117		68
Other noncurrent assets		190		205
Total assets	$	18,339	$	17,806
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Short-term borrowings	$	655	$	746
Long-term debt due currently		11		401
Trade accounts payable - nonaffiliates		683		879
Trade accounts and other payables to affiliates		378		355
Commodity contract liabilities		509		1,481
Cash flow hedge and other derivative liabilities		29		260
Margin deposits related to commodity positions		721		357
Accrued income taxes payable to parent		620		─
Accrued taxes other than income		71		51
Other current liabilities		311		415
Total current liabilities		3,988		4,945
Accumulated deferred income taxes		3,050		2,800
Investment tax credits		315		326
Commodity contract liabilities		158		516
Cash flow hedge and other derivative liabilities		39		44
Notes or other liabilities due affiliates		370		406
Other noncurrent liabilities and deferred credits		1,093		833
Long-term debt, less amounts due currently		2,941		3,055
Exchangeable preferred membership interests, net of discount ($─ and $222)		─		528
Total liabilities		11,954		13,453
Commitments and contingencies (Note 8)
Membership interests (Note 7):
Capital account		6,104		4,474
Accumulated other comprehensive income (loss)		281		(121	)
Total membership interests		6,385		4,353
Total liabilities and membership interests	$	18,339	$	17,806

See Notes to Financial Statements.

4

TXU ENERGY COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS

Description of Business — TXU Energy Company is a wholly-owned subsidiary of US Holdings, which is a wholly-owned subsidiary of TXU Corp. TXU Energy Company is a holding company whose subsidiaries are engaged in electricity generation, residential and business retail electricity sales as well as wholesale energy markets activities primarily in Texas. There are no reportable business segments within TXU Energy Company.

Basis of Presentation — The condensed consolidated financial statements of TXU Energy Company have been prepared in accordance with accounting principles generally accepted in the US and on the same basis as the audited financial statements included in its 2005 Form 10-K. All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. As discussed below, certain reclassifications have been made to conform prior period data to current period presentation. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in the 2005 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

As previously disclosed, a realignment of TXU Energy Company’s wholesale energy operations was completed effective January 1, 2006. Under the realignment, management of wholesale purchases and sales of power for purposes of balancing power supply and demand was segregated from the buying and selling of power for trading purposes. Previously, all wholesale power purchases and sales were managed in aggregate under a “portfolio management” structure, as the primary activity was energy balancing, and all wholesale activity utilized (and continues to utilize) contracts for physical delivery. Financial derivative instruments, as are common in natural gas markets, are not as readily available in the Texas power market. The realignment reflects an expectation of a growing market for power trading in Texas. Under the previous structure, all purchases and sales scheduled with ERCOT for delivery were reported gross in the income statement, and “booked-out” sales and purchases (agreement with the counterparty to net settle before scheduling for delivery) were reported net. Effective with the January 1, 2006 realignment and consistent with reporting for the first and second quarters of 2006, those contracts that are separately managed as a trading book and scheduled for physical delivery are reported net upon settlement in accordance with existing accounting rules (EITF 02-03). All transactions reported net, including booked-out contracts, are reported as a component of revenues. Gross revenues from power trading activities in 2006 totaled approximately $384 million in the third quarter and $1.0 billion year-to-date.

Also, as previously disclosed, TXU Energy Company reviewed its reporting of ERCOT power balancing transactions. These transactions represent wholesale purchases and sales of power for real-time balancing purposes as measured in 15-minute intervals. As is industry practice, these purchases and sales with ERCOT, as the balancing energy clearinghouse agent, are reported net. TXU Energy Company has historically reported the net amount as a component of purchased power cost, as its retail load had exceeded baseload generation. The amount had consistently represented a net purchase of power prior to 2005. With TXU Energy Company’s generation increasingly exceeding its retail load, the net balancing activity has more recently generally resulted in net sales of power. TXU Energy Company believes that presentation of this activity as a component of revenues more appropriately reflects its market position. Accordingly, consistent with reporting for the first and second quarters of 2006, net power balancing transactions are reported in revenues and the prior years’ amounts have been reclassified. The amount reported in revenues for the third quarter and year-to-date periods of 2006 totaled $32 million and $6 million in net purchases, respectively. The amounts reclassified for the third quarter and year-to-date periods of 2005 totaled $123 million and $189 million in net sales, respectively.

5

Commodity contract and derivative assets and liabilities and margin deposits reported in the condensed consolidated balance sheet reflect counterparty netting in accordance with legal right of offset agreements.

Discontinued Businesses — Note 3 presents detailed information regarding the effects of discontinued businesses, the results of which have been classified as discontinued operations.

Use of Estimates — Preparation of TXU Energy Company’s financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including 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 to previous estimates or assumptions during the current period.

Changes in Accounting Standards — In September 2006, the FASB issued SFAS 157. SFAS 157 establishes a framework for measuring fair value. This statement is effective for fiscal years beginning after November 15, 2007. TXU Energy Company expects that the adoption of the statement will impact mark-to-market valuations of certain commodity contracts, but the effect is not expected to be material at this time.

Also, in September 2006, the FASB issued SFAS 158, which will be effective December 31, 2006 for TXU Energy Company. SFAS 158 revises SFAS 87, 88, 106 and 132(R) and requires reporting in the balance sheet of the funded status of defined benefit pension and other postretirement employee benefit (OPEB) plans. For TXU Energy Company, the initial recognition of the funded status on the financial statements is expected to be reflected as a decrease in the defined benefit obligation and an increase in accumulated other comprehensive income. SFAS 158 does not change the measurement or reporting of net periodic benefit costs in the income statement.

TXU Energy Company is a participating employer in the pension and OPEB plans sponsored by TXU Corp. The funded status of the pension plan is determined on a total plan basis and has been allocated to TXU Energy Company using assumptions designed to provide a reasonable approximation of the funded status for its participants. Historically, TXU Corp. has only made contributions to the OPEB plan for its regulated businesses. As a result, no OPEB plan assets have been allocated to TXU Energy Company. Following is an indicative estimate of the effect on the consolidated balance sheet of the adoption of SFAS 158 based on a December 31, 2005 measurement:

	Increase to September 30, 2006 Balances
Noncurrent assets:
Prepaid defined benefit pension	$	91
Noncurrent liabilities:
Accumulated deferred income taxes	$	26
OPEB obligation	$	14
Membership interests:
Accumulated other comprehensive income	$	51

The amounts to be recorded in the fourth quarter of 2006 upon adoption of SFAS 158 will be based on TXU Energy Company’s allocation of the measurements of TXU Corp.’s pension and OPEB plans at the December 31, 2006 year-end date, which has been TXU Energy Company’s practice but is now required under SFAS 158.

In September 2006, the FASB issued guidance regarding accounting for major maintenance activities (referred to as FSP AUG AIR-1). This guidance prohibits the use of the accrue-in-advance method of accounting. TXU Energy Company expenses major maintenance costs as incurred, and therefore the guidance is not applicable.

6

In July 2006, the FASB issued FIN 48. FIN 48 provides clarification of the accounting for uncertainty in income taxes in accordance with SFAS 109 and requires disclosure of tax benefits taken that do not qualify for financial statement recognition. FIN 48 is effective for fiscal years beginning after December 15, 2006. TXU Energy Company is currently evaluating the potential impact of this standard.

2.IMPAIRMENT OF NATURAL GAS-FIRED GENERATION PLANTS

As previously disclosed in the second quarter of 2006, TXU Energy Company performed an evaluation of its natural gas-fired generation plants for impairment in accordance with the requirements of SFAS 144, which provides that long-lived assets should be tested for recovery whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In consideration of the new lignite/coal-fired generation plant development program, among other factors, TXU Energy Company determined that it was more likely than not that its gas-fired generation plants, which have generally been operated to meet peak demands for power, would be sold or otherwise disposed of before the end of their previously estimated useful lives and should be tested for impairment as an asset group. As a result, it was determined that an impairment existed, and a charge of $196 million ($127 million after-tax) was recorded in 2006 to write down the assets to fair value, which was determined based on discounted estimated future cash flows. Future cash flow expectations are subject to considerable estimation, including forecasts of future natural gas prices and market heat rates. Further, the form and timing of usage and ultimate disposition of the plants is uncertain. Because of the highly judgmental nature of key assumptions and potential volatility of market conditions, the estimate of impairment is subject to future changes. The impairment was reported in other deductions in the Condensed Statements of Consolidated Income. (Also see Note 11.)

3.DISCONTINUED OPERATIONS

Discontinued operations in 2005 represents the results of the Pedricktown, New Jersey power production business sold in July 2005 as follows:

	Three Months Ended			Nine Months Ended
	September 30, 2005			September 30, 2005
Operating revenues	$	─		$	12
Operating costs and expenses		─			14
Operating loss before income taxes		─			(2	)
Income tax benefit		─			─
Charges related to exit (after-tax)		(2	)		(4	)
Loss from discontinued operations	$	(2	)	$	(6	)

4.TEXAS MARGIN TAX

As previously disclosed, the Texas legislature enacted a new law in May 2006 that reforms the Texas franchise tax system and replaces it with a new tax system, referred to as the Texas margin tax. The Texas margin tax is a significant change in Texas tax law because it generally makes all legal entities subject to tax, including general and limited partnerships, while the current franchise tax system applies only to corporations and limited liability companies. TXU Energy Company conducts significant operations through Texas limited partnerships that will become subject to the new Texas margin tax. The effective date of the Texas margin tax, which has been interpreted to be an income tax for accounting purposes, is January 1, 2008 for calendar year-end companies, and the computation of tax liability is expected to be based on 2007 revenues as reduced by certain deductions.

In accordance with the provisions of SFAS 109, which require that deferred tax assets and liabilities be adjusted for the effects of new tax legislation in the period of enactment, TXU Energy Company estimated and recorded a net charge to deferred tax expense of $42 million in the second quarter of 2006. The estimate is based on the Texas margin tax law in its current form and the current guidance issued by the Texas Comptroller of Public Accounts (Comptroller). TXU Energy Company expects the law to be amended in the next Texas legislative session beginning in January 2007 and for the Comptroller to issue further guidance. TXU Energy Company will monitor these developments and make any appropriate changes to its estimate.

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5.TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables — TXU Energy Company participates in an accounts receivable securitization program established by TXU Corp. for certain of its subsidiaries, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of TXU Energy Company 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). The current program is subject to renewal in June 2008.

As of September 30, 2006, the program funding to all TXU Corp. subsidiary participants (originators) totaled $700 million, which is the maximum amount of funding currently available under the program. The program funding to TXU Energy Company as of September 30, 2006 totaled $626 million. Under certain circumstances, the amount of customer deposits held by the originators can reduce the amount of undivided interests that can be sold, thus reducing funding available under the program. Funding availability for all originators is reduced by 100% of the originators’ customer deposits if TXU Energy Company’s fixed charge coverage ratio is less than 2.5 times; 50% if TXU Energy Company’s coverage ratio is less than 3.25 times, but at least 2.5 times; and zero % if TXU Energy Company’s coverage ratio is 3.25 times or more. The originators’ customer deposits, which totaled $115 million, did not affect funding availability at that date as TXU Energy Company’s coverage ratio was in excess of 3.25 times.

All new trade receivables under the program generated by TXU Energy Company 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, reflect seasonal variations in the level of accounts receivable, changes in collection trends as well as other factors such as changes in sales prices and volumes. TXU Receivables Company has issued subordinated notes payable to TXU Energy Company for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to TXU Energy Company that was funded by the sale of the undivided interests. The balance of the subordinated notes issued to TXU Energy Company, which is reported in trade accounts receivable, was $565 million and $154 million at September 30, 2006 and December 31, 2005, respectively.

The discount from face amount on the purchase of receivables principally funds program fees paid by TXU Receivables Company to the funding entities. The discount also funds a servicing fee paid by TXU Receivables Company to TXU Business Services Company, a direct subsidiary of TXU Corp. The program fees, also referred to as losses on sale of the receivables under SFAS 140, consist primarily of interest costs on the underlying financing and totaled $25 million and $12 million for the nine-month periods ending September 30, 2006 and 2005, respectively, and averaged 5.7% and 3.4% (on an annualized basis) of the funding under the program for the first nine months of 2006 and 2005, respectively. The servicing fee, which totaled approximately $3 million in the first nine months of both 2006 and 2005, compensates TXU Business Services Company for its services as collection agent, including maintaining the detailed accounts receivable collection records. The program and servicing fees represent essentially all the net incremental costs of the program to TXU Energy Company and are reported in SG&A expenses.

The accounts receivable balance reported in the September 30, 2006 consolidated balance sheet has been reduced by $1,191 million face amount of trade accounts receivable sold to TXU Receivables Company, partially offset by the inclusion of $565 million of subordinated notes receivable from TXU Receivables Company. Funding under the program increased $44 million to $626 million for the nine months ended September 30, 2006 and increased $213 million to $624 million for the nine months ended September 30, 2005. 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 balance approximated fair value due to the short-term nature of the collection period.

8

Activities of TXU Receivables Company related to TXU Energy Company for the nine months ended September 30, 2006 and 2005 were as follows:

	Nine Months Ended September 30,
	2006			2005
Cash collections on accounts receivable	$	5,259		$	4,626
Face amount of new receivables purchased		(5,714	)		(4,894	)
Discount from face amount of purchased receivables		28			15
Program fees paid		(25	)		(12	)
Servicing fees paid		(3	)		(3	)
Increase in subordinated notes payable		411			55
Operating cash flows provided to TXU Energy Company under the program	$	(44	)	$	(213	)

Upon termination of the program, cash flows to TXU Energy Company 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 30 days.

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; or

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.

Trade Accounts Receivable —

	September 30,			December 31,
	2006			2005
Gross trade accounts receivable	$	1,599		$	1,791
Undivided interests in accounts receivable sold by TXU Receivables Company		(1,191	)		(736	)
Subordinated notes receivable from TXU Receivables Company		565			154
Allowance for uncollectible accounts related to undivided interests in receivables retained		(26	)		(31	)
Trade accounts receivable ― reported in balance sheet	$	947		$	1,178

Gross trade accounts receivable at both September 30, 2006 and December 31, 2005 included unbilled revenues of $443 million.

Allowance for Uncollectible Accounts—

	2006			2005
Allowance for uncollectible accounts receivable as of January 1	$	31		$	15
Increase for bad debt expense		52			37
Decrease for account write-offs		(55	)		(43	)
Changes related to receivables sold		13			24
Other (a)		(15	)		15
Allowance for uncollectible accounts receivable as of September 30	$	26		$	48
____________

 (a)Reflects an allowance established in 2005 for a coal contract dispute that was reversed upon settlement in 2006. See Note 11.

Allowances related to undivided interests in receivables sold are reported in current liabilities and totaled $16 million and $29 million at September 30, 2006 and December 31, 2005, respectively.

9

6.SHORT-TERM AND LONG-TERM DEBT

Short-term Borrowings —At September 30, 2006 and December 31, 2005, the outstanding short-term borrowings of TXU Energy Company consisted of the following:

	At September 30, 2006					At December 31, 2005
	Outstanding Amount		Interest Rate (a)			Outstanding Amount		Interest Rate (a)
Commercial paper	$	360		5.56	%	$	306		4.48	%
Bank borrowings	$	295		5.88	%	$	440		4.86	%
Total	$	655				$	746
______________
(a)Weighted average interest rate at the end of the period.

Under the commercial paper program, TXU Energy Company may issue up to $2.4 billion of these securities. The program is supported by existing credit facilities.

Credit Facilities— At September 30, 2006, TXU Energy Company had access to credit facilities as follows:

		At September 30, 2006
Authorized Borrowers	Maturity Date	Facility Limit	Letters of Credit	Cash Borrowings	Availability
TXU Energy Company	May 2007	$1,500	$ ―	$―	$1,500
TXU Energy Company, TXU Electric Delivery	June 2008	1,400	483	―	917
TXU Energy Company, TXU Electric Delivery	August 2008	1,000	―	250	750
TXU Energy Company, TXU Electric Delivery	March 2010	1,600	3	―	1,597
TXU Energy Company, TXU Electric Delivery	June 2010	500	―	―	500
TXU Energy Company	December 2009	500	455	45	―
Total		$6,500	$941	$295	$5,264

 The $1.5 billion facility in the above table with a May 2007 maturity date was entered into by TXU Energy Company in May 2006 on terms comparable to its existing facilities.

The maximum amount TXU Energy Company and TXU Electric Delivery can directly access under the facilities is $6.5 billion and $3.6 billion, respectively. These facilities may be used for working capital and general corporate purposes, including providing support for issuances of commercial paper and for issuing letters of credit.

In addition, TXU Energy Company and TXU Electric Delivery have a $25 million joint uncommitted line of credit facility without an expiration date and a $50 million joint uncommitted line of credit facility that expires on December 31, 2006. The terms of these facilities are generally consistent with existing credit facilities, except that funding remains at the discretion of the lenders. As of September 30, 2006, there were no outstanding borrowings under these facilities.

All letters of credit and cash borrowings under the credit facilities as of September 30, 2006 are the obligations of TXU Energy Company. In addition, TXU Electric Delivery has outstanding commercial paper supported by these facilities totaling $615 million.

10

Long-term debt — At September 30, 2006 and December 31, 2005, the long-term debt of TXU Energy Company consisted of the following:

	September 30,			December 31,
	2006			2005
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39		$	39
5.400% Fixed Series 1994B due May 1, 2029, remarketing date May 1, 2006(a) (b)		―			39
5.400% Fixed Series 1995A due April 1, 2030, remarketing date May 1, 2006(a) (b)		―			50
5.050% Fixed Series 1995B due June 1, 2030, remarketing date June 19, 2006(a) (c)		―			114
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
3.850% Floating Series 2001A due October 1, 2030(d)		71			71
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)		217			217
3.790% Floating Series 2001D due May 1, 2033(d)		268			268
5.310% Floating Taxable Series 2001I due December 1, 2036(d)		62			62
3.850% Floating Series 2002A due May 1, 2037(d)		45			45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)		44			44
6.300% Fixed Series 2003B due July 1, 2032		39			39
6.750% Fixed Series 2003C due October 1, 2038		52			52
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014(a)		31			31
5.000% Fixed Series 2006 due March 1, 2041		100			―
Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021		51			51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011(a)		91			91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011(a)		107			107
5.200% Fixed Series 2001C due May 1, 2028		70			70
5.800% Fixed Series 2003A due July 1, 2022		12			12
6.150% Fixed Series 2003B due August 1, 2022		45			45
Trinity River Authority of Texas
6.250% Fixed Series 2000A due May 1, 2028		14			14
5.000% Fixed Series 2001A due May 1, 2027, remarketing date November 1, 2006(a)		37			37
Other:
6.125% Fixed Senior Notes due March 15, 2008 (e)		250			250
7.000% Fixed Senior Notes due March 15, 2013		1,000			1,000
4.920% Floating Rate Senior Notes due January 17, 2006 (interest rate in effect at December 31, 2005)		―			400
Capital lease obligations		101			103
Fair value adjustments related to interest rate swaps		10			9
Total TXU Energy Company		2,952			3,456
Less amount due currently		(11	)		(401	)
Total long-term debt	$	2,941		$	3,055

____________

(a)	These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.
(b)	Repurchased on May 1, 2006 for remarketing at a later date.
(c)	Repurchased on June 19, 2006 for remarketing at a later date.
(d)	Interest rates in effect at September 30, 2006. These series are in a weekly interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.
(e)	Interest rate swapped to variable on entire principal amount.

11

In August 2006, TXU Energy Company extended the $95 million Big Brown rail spur capital lease for five years through 2011.

Debt Issuances, Repurchases and Retirements in 2006 — In June 2006, upon the scheduled mandatory tender date, TXU Energy Company repurchased all of the Brazos River Authority Pollution Control Revenue (Refunding) Bonds Series 1995B with an aggregate principal amount of $114 million at a price of 100% of the principal amount thereof. TXU Energy Company currently plans to remarket these bonds.

In May 2006, upon the scheduled mandatory tender date, TXU Energy Company repurchased all of the Brazos River Authority Pollution Control Revenue (Refunding) Bonds Series 1994B and 1995A with aggregate principal amounts of $39 million and $50 million, respectively, at a price of 100% of the principal amounts thereof. TXU Energy Company currently plans to remarket these bonds.

In March 2006, TXU Energy Company issued the Brazos River Authority Series 2006 Pollution Control Revenue Bonds with an aggregate principal amount of $100 million. The bonds have a fixed interest rate of 5.0% and mature in March 2041. Net proceeds of $99 million (face amount less issuance expenses) from the issuance are held in a trust and are classified as restricted cash. Amounts in the trust earn interest that is also reported as restricted cash. Such proceeds will be released to TXU Energy Company by the trust at such time documentation of qualified expenditures are presented and approved by the trustee.

Other retirements of long-term debt in 2006 totaling $402 million represented payments at scheduled maturity dates and included $400 million of TXU Energy Company senior notes.

Fair Value Hedge —TXU Energy Company uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At September 30, 2006, $250 million of fixed rate debt had been effectively converted to variable rates through an interest rate swap transaction expiring in 2008. The swap qualified for and has been designated as a fair value hedge in accordance with SFAS 133 (under the short-cut method as the conditions for assuming no ineffectiveness are met).

Long-term debt fair value adjustments—

	September 30, 2006
Long-term debt fair value adjustments related to an interest rate swap at beginning of period ― increase in debt carrying value	$	9
Fair value adjustments during the period		3
Amortization of net gains on settled fair value hedge (a)		(2	)
Long-term debt fair value adjustments at end of period ― increase in debt carrying value (net in-the-money value of swap)	$	10

 ___________

(a) Net value of settled in-the-money fixed-to-variable swap that is being amortized as a reduction to interest expense over the remaining life of the associated debt. Amount is pretax.

Any changes in open (unsettled) swap fair values reported as fair value adjustments to debt amounts are offset by changes in derivative assets and liabilities.

12

7.MEMBERSHIP INTERESTS

Effective September 30, 2006, TXU Energy Company’s exchangeable preferred membership interests, which were held entirely by subsidiaries of TXU Corp., were recapitalized into common equity membership interests of TXU Energy Company. The principal amount of these preferred interests, net of the related discount, were reported as a noncurrent liability in the condensed consolidated balance sheet.

The following amounts were reclassified to membership interests at September 30, 2006:

Principal amount of the preferred interests	$	750
Remaining unamortized discount recorded at issuance		(208	)
Remaining unamortized issuance costs (a)		(21	)
Total amount recapitalized	$	521
____________
(a) Reported in other noncurrent assets in the condensed consolidated balance sheet.

Under SFAS 123R, compensation expense related to TXU Corp.’s stock-based incentive compensation awards to TXU Energy Company’s employees is accounted for as a noncash capital contribution from the parent. Accordingly, TXU Energy Company recorded a credit to its membership interests account of $2 million and $6 million for the three and nine months ended September 30, 2006, respectively.

The increase in membership interests in 2006 in the table below also reflects the excess tax benefit of $13 million arising from the distribution date value of the stock-based incentive awards exceeding the reported compensation expense.

Cash distributions of $286 million were paid to US Holdings in January 2006, April 2006 and July 2006.

The following table presents the changes in membership interests for the nine months ended September 30, 2006:

	Capital Accounts			Accumulated Other Comprehensive Gain (Loss)			Total Membership Interests
Balance at December 31, 2005	$	4,474		$	(121	)	$	4,353
Net income		1,947			─			1,947
Distributions paid to parent		(858	)		─			(858	)
Net effects of cash flow hedges (net of tax)		─			402			402
Effects of stock-based incentive compensation plans		19			─			19
Recapitalization of exchangeable preferred membership interests		521			─			521
Other		1			─			1
Balance at September 30, 2006	$	6,104		$	281		$	6,385

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8.COMMITMENTS AND CONTINGENCIES

Wholesale Market Activity Investigation — On October 6, 2006, TXU Portfolio Management Company was notified that the Commission had begun an investigation of its 2005 activities in the ERCOT wholesale electricity market as a result of observations noted in the 2005 State of the Market Report for the ERCOT WholesaleElectricity Market performed by Potomac Economics, an economic consulting firm. Although it has not yet received any information requests from the Commission, TXU Portfolio Management Company believes that the investigation will focus on activities involving bids to sell balancing energy and generation unit commitments. Balancing energy represents approximately five to ten percent of the total energy sold in the ERCOT wholesale market. TXU Portfolio Management Company intends to cooperate fully with the Commission in its investigation.

Guarantees — TXU Energy Company has entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions. Guarantees issued or modified after December 31, 2002 are subject to the recognition and initial measurement provisions of FIN 45, which requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.

Debt obligation of TXU Corp. ―TXU Energy Company has provided a guarantee of the obligations under TXU Corp.’s financing lease (approximately $99 million at September 30, 2006) for its headquarters building.

Residual value guarantees in operating leases — TXU Energy Company is the lessee under various operating leases that obligate it to guarantee the residual values of the leased assets. At September 30, 2006, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled approximately $96 million. These leased assets consist primarily of mining equipment and rail cars. The average life of the lease portfolio is approximately seven years. A significant portion of the maximum guarantee amount relates to leases entered into prior to December 31, 2002.

Letters of credit — At September 30, 2006, TXU Energy Company had outstanding letters of credit under its revolving credit facilities in the amount of $449 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter transactions related to the long-term hedging program, and for miscellaneous credit support requirements. As of September 30, 2006, approximately 15% of the obligations supported by these letters of credit mature within one year, and substantially all of the remainder mature in the next four years. Additionally, TXU DevCo’s commodity price hedging transactions under a long-term hedging program were initially supported by letters of credit aggregating $500 million issued by TXU Energy Company. On August 30, 2006, the letters of credit were cancelled by the counterparty and replaced by a first-lien security interest in the assets of TXU Big Brown consisting of two lignite/coal-fired generation units.

Further, TXU Energy Company has outstanding letters of credit under its revolving credit facilities totaling $455 million at September 30, 2006 to support existing floating rate pollution control revenue bond debt of $446 million principal amount. The letters of credit are available to fund the payment of such debt obligations and expire in 2009.

Contractual Obligations— TXU Energy Company has entered into an engineering, procurement and construction contract for the development of two generation units. Contingent cancellation costs related to this agreement totaled approximately $120 million at September 30, 2006. This amount could be reduced by recovery values related to the assets acquired and for owned assets that are intended to be utilized in the project. The obligations under the contract are expected to be assumed by TXU DevCo by the spring of 2007.

14

Legal Proceedings—On March 18, 2005, TXU Corp. received a subpoena from the SEC. The subpoena requires TXU Corp. to produce documents and other information for the period from January 1, 2001 to March 31, 2003 relating to, among other things, the financial distress at TXU Europe during 2002 and the resulting financial condition of TXU Corp. including reduction of TXU Corp.’s quarterly dividend in October 2002. The documents accompanying the subpoena state that (i) the SEC is conducting a fact-finding inquiry for purposes of allowing it to determine whether there have been any violations of the federal securities laws and (ii) the request does not mean the SEC has concluded that TXU Corp. or any other person has violated the law. TXU Corp. cannot predict the outcome of the SEC inquiry, but does not believe that there were any violations of law or regulation in connection with the events which are the subject of the SEC’s inquiry. TXU Corp. has cooperated with the SEC and completed the production of the documents requested by the subpoena. TXU Corp. has also responded to the SEC’s requests for information, including requests for production of additional email data.

Between October 19, 2004 and October 31, 2005, twelve lawsuits were filed in various California superior courts by purported customers against TXU Corp., TXU Energy Trading Company and TXU Energy Services and other marketers, traders, transporters and sellers of natural gas in California. Plaintiffs allege that beginning at least by the summer of 2000, defendants manipulated and fixed at artificially high levels natural gas prices in California in violation of the Cartwright Act and other California state laws. These lawsuits have been coordinated in the San Diego Superior Court with numerous other natural gas actions as "In re Natural Gas Anti-Trust Cases I, II, III, IV and V." The court denied TXU Corp.’s Motion to Quash Service for lack of personal jurisdiction. Discovery has commenced in this litigation. TXU Corp. believes the claims against TXU Corp. and its subsidiaries are without merit and TXU Corp. intends to vigorously defend the lawsuits. TXU Energy Company is, however, unable to estimate any possible loss or predict the outcome of these actions.

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

Environmental Contingencies ― The federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on sulfur dioxide and nitrogen oxide emissions produced by electricity generation plants. The capital requirements of TXU Energy Company and its subsidiaries have not been significantly affected by the requirements of the Clean Air Act. In addition, all air pollution control provisions of the 1999 Restructuring Legislation have been satisfied.

TXU Energy Company and its subsidiaries must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. TXU Energy Company and its subsidiaries are in compliance with all current laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulation is not determinable. The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:

· changes toexisting state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters;

· the identification of sites requiring clean-up or the filing of other complaints in which TXU Energy Company or its subsidiaries may be asserted to be potential responsible parties.

15

9.COMMODITY CONTRACT ASSETS AND LIABILITIES

Commodity contract assets and liabilities generally arise from changes in the fair value of derivative contracts entered into for commodity price hedging and proprietary trading purposes and include mark-to-market values of derivative contracts that are either not accounted for as cash flow hedges or for which the “normal” purchase or sale exemption has not been elected under SFAS 133.

Current and noncurrent commodity contract assets totaling $596 million at September 30, 2006 and $1.9 billion at December 31, 2005 are stated net of applicable credit (collection) and performance reserves totaling $9 million and $12 million, respectively. Performance reserves are provided for direct, incremental costs to settle the contracts.

Current and noncurrent commodity contract liabilities totaled $667 million at September 30, 2006 and $2.0 billion at December 31, 2005.

10.CASH FLOW HEDGES UNDER SFAS 133

TXU Energy Company experienced cash flow hedge ineffectiveness net gains related to positions held at the end of the period of $129 million and $274 million for the three and nine month periods ended September 30, 2006, respectively. For the corresponding periods of 2005, the amounts were $1 million and $2 million in net gains, respectively. These amounts are pretax and are reported in revenues.

The net effect of recording unrealized mark-to-market gains and losses arising from hedge ineffectiveness (versus recording gains and losses upon settlement) includes the above amounts as well as the effect of reversing unrealized ineffectiveness gains and losses recorded in previous periods to offset realized gains and losses in the current period. Such net effect totaled $136 million and $286 million in net gains for the three and nine month periods ended September 30, 2006, respectively, and $2 million and $8 million in net gains for the three and nine month periods ended September 30, 2005, respectively.

As of September 30, 2006, commodity positions accounted for as cash flow hedges reduce exposure to variability of future cash flows from future revenues or purchases through 2011.

Cash flow hedge amounts reported in the Statements of Consolidated Comprehensive Income exclude net gains and losses associated with cash flow hedges entered into and settled within the periods presented. These totaled $12 million in after-tax net losses and $6 million in after-tax net gains for the three and nine month periods ended September 30, 2006, respectively, and $4 million and $6 million in after-tax net gains for the corresponding periods of 2005.

TXU Energy Company expects that $129 million in after-tax net gains related to cash flow hedges included in accumulated other comprehensive net income will be reclassified into net income during the next twelve months as the related hedged transactions are settled and affect net income. Of this amount, $135 million in gains relate to commodity hedges and $6 million in losses relate to financing-related hedges.

16

11.OTHER INCOME AND DEDUCTIONS

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006			2005
Other income:
Net gain on sales of assets (a)	$	9		$	5	$	9		$	6
Gain on sale of power transmission project investment		─			7		─			7
Insurance recovery of damage claim		─			6		─			6
Power services agreement termination fee		─			─		─			4
Other		─			1		2			5
Total other income	$	9		$	19	$	11		$	28
Other deductions:
Impairment of natural gas-fired generation plants (b)	$	(2	)	$	─	$	196		$	─
Charge (credit) related to coal contract counterparty claim (c)		─			─		(12	)		12
Inventory write-off related to natural gas-fired generation plants		─			─		3			─
Capgemini outsourcing transition costs		─			3		─			9
Equity losses of affiliate holding investment in Capgemini		3			2		8			5
Charge (credit) related to impaired leases (d)		─			─		(4	)		(12	)
Other		3			1		7			5
Total other deductions	$	4		$	6	$	198		$	19

_____________
(a)	In the third quarter of 2006, TXU Energy Company recorded an $8 million gain related to the sale of mineral interests.
(b)	See Note 2 for discussion of impairment charge recorded in the second quarter of 2006. The $2 million adjustment in the third quarter relates to combustion turbines held by another TXU Corp. subsidiary.
(c)	In the first quarter of 2006, TXU Energy Company recorded income of $12 million upon the settlement of a claim against a counterparty for nonperformance under a coal contract. A charge in the same amount was recorded in the first quarter of 2005 for losses due to the nonperformance.
(d)	Amounts recorded in 2005 and 2006 for impaired leases relate to gas-fired combustion turbines that TXU Energy Company has ceased operating for its own benefit. The amounts represent adjustments to the estimated charge of $157 million recorded in 2004 for net liabilities under the leases.

17

12.RELATED-PARTY TRANSACTIONS

The following represent the significant related-party transactions of TXU Energy Company:

·   TXU Energy Company incurs electricity delivery fees charged by TXU Electric Delivery. These fees totaled $346 million and $386 million for the three months ended September 30, 2006 and 2005, respectively, and $900 million and $1.0 billion for the nine months ended September 30, 2006 and 2005, respectively.

·   TXU Electric Delivery has issued securitization bonds to recover generation-related regulatory assets through a transition charge to its customers. The incremental income taxes TXU Electric Delivery will pay on the transition charges it collects will be reimbursed by TXU Energy Company. Therefore, TXU Energy Company’s financial statements reflect a noninterest bearing note payable to TXU Electric Delivery of $364 million ($32 million reported as current liabilities) at September 30, 2006 and $395 million ($33 million reported as current liabilities) at December 31, 2005.

·   TXU Energy Company records interest expense to reimburse TXU Electric Delivery for interest on TXU Electric Delivery’s securitization bonds. This interest expense totaled $13 million and $14 million for the three months ended September 30, 2006 and 2005, respectively, and $40 million and $42 million for the nine months ended September 30, 2006 and 2005, respectively.

·   Current and noncurrent advances to parent totaled $2.6 billion at September 30, 2006 and $694 million at December 31, 2005. The average daily balances of the advances to parent totaled $2.4 billion and $1.5 billion during the three months ended September 30, 2006 and 2005, respectively. Interest income earned on the advances totaled $35 million and $16 million for the three months ended September 30, 2006 and 2005, respectively. The weighted average annual interest rates were 5.72% and 4.21% for the three months ended September 30, 2006 and 2005, respectively. The average daily balance of the advances to parent were $1.6 billion and $1.1 billion during the nine months ended September 30, 2006 and 2005, respectively. Interest income earned on the advances totaled $67 million and $32 million for the nine months ended September 30, 2006 and 2005, respectively. The weighted average annual interest rates were 5.35% and 3.87% for the nine months ended September 30, 2006 and 2005, respectively.

·   In December 2005, TXU Energy Company received a $1.5 billion note receivable from TXU Corp. in partial settlement of outstanding advances to parent. The note carries interest at the same rate applied to advances to affiliates as discussed above. Interest income related to this note totaled $21 million and $61 million for the three and nine months ended September 30, 2006, respectively.

·   TXU Corp. charges TXU Energy Company for financial, accounting, environmental and other administrative services at cost. These costs, which are primarily reported in SG&A expenses, totaled $15 million and $18 million for the three months ended September 30, 2006 and 2005, respectively, and $51 million and $46 million for the nine months ended September 30, 2006 and 2005, respectively.

·   Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in investments on TXU Energy Company’s balance sheet, is funded by a delivery fee surcharge billed to REPs by TXU Electric Delivery and remitted to TXU Energy Company, with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported in noncurrent liabilities on TXU Energy Company’s balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by TXU Energy Company are offset by a net change in the intercompany receivable/payable with TXU Electric Delivery, which in turn results in a change in the net regulatory asset/liability. The regulatory liability, which totaled $2 million at September 30, 2006 and is reported on TXU Electric Delivery’s balance sheet, represents the excess of the trust fund balance over the decommissioning liability. The regulatory asset, which totaled $8 million at December 31, 2005 and is reported on TXU Electric Delivery’s balance sheet, represents the excess of the decommissioning liability over the trust fund balance.

18

· Distributions and discount amortization (both reported as interest expense) related to TXU Energy Company’s exchangeable preferred membership interests held entirely by subsidiaries of TXU Corp. totaled $23 million and $22 million for the three months ended September 30, 2006 and 2005, respectively, and totaled $67 million and $65 million for the nine months ended September 30, 2006 and 2005, respectively. Effective September 30, 2006, these securities were recapitalized into common equity membership interests (see Note 7).

· In March 2006, US Holdings completed the purchase of the owner participant interest in a trust that leases combustion turbines to TXU Energy Company. The trust was consolidated by US Holdings at December 31, 2005. In 2004, TXU Energy Company had recorded a liability for lease payments to the trust because TXU Energy Company had ceased using certain of the combustion turbines for its own benefit. The remaining liability totaled $50 million ($12 million reported as due currently) at September 30, 2006 and $59 million ($15 million reported as due currently) at December 31, 2005. TXU Energy Company’s lease expense for the trust’s other combustion turbines that it continues to operate for its own benefit totaled $3 million and $8 million for the three and nine months ended September 30, 2006, respectively, and are reported as operating costs.

· TXU Energy Company has a 53.1% limited partnership interest, with a carrying value of $16 million and $24 million at September 30, 2006 and December 31, 2005, respectively, in a TXU Corp. subsidiary holding Capgemini-related assets. Equity losses related to this interest totaled $3 million and $2 million for the three months ended September 30, 2006 and 2005, respectively, and totaled $8 million and $5 million for the nine months ended September 30, 2006 and 2005, respectively. These losses primarily represent amortization of software assets held by the subsidiary. The equity losses are reported as other deductions.

· TXU Corp. files a consolidated federal income tax return, and federal income taxes are allocated to subsidiaries based on their respective taxable income or loss. As a result, TXU Energy Company had an income tax payable to TXU Corp. of $620 million at September 30, 2006 and an income tax receivable from TXU Corp. of $361 million at December 31, 2005.

· TXU Energy Company charges TXU DevCo for employee services related to the development of generation facilities in Texas. These charges totaled $1 million and $2 million for the three and nine months ended September 30, 2006, respectively, and are largely reflected as a reduction in TXU Energy Company’s SG&A expenses.

See Notes 5, 7 and 13 for information regarding the accounts receivable securitization program and related subordinated notes receivable from TXU Receivables Company, cash distributions to US Holdings and the assumption by TXU Electric Delivery of certain TXU Energy Company pension and other postretirement benefit costs, respectively.

19

13.SUPPLEMENTARY FINANCIAL INFORMATION

Interest Expense and Related Charges—

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Interest	$	89		$	84		$	256		$	224
Distributions on exchangeable preferred membership interests		17			17			51			51
Amortization of discount and debt issuance costs		8			4			22			21
Interest capitalized in accordance with SFAS 34		(6	)		(3	)		(19	)		(9	)
Total interest expense and related charges	$	108		$	102		$	310		$	287

Restricted Cash —

	Balance Sheet Classification
	At September 30, 2006				At December 31, 2005
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Pollution control revenue bond funds held by trustee (See Note 6)	$	―	$	101	$	―	$	―
All other		3		―		8		―
Total restricted cash	$	3	$	101	$	8	$	―

Inventories by Major Category —

	September 30,		December 31,
	2006		2005
Materials and supplies	$	116	$	108
Environmental energy credits and emission allowances		15		21
Fuel stock		95		81
Natural gas in storage		88		99
Total inventories	$	314	$	309

Investments —

	September 30,		December 31,
	2006		2005
Nuclear decommissioning trust	$	424	$	389
Assets related to employee benefit plans, principally employee savings programs		47		54
Land		31		32
Investment in affiliate holding Capgemini-related assets		16		24
Miscellaneous other		1		2
Total investments	$	519	$	501

Property, Plant and Equipment — As of September 30, 2006 and December 31, 2005, property, plant and equipment of $10.0 billion for both periods is stated net of

accumulated depreciation and amortization of $8.2 billion and $7.9 billion, respectively.

20

Asset Retirement Obligations— For TXU Energy Company, such liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fired plant ash treatment facilities and asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of TXU Electric Delivery’s rate setting.

The following table summarizes the changes to the asset retirement liability, reported in other noncurrent liabilities and deferred credits in the condensed consolidated balance sheet, during the nine months ended September 30, 2006:

Asset retirement liability at December 31, 2005	$	558
Additions:
Accretion		27
Reductions:
Net change in mining land reclamation estimated liability		(4	)
Mining reclamation payments		(20	)
Asset retirement liability at September 30, 2006	$	561

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

	As of September 30, 2006						As of December 31, 2005
	Gross						Gross
	Carrying		Accumulated				Carrying		Accumulated
	Amount		Amortization		Net		Amount		Amortization		Net
Intangible assets subject to amortization included
in property, plant and equipment:
Mineral rights and other	$	31	$	24	$	7	$	31	$	24	$	7
Capitalized software placed in service		11		5		6		7		3		4
Land easements		2		1		1		2		1		1
Total	$	44	$	30	$	14	$	40	$	28	$	12

Aggregate amortization expense for intangible assets totaled $0.8 million and $1 million for the three months ended September 30, 2006 and 2005, respectively, and totaled $2 million for both the nine months ended September 30, 2006 and 2005, respectively. At September 30, 2006, the weighted average remaining useful lives of mineral rights and other assets, capitalized software and land easements were 40 years, 6 years and 54 years, respectively.

The estimated aggregate amortization expense for each of the five succeeding fiscal years from December 31, 2005 is $1 million for the years 2006-2009 and less than $1 million for 2010.

Goodwill of $517 million at September 30, 2006 and December 31, 2005 was stated net of previously recorded accumulated amortization of $60 million.

21

Pension and Other Postretirement Benefits (OPEBs)— TXU Energy Company is a participating employer in the pension plan sponsored by TXU Corp. TXU Energy Company also participates with TXU Corp. and other subsidiaries of TXU Corp. to offer health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. The allocated pension and OPEB costs applicable to TXU Energy Company totaled $4 million for both the three month periods ended September 30, 2006 and 2005 and $13 million and $11 million for the nine month periods ended September 30, 2006 and 2005, respectively.

The discount rate reflected in net pension and OPEB costs in 2006 is 5.75%. The expected rate of return on plan assets reflected in the 2006 cost amounts is 8.75% for the pension plan and 8.67% for OPEBs.

In June 2005, an amendment to PURA relating to pension and OPEBs was enacted by the Texas Legislature. This amendment, which was retroactively effective January 1, 2005, provides for the recovery by TXU Electric Delivery of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, primarily TXU Energy Company’s active and retired employees, related to employee service prior to the unbundling of TXU Corp.’s electric utility business and the deregulation of the Texas electricity industry effective January 1, 2002. TXU Electric Delivery and TXU Energy Company have entered into an agreement whereby TXU Electric Delivery has assumed responsibility for TXU Energy Company’s applicable pension and OPEB costs. In accordance with this agreement, TXU Energy Company’s pension-related liabilities of $137 million and pension-related assets of $8 million were transferred to TXU Electric Delivery in 2005 and 2006, respectively.

Severance Liabilities Related to Strategic Initiatives —

Liability for severance costs as of December 31, 2005	$	18
Additions to liability (a)		8
Payments charged against liability		(23	)
Other adjustments to liability		(1	)
Liability for severance costs as of September 30, 2006	$	2
_____________
(a)Additions to the liability relate to an outsourcing of certain engineering services.

Supplemental Cash Flow Information—

	Nine Months Ended September 30,
	2006			2005
Cash payments (receipts) related to continuing operations:
Interest (net of amounts capitalized)	$	304		$	282
Income taxes	$	(169	)	$	524
Noncash investing and financing activities:
Capital lease for generation plant rail spur	$	─		$	95
Noncash contribution of pension-related assets	$	(8	)	$	156
Recapitalization of exchangeable preferred membership interests	$	521		$	─

22

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Member of TXU Energy Company LLC:

We have reviewed the accompanying condensed consolidated balance sheet of TXU Energy Company LLC and subsidiaries (“TXU Energy Company”) as of September 30, 2006, and the related condensed statements of consolidated income and comprehensive income for the three-month and nine-month periods ended September 30, 2006 and 2005, and of cash flows for the nine-month periods ended September 30, 2006 and 2005. These interim financial statements are the responsibility of TXU Energy Company’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of TXU Energy Company as of December 31, 2005, and the related statements of consolidated income, comprehensive income, membership interests, and cash flows for the year then ended (not presented herein); and in our report dated March 1, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Dallas, Texas

November 9, 2006

23

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS

TXU Energy Company is a wholly-owned subsidiary of US Holdings, which is a wholly-owned subsidiary of TXU Corp. TXU Energy Company is a holding company whose subsidiaries are engaged in electricity generation, retail electricity sales to residential and business customers as well as wholesale energy markets activities primarily in Texas. TXU Energy Company is managed as an integrated business; therefore, there are no reportable business segments.

SIGNIFICANT DEVELOPMENTS IN 2006

New Generation Development Program

As previously disclosed, TXU Corp., currently through TXU DevCo, intends to develop and construct up to 11 lignite/coal-fired generation units in Texas. In connection with this development program, TXU Energy Company expects to incur capital expenditures of approximately $550 million for environmental control systems to voluntarily reduce emissions from TXU Energy Company’s existing lignite/coal fired-generation facilities. Further, TXU Corp. is launching a renewable energy initiative involving investment in power facilities that is expected to double TXU Energy Company’s renewable energy portfolio to 1,400 MW by 2011.

Impairment of Natural Gas-Fired Generation Plants

As previously disclosed, in consideration of the new generation development program and other factors, TXU Energy Company performed a test of recoverability of the carrying value of its natural gas-fired generation plants. See Note 2 to Financial Statements for a discussion of the impairment of the plants, resulting in a charge in 2006 of $196 million ($127 million after-tax).

Long-term Hedging Program and Related Collateral Arrangements

As previously disclosed, TXU Corp. commenced a long-term hedging program in October 2005 designed to reduce exposure to changes in future power prices due to changes in the price of natural gas. Under the program, subsidiaries of TXU Energy Company have entered into market transactions involving natural gas-related financial instruments. Since February 2006, TXU Energy Company has more than doubled its position of forward gas sales for the period from 2006 to 2012, the substantial majority of which are being accounted for as cash flow hedges of future energy transactions. The balance of the hedge transactions are marked-to-market in net income. While there is significant correlation in the movement of natural gas prices and wholesale power prices in ERCOT because marginal demand is generally met with gas-fired generation plants, power prices do not always move in tandem with natural gas prices. Given the size of the hedge program and the cross-commodity nature of the hedges, the program may result in greater volatility of net income due to hedge ineffectiveness gains and losses, as well as greater mark-to-market gains and losses largely reported in other comprehensive income, than TXU Energy Company has experienced in recent years. The effect on reported earnings of unrealized hedge ineffectiveness net gains and mark-to-market net gains recorded under SFAS 133 (versus settlement accounting) totaled $139 million and $264 million pretax for the three and nine month periods ended September 30, 2006, respectively, for positions in the program. Based on the current size of the long-term hedging program, a parallel 0.1 (or approximately 1%) change in market heat rate across each year of the program may cause up to an estimated $80 million to $100 million in cash flow hedge ineffectiveness pretax gains or losses in the period of such change. The other positions in the hedging program that are marked-to-market could, with a similarly parallel $1.00/MMBtu move in gas prices, result in an estimated $160 million of unrealized mark-to-market pre-tax gains or losses.

24

As discussed below, TXU DevCo entered into a related series of hedging transactions in June 2006. The discussion immediately above does not include any amounts related to TXU DevCo’s hedging transactions.

As part of TXU Corp.’s overall hedging program, in June 2006 TXU DevCo entered into a related series of hedging transactions that allow hedging of movements in power prices through both new transactions and the novation of existing TXU Energy Company hedging transactions to TXU DevCo.

Commodity hedging transactions typically require the posting of collateral to support potential future payment obligations if the forward price of natural gas moves such that the hedging instrument is out-of-the-money to the holder. Subsidiaries of TXU Energy Company have used cash and letters of credit to satisfy their collateral obligations. TXU DevCo’s hedging transactions were initially supported by letters of credit aggregating $500 million issued by TXU Energy Company. Considering the current and expected scale of its hedging program and the desire to reduce the potential effect on liquidity of collateral postings, on August 30, 2006, the $500 million of TXU Energy Company letters of credit were replaced with a first-lien security interest in the assets of TXU Big Brown consisting of two existing lignite/coal-fired generation units. This security interest (Big Brown Lien) supports a portion of the positions in the long-term hedging program.

The Big Brown Lien is expected to be replaced as collateral for the TXU DevCo hedging transactions by a capped first-lien and an uncapped second-lien on the assets of TXU DevCo on the earlier of December 31, 2007 or the date when TXU DevCo has secured air permits for the new Oak Grove generation units and at least four of the eight new reference plants.

In accordance with the TXU DevCo hedging agreement, on December 31, 2007, TXU DevCo expects to determine the amount of hedging transactions that may be secured by liens on TXU DevCo assets. The hedge amounts are expected to be based on an agreed-upon portion of each 1,000 megawatts of air-permitted capacity that is expected to be commercially available between 2009 and 2012. To the extent there are excess hedges at TXU DevCo, such hedges would be novated back to TXU Energy Company and continue to be secured by the Big Brown Lien (or alternative collateral of equivalent value or letters of credit).

TXU Energy Retail Customer Initiatives

On October 3, 2006, in connection with the upcoming transition to full competition in the Texas retail electricity market that will occur as a result of the expiration of price-to-beat on January 1, 2007, TXU Energy Retail announced a strategy that includes the following four elements:

· Those residential customers receiving service from TXU Energy Retail as of October 29, 2006 and who live in areas where TXU Energy Retail offers the price-to-beat rate will receive a special one-time customer appreciation bonus of $100. This bonus program is expected to result in an estimated pretax charge of approximately $165 million in the fourth quarter of 2006. These bonuses are expected to be paid in four quarterly installments beginning November 2006.

· In order to protect customers against the risk of rising wholesale power prices, TXU Energy Retail has committed to not raise rates for its residential price-to-beat customers and other month-to-month customers paying a rate that is equal to the price-to-beat rate as of December 31, 2006 who choose to remain on their existing plan and meet certain other criteria, for a period of three years or until at least January 1, 2010.

· For a limited time, any residential price-to-beat customer who chooses one of TXU Energy Retail’s non-price-to-beat plans, or any residential customer who chooses any of TXU Energy Retail’s term plans, will receive a $25 sign-up incentive.

· An extension of TXU Energy Retail’s 10% discount program for low-income residential customers through September 1, 2007.

Other than the impact of the one-time customer appreciation bonus, TXU Energy Company cannot predict the impact, if any, of the strategy on its results of operations.

25

RESULTS OF OPERATIONS

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

The results of operations and the related management’s discussion of those results for all periods presented reflect the discontinuance of certain operations (see Note 3 to Financial Statements regarding discontinued operations).

Sales Volume Data

	Three Months Ended									Nine Months Ended
	September 30,									September 30,
	2006			2005			Change %			2006			2005			Change %
Sales volumes:
Retail electricity sales volumes (GWh):
Historical service territory:
Residential		8,838			9,965			(11.3	)		20,896			23,382			(10.6	)
Small business (a)		2,408			2,801			(14.0	)		6,203			7,124			(12.9	)
Total historical service territory		11,246			12,766			(11.9	)		27,099			30,506			(11.2	)
Other territories:
Residential		1,245			1,215			2.5			2,874			2,701			6.4
Small business (a)		213			233			(8.6	)		513			537			(4.5	)
Total other territories		1,458			1,448			0.7			3,387			3,238			4.6
Large business and other customers		3,918			4,006			(2.2	)		10,703			12,540			(14.6	)
Total retail electricity		16,622			18,220			(8.8	)		41,189			46,284			(11.0	)
Wholesale electricity sales volumes (b)		10,268			15,679			(34.5	)		27,138			40,504			(33.0	)
Total sales volumes		26,890			33,899			(20.7	)		68,327			86,788			(21.3	)
Average volume (kWh) per retail customer (c):
Residential		5,244			5,500			(4.7	)		12,235			12,563			(2.6	)
Small business		9,501			10,247			(7.3	)		23,926			25,241			(5.2	)
Large business and other customers		81,369			71,972			13.1			210,515			192,090			9.6
Weather (service territory average) - percent of normal (d):
Percent of normal:
Cooling degree days		109.0	%		106.2	%					118.5	%		104.5	%

________________

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

(b) See Note 1 to Financial Statements for discussion of reporting of trading and ERCOT balancing activity in 2006. Includes net sales volumes related to ERCOT balancing of 103 GWh in the third quarter of 2006 and 1,910 GWh in the third quarter of 2005, and net sales volumes of 1,268 GWh and 3,923 GWh in the nine months ended September 30, 2006 and 2005, respectively.

(c) Calculated using average number of customers for period.

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

26

Customer Count Data

	Nine Months Ended
	September 30,
	2006		2005		Change %
Customer counts:
Retail electricity customers (end of period and in thousands) (a):
Historical service territory:
Residential		1,670		1,804		(7.4	)
Small business (b)		265		285		(7.0	)
Total historical service territory		1,935		2,089		(7.4	)
Other territories:
Residential		234		203		15.3
Small business (b)		8		7		14.3
Total other territories		242		210		15.2
Large business and other customers		47		55		(14.5	)
Total retail electricity customers		2,224		2,354		(5.5	)

________________

(a) Based on number of meters.

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

27

Revenue and Market Share Data

	Three Months Ended									Nine Months Ended
	September 30,									September 30,
	2006			2005			Change %			2006			2005			Change %
Operating revenues:
Retail electricity revenues:
Historical service territory:
Residential	$	1,333		$	1,208			10.3		$	3,086		$	2,682			15.1
Small business (a)		357			333			7.2			923			831			11.1
Total historical service territory		1,690			1,541			9.7			4,009			3,513			14.1
Other territories:
Residential		194			153			26.8			442			309			43.0
Small business (a)		25			24			4.2			61			51			19.6
Total other territories		219			177			23.7			503			360			39.7
Large business and other customers		375			347			8.1			1,031			1,006			2.5
Total retail electricity revenues		2,284			2,065			10.6			5,543			4,879			13.6
Wholesale electricity revenues (b)		648			959			(32.4	)		1,629			2,091			(22.1	)
Net gains (losses) from risk management and trading activities		72			(116	)		─			134			(122	)		─
Other revenues		87			86			1.2			263			243			8.2
Total operating revenues	$	3,091		$	2,994			3.2		$	7,569		$	7,091			6.7
Risk management and trading activities:
Realized net gains (losses) on settled positions	$	(67	)	$	(11	)				$	(153	)	$	(35	)
Reversal of prior periods’ unrealized net (gains) losses
on positions settled in current period		(21	)		3						1			(20	)
Other unrealized net gains (losses), including cash flow hedge ineffectiveness		160			(108	)					286			(67	)
Total net gains (losses)	$	72		$	(116	)				$	134		$	(122	)
Average revenues per MWh:
Residential	$	151.45		$	121.81			24.3		$	148.44		$	114.71			29.4
Small business	$	145.66		$	117.37			24.1		$	146.44		$	115.09			27.2
Large business and other customers	$	95.83		$	86.61			10.6		$	96.29		$	80.20			20.1
Estimated share of ERCOT retail markets (c)(d):
Historical service territory:
Residential											67	%		74	%
Small business											67	%		73	%
Total ERCOT:
Residential											37	%		40	%
Small business											27	%		30	%
Large business and other customers											16	%		19	%

__________________________

(a)	Customers with demand of less than 1 MW annually.
(b)	See Note 1 to Financial Statements for discussion of reporting of trading and ERCOT balancing activity in 2006. Includes net purchases related to ERCOT balancing of $32 million in the third quarter of 2006 and $123 million of net sales in the third quarter of 2005, and net purchases of $6 million and net sales of $189 million in the nine months ended September 30, 2006 and 2005, respectively.
(c)	Based on number of meters.
(d)	Estimated market share is based on the number of customers that have choice.

28

Production, Purchased Power and Delivery Cost Data

	Three Months Ended									Nine Months Ended
	September 30,									September 30,
	2006			2005			Change %			2006			2005			Change %
Fuel, purchased power costs and delivery fees
($ millions):
Nuclear fuel	$	22		$	21			4.8		$	65		$	60			8.3
Lignite/coal		124			121			2.5			353			354			(0.3	)
Total baseload fuel		146			142			2.8			418			414			1.0
Natural gas/oil fuel and purchased power		740			1,194			(38.0	)		1,429			2,446			(41.6	)
Other costs		41			64			(35.9	)		163			197			(17.3	)
Fuel and purchased power costs (a)		927			1,400			(33.8	)		2,010			3,057			(34.2	)
Delivery fees		415			435			(4.6	)		1,065			1,116			(4.6	)
Total	$	1,342		$	1,835			(26.9	)	$	3,075		$	4,173			(26.3	)
Fuel and purchased power costs (which excludes
generation plant operating costs) per MWh:
Nuclear generation	$	4.29		$	4.22			1.7		$	4.25		$	4.20			1.2
Lignite/coal generation (b)	$	11.73		$	11.22			4.5		$	12.11		$	11.71			3.4
Natural gas fuel and purchased power	$	69.87		$	68.32			2.3		$	65.71		$	59.17			11.1
Delivery fee per MWh	$	24.75		$	23.60			4.9		$	25.60		$	23.81			7.5
Production and purchased power volumes (GWh):
Nuclear		5,115			5,099			0.3			15,292			14,146			8.1
Lignite/coal		11,886			11,597			2.5			32,804			32,722			0.3
Total baseload generation		17,001			16,696			1.8			48,096			46,868			2.6
Natural gas-fired generation		1,948			1,682			15.8			3,487			2,947			18.3
Purchased power (a)		8,641			15,798			(45.3	)		18,258			38,397			(52.4	)
Total energy supply		27,590			34,176			(19.3	)		69,841			88,212			(20.8	)
Less line loss and power imbalances		700			277			─			1,514			1,424			6.3
Net energy supply volumes		26,890			33,899			(20.7	)		68,327			86,788			(21.3	)
Baseload capacity factors (%):
Nuclear		101.2	%		100.8	%		0.4			102.0	%		94.2	%		8.3
Lignite/coal		95.8	%		93.2	%		2.8			89.5	%		89.3	%		0.2
Total baseload		97.3	%		95.3	%		2.1			93.1	%		90.7	%		2.6

________________

(a)See Note 1 to Financial Statements for discussion of reporting of trading and ERCOT balancing activity in 2006.

(b)Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.

29

TXU Energy Company’s results in the fourth quarter of 2006 are expected to be impacted by the effects of the retail initiatives described under “Significant Developments in 2006”, principally a charge of approximately $165 million for residential customer appreciation bonuses.

Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005

Operating revenues increased $97 million, or 3%, to $3.1 billion in 2006. Retail electricity revenues increased $219 million, or 11%, to $2.3 billion.

· The retail revenue increase reflected $400 million in higher average pricing. Higher retail prices reflected increases in natural gas prices that resulted in the regulatory-approved price-to-beat rate increase implemented in October 2005 and January 2006.

· The effect of higher retail pricing was partially offset by $181 million in lower retail volumes. Total retail sales volumes declined 9%. Residential and small business volumes fell 11% on a net loss of customers due to competitive activity and lower average consumption per customer. The lower consumption reflected customer efficiency measures in response to prices and warmer weather. Large business market volumes declined 2% as the effect of fewer customers was largely offset by higher average consumption per customer. A change in large business customer mix reflected a continuing strategy to improve margins.

· Retail electricity customer counts at September 30, 2006 declined 6% from September 30, 2005. Total residential and small business customer counts in the historical service territory declined 7% and in all combined territories declined 5%.

Wholesale electricity revenues decreased $311 million to $648 million. The decline was driven by the changes in reporting of wholesale power trading and ERCOT balancing activities described in Note 1 to Financial Statements. These effects were partially offset by higher wholesale sales prices.

Results from risk management and trading activities, which are reported in revenues and include both realized and unrealized (mark-to-market) gains and losses, reflected net gains of $72 million in 2006 and net losses of $116 million in 2005. Because hedging activities are intended to mitigate the risk of commodity price movements on revenues and fuel and purchased power costs, 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 in 2006 included:

Results associated with the long-term hedging program

These results totaled $139 million in unrealized net gains and $30 million in realized net losses and consisted of:

· $132 million in unrealized cash flow hedge ineffectiveness net gains, which includes $127 million in net gains on unsettled positions and $5 million in net gains that represent reversals of previously recorded unrealized net losses on positions settled in the current period;

· $7 million in unrealized mark-to-market net gains on unsettled positions that are not being accounted for as cash flow hedges; and

· $30 million in realized net losses associated with cash flow hedges, including $25 million previously deferred in accumulated other comprehensive income, that partially offset the hedged electricity revenues recognized in the current period.

Results associated with other risk management and trading activities

· $15 million in unrealized net losses that represent reversals of previously recorded unrealized net gains on physical power positions (which were economic hedges marked-to-market) that were settled in the current period and reported in electricity revenues and fuel and purchased power costs;

· $14 million in realized net losses associated with hedges entered into in prior years (largely 2003), including $10 million related to cash flow hedges previously deferred in accumulated other comprehensive income, that partially offset the hedged electricity revenues recognized in the current period;

· $11 million in unrealized net losses primarily relating to economic hedge positions that are marked-to-market; and

· $7 million in unrealized net gains on various commodity trading positions, primarily natural gas.

30

Gross Margin

	Three Months Ended September 30,
	2006		% of Revenue			2005		% of Revenue
Operating revenues	$	3,091		100	%	$	2,994		100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,342		43			1,835		61
Generation plant operating costs		142		5			151		5
Depreciation and amortization		80		3			77		3
Gross margin	$	1,527		49	%	$	931		31	%

Gross margin is considered a key operating metric as its changes measure the effect of movements in sales volumes and pricing versus the variable and fixed costs to generate, purchase and deliver energy.

Gross margin increased $596 million, or 64%, to $1.5 billion in 2006. The gross margin increase reflected the regulatory-approved price-to-beat increase implemented in October 2005 and January 2006, $139 million in unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of positions in the long-term hedging program and improved productivity of the baseload generation plants. The gross margin performance was tempered by the effects of lower retail sales volumes and higher purchased power prices.

Gross margin as a percent of revenues increased 18 percentage points to 49%. The improvement reflected the following estimated effects:

· higher average pricing, as the average retail sales price per MWh rose 21% and the average wholesale sales price per MWh rose 3% (7 percentage point margin increase);

· the effect of reporting wholesale power trading activity on a net basis (5 percentage point margin increase);

· the effect of unrealized cash flow hedge ineffectiveness and mark-to-market gains related to the long-term hedge program (2 percentage point margin increase); and

· improved baseload generation plant productivity (1 percentage point margin increase).

Fuel, purchased power costs and delivery fees declined $493 million, or 27%, to $1.3 billion reflecting the reporting of wholesale trading activity on a net basis as discussed in Note 1 to the Financial Statements, as well as the decline in retail sales volumes and improved baseload generation plant productivity.

Operating costs decreased $9 million, or 6%, to $142 million in 2006. The decrease reflected:

· $8 million in lower maintenance expense, including amounts related to outages, due to timing of projects; and

· $2 million in savings from staff reductions.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) increased $4 million, or 5%, to $82 million reflecting higher expense associated with mining reclamation obligations and rail spur capital lease amortization, partially offset by $4 million in lower depreciation due to the impairment of natural gas-fired generation plants in the second quarter of 2006.

31

SG&A expenses decreased $2 million, or 1%, to $137 million in 2006. The decrease reflected:

· $4 million in lower marketing expenses due to timing of activities;

· $3 million benefit from cost reduction initiatives;

· $2 million in lower expenses related to stock-based incentive compensation and a deferred compensation plan; and

· $2 million in lower consulting fees related to various strategic initiatives,

partially offset by:

· $5 million in higher bad debt expense reflecting higher retail accounts receivable balances due to higher prices and the effects of a regulatory-mandated deferred payment arrangement and disconnect moratorium applicable to certain retail customers; and

· $5 million in higher fees related to the sale of accounts receivable program due to higher interest rates.

Franchise and revenue-based taxes increased by $4 million, or 15%, to $31 million reflecting higher state gross receipts taxes due to higher revenues.

Other income totaled $9 million in 2006 and $19 million in 2005. Other deductions totaled $4 million in 2006 and $6 million in 2005. See Note 11 to Financial Statements for detail of other income and deductions.

Interest income increased by $40 million to $61 million in 2006 reflecting $26 million due to higher average advances to affiliates and $14 million due to higher average rates.

Interest expense and related charges increased by $6 million, or 6%, to $108 million in 2006 reflecting $9 million in higher average rates, partially offset by $3 million of higher capitalized interest.

Income tax expense on income from continuing operations totaled $431 million in 2006 compared to $237 million in 2005. The effective tax rate was 32.8% in 2006 compared to 34.1% in 2005. The decrease in the effective tax rate reflects increased estimated tax benefits related to lignite depletion and the production deduction.

Income from continuing operations increased $425 million, or 93%, to $884 million in 2006 driven by improved gross margin.

32

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Operating revenues increased $478 million, or 7%, to $7.6 billion in 2006. Retail electricity revenues increased $664 million, or 14%, to $5.5 billion.

· The retail revenue increase reflected $1.2 billion in higher average pricing. Higher retail prices reflected increases in natural gas prices that resulted in the regulatory-approved price-to-beat rate increases implemented in May 2005, October 2005 and January 2006.

· The effect of higher retail pricing was partially offset by $537 million in lower retail volumes. Total retail sales volumes declined 11%. Residential and small business volumes fell 10% on a net loss of customers due to competitive activity and lower average consumption per customer. The lower consumption reflected customer efficiency measures in response to prices and warmer weather. Large business market sales volumes declined 15% as the effect of fewer customers was partially offset by higher average consumption per customer. A change in large business customer mix reflected a continuing strategy to improve margins.

· Retail electricity customer counts at September 30, 2006 declined 6% from September 30, 2005. Total residential and small business customer counts in the historical service territory declined 7% and in all combined territories declined 5%.

Wholesale electricity revenues decreased $462 million to $1.6 billion. The decline was driven by the changes in reporting of wholesale power trading and ERCOT balancing activities described in Note 1 to Financial Statements. These effects were partially offset by higher wholesale sales prices.

Results from risk management and trading activities, which are reported in revenues and include both realized and unrealized (mark-to-market) gains and losses, reflected net gains of $134 million in 2006 and net losses of $122 million in 2005. Because hedging activities are intended to mitigate the risk of commodity price movements on revenues and fuel and purchased power costs, 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 in 2006 included:

Results associated with the long-term hedging program

These results totaled $264 million in unrealized net gains and consisted of:

· $257 million in unrealized cash flow hedge ineffectiveness net gains, which includes $262 million in net gains on unsettled positions and $5 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period; and

· $7 million in unrealized mark-to-market net gains on unsettled positions that are not being accounted for as cash flow hedges.

Results associated with other risk management and trading activities

· $46 million in unrealized net losses that represent reversals of previously recorded unrealized net gains on physical power positions (which were economic hedges marked-to-market) that were settled in the current period and reported in electricity revenues and fuel and purchased power costs;

· $57 million in realized net losses associated with hedges entered into in prior years (largely 2003), including $24 million related to cash flow hedges previously deferred in accumulated other comprehensive income, that partially offset the hedged electricity revenues recognized in the current period;

· $29 million in unrealized cash flow hedge ineffectiveness net gains, which includes $17 million in net gains that represent reversals of previously recorded unrealized net losses on positions (largely the 2003 hedges) settled in the current period;

· $38 million in unrealized net losses primarily relating to economic hedge positions that are marked-to-market;

· $84 million in realized net losses on settlement of economic hedge positions that partially offset the hedged electricity revenues recognized in the current period; and

· $70 million in unrealized net gains that represent reversals of previously recorded net unrealized losses on positions settled in the current period, primarily the economic hedges referred to immediately above.

33

Gross Margin

	Nine Months Ended September 30,
	2006		% of Revenue			2005		% of Revenue
Operating revenues	$	7,569		100	%	$	7,091		100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		3,075		41			4,173		59
Generation plant operating costs		447		6			482		7
Depreciation and amortization		246		3			231		3
Gross margin	$	3,801		50	%	$	2,205		31	%

Gross margin increased $1.6 billion, or 72%, to $3.8 billion in 2006. The gross margin increase reflected the regulatory-approved price-to-beat increases implemented in May 2005, October 2005 and January 2006, $264 million in unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of positions in the long-term hedging program and improved productivity of the baseload generation plants. The gross margin performance was tempered by the effects of lower retail sales volumes and higher purchased power prices.

Gross margin as a percent of revenues increased 19 percentage points to 50%. The improvement reflected the following estimated effects:

· higher pricing, as the average retail sales price per MWh rose 28% and the average wholesale sales price per MWh rose 16% (9 percentage point margin increase);

· the effect of reporting wholesale power trading activity on a net basis (6 percentage point margin increase); and

· the effect of unrealized cash flow hedge ineffectiveness and mark-to-market gains related to the long-term hedge program (2 percentage point margin increase); and

· improved baseload generation plant productivity (1 percentage point margin increase),

partially offset by lower retail sales volumes (1 percentage point margin decrease).

Fuel, purchased power costs and delivery fees declined $1.1 billion, or 26%, to $3.1 billion reflecting the reporting of wholesale trading activity on a net basis as discussed in Note 1 to the Financial Statements, as well as the decline in retail sales volumes and improved baseload generation plant productivity.

Operating costs decreased $35 million, or 7%, to $447 million in 2006. The decrease reflected:

· $32 million in lower maintenance costs reflecting costs incurred for the spring 2005 nuclear generation plant refueling outage and the timing of other maintenance projects;

· $6 million in lower incentive compensation expense; and

· $7 million in severance and early retirement costs associated with generation outsourcing services agreements entered into in early 2006.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) increased $17 million, or 7%, to $251 million reflecting higher expense associated with mining reclamation obligations and rail spur capital lease amortization, partially offset by $4 million in lower depreciation due to the impairment of natural gas-fired generation plants in the second quarter of 2006.

34

SG&A expenses increased by $16 million, or 4%, to $383 million in 2006. The increase reflected:

· $15 million in higher bad debt expense reflecting higher retail accounts receivable balances due to higher prices and the effect of a regulatory-mandated deferred payment arrangement and disconnect moratorium applicable to certain retail customers;

· $13 million in higher fees related to the sale of accounts receivable program due to higher interest rates; and

· $6 million in executive severance expense (including amounts allocated from parent),

partially offset by:

· $9 million in lower consulting fees primarily reflecting expenses in 2005 for the development and implementation of the TXU Operating System to improve productivity;

· $6 million in lower stock-based incentive compensation and deferred compensation expenses; and

· $4 million in lower marketing expenses due to timing of activities.

Franchise and revenue-based taxes increased $7 million, or 9%, to $84 million reflecting higher state gross receipts taxes due to higher revenues.

Other income totaled $11 million in 2006 and $28 million in 2005. Other deductions totaled $198 million in 2006 and $19 million in 2005. See Note 11 to Financial Statements for detail of other income and deductions.

Interest income increased by $95 million to $137 million in 2006 reflecting $61 million due to higher average advances to affiliates and $34 million due to higher average rates.

Interest expense and related charges increased by $23 million, or 8%, to $310 million in 2006. The increase reflects higher average interest rates of $21 million, partially offset by higher capitalized interest of $10 million and higher average borrowings of $12 million.

Income tax expense on income from continuing operations totaled $1.0 billion in 2006 compared to $515 million in 2005. The effective tax rate was 34.4% in 2006 compared to 33.8% in 2005. The 2006 amount included a charge of $41 million (a 1.4 percentage point effective tax rate impact) representing an adjustment to deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 4 to the Financial Statements. The 2005 amount reflected a charge of $10 million (a 0.6 percentage point effective tax rate impact) related to the settlement of the IRS audit for the 1994 to 1996 years.

Income from continuing operations increased $940 million, or 93%, to $1.9 billion in 2006 driven by improved gross margin, partially offset by the charge for the write-down of the natural gas-fired generation plants.

35

Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes incommodity contract assets and liabilities for the nine months ended September 30, 2006. The net changes in these assets and liabilities, excluding “other activity” as described below, represent the net effect of mark-to-market accounting for positions in the commodity contract portfolio, which excludes positions that are subject to cash flow hedge accounting. For the nine months ended September 30, 2006, this effect totaled $1 million in unrealized net gains, which represented reversals of net losses recognized in prior periods on positions settled in the current period. These positions represent both economic hedging and proprietary trading activities.

	Nine Months
	Ended
	September 30, 2006
Commodity contract net liability at beginning of period	$	(56	)
Settlements of positions included in the opening balance (1)		1
Unrealized mark-to-market valuations of positions held at end of period		─
Other activity (2)		(16	)
Commodity contract net liability at end of period	$	(71	)

 __________________________

(1) Represents reversals of unrealized mark-to-market valuations of these positions recognized in earnings prior to the beginning of the period, to offset gains and losses realized upon settlement of the positions in the current period.

(2) These amounts do not arise from mark-to-market activities. Includes initial values of positions involving the receipt or payment of cash or other consideration such as option premiums paid and received and related amortization. Activity for the period includes $24 million of natural gas received related to physical swap transactions as well as $8 million of option premium payments.

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 gains and losses associated with commodity-related cash flow hedges. These effects, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are reflected in the balance sheet as changes in cash flow hedge and other derivative assets and liabilities. The total net effect of recording unrealized gains and losses related to commodity contracts under SFAS 133 is summarized as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006		2005			2006		2005
Unrealized gains (losses) related to contracts marked-to-market	$	3	$	(107	)	$	1	$	(95	)
Ineffectiveness gains related to cash flow hedges (a)		136		2			286		8
Total unrealized gains (losses) related to commodity contracts	$	139	$	(105	)	$	287	$	(87	)

__________________________

(a) See Note 10 to Financial Statements.

These amounts are reported in the “risk management and trading activities” component of revenues.

36

Maturity Table — Of the commodity contract net liability of $71 million at September 30, 2006, the amount representing cumulative unrealized mark-to-market net gains that have been recognized in current and prior years’ earnings totaled $38 million. The remaining net liability of $109 million is comprised principally of amounts representing current and prior years’ net receipts of cash or other consideration, including $102 million related to natural gas physical swap transactions, as well as option premiums net of amortization. The following table presents the unrealized net commodity contract liability arising from mark-to-market accounting as of September 30, 2006, scheduled by contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract net assets (liabilities) at September 30, 2006
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	13		$	18		$	7		$	(2	)	$	36
Prices provided by other
external sources		(65	)		2			(8	)		1			(70	)
Prices based on models		43			29			─			─			72
Total	$	(9	)	$	49		$	(1	)	$	(1	)	$	38
Percentage of total fair value		(23	)%		129	%		(3	)%		(3	)%		100	%

As the above table indicates, 106% of the net asset from unrealized mark-to-market valuations as of September 30, 2006 mature within three years. This is reflective of the terms of the positions and the methodologies employed in valuing positions for periods where there is less market liquidity and visibility. The “prices actively quoted” category reflects only exchange traded contracts with active quotes available. The “prices provided by other external sources” category represents forward commodity positions at locations for which over-the-counter broker quotes are available. Over-the-counter quotes for power in ERCOT generally extend through 2010 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange 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.

37

COMPREHENSIVE INCOME

Cash flow hedge activity reported in other comprehensive income from continuing operations consisted of (all amounts after-tax):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
Net increase (decrease) in fair value of cash flow hedges (all commodity) held at end of period	$	342	$	(71	)	$	381	$	(58	)
Derivative value net losses reported in net income that relate to hedged transaction recognized in the period:
Commodities		9		14			16		47
Financing - interest rate swaps		2		3			5		5
		11		17			21		52
Total income (loss) effect of cash flow hedges reported in other comprehensive income related to continuing operations	$	353	$	(54	)	$	402	$	(6	)

TXU Energy Company has historically used, and expects to continue to use, derivative instruments that are effective in offsetting future cash flow variability 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 open 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, unless the hedged transactions become probable of not occurring at which time the value would be reported in net income. The effects of the hedge (accumulated gain or loss) will be reported in net income as the hedged transactions are actually recognized in net income.

See Note 10 to Financial Statements.

38

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows— Cash flows provided by operating activities for the nine months ended September 30, 2006 totaled $3.9 billion for an increase of $2.6 billion over the nine months ended September 30, 2005. The improvement reflected:

· higher operating earnings after taking into account noncash items such as depreciation, deferred income tax expense, the generation plant impairment charge and the net effect of unrealized mark-to-market valuations;

· a favorable change of $1.2 billion in the federal income tax liability to TXU Corp. due to an increase in the 2006 income tax liability resulting from higher taxable earnings and a tax refund received in 2006 related to 2005 reflecting a market value tax loss related to a power sales agreement (approximately $500 million in income taxes related to 2006 taxable earnings is expected to be paid largely in the first quarter of 2007); and

· a favorable change of $415 million in net margin deposits, primarily reflecting amounts received from counterparties related to natural gas positions in the long-term hedging program.

Cash flows used in financing activities increased $1.2 billion as summarized below:

	Nine Months Ended September 30,
	2006			2005
Net repayments, repurchases and issuances of borrowings	$	(609	)	$	236
Decrease in note payable to TXU Electric Delivery		(31	)		(40	)
Distributions paid to parent		(858	)		(525	)
Excess tax benefits on stock-based incentive compensation		13			7
Total	$	(1,485	)	$	(322	)

Cash flows used in investing activities increased $1.6 billion as summarized below:

	Nine Months Ended September 30,
	2006			2005
Advances to affiliates	$	(1,864	)	$	(661	)
Capital expenditures, including nuclear fuel		(488	)		(246	)
Proceeds from sale of assets		11			36
Deposit of proceeds from pollution control revenue bonds with trustee		(99	)		―
Net investments in nuclear decommissioning trust fund securities		(12	)		(11	)
Other		2			2
Total	$	(2,450	)	$	(880	)

Capital expenditures in 2006 include approximately $127 million of spending related to TXU DevCo's generation development program, which is expected to be reimbursed by TXU DevCo in 2007 following the closing of TXU DevCo's related financing and the issuance of applicable air permits.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $51 million for 2006. This difference represents amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice.

39

Long-term Debt Activity —During the first nine months of 2006, TXU Energy Company issued or made scheduled principal payments on long-term debt as follows (all amounts presented are principal):

	Issuances		Retirements and Repurchases
Pollution control revenue bonds	$	100	$	203
Senior notes		―		400
Other long-term debt		―		2
Total	$	100	$	605

 See Note 6 to Financial Statements for further detail of debt issuances, repurchases and retirements and financing arrangements.

Credit Facilities— At October 23, 2006, TXU Energy Company, jointly with TXU Electric Delivery, had access to credit facilities totaling $6.5 billion of which $5.3 billion was unused. The facilities expire on various dates between May 2007 and June 2010. TXU Energy Company can directly access the maximum $6.5 billion under the facilities. These credit facilities are used for working capital and general corporate purposes including providing support for issuances of commercial paper and for issuing letters of credit. See Note 6 to Financial Statements for details of the arrangements.

Capital Expenditures — Capital expenditures related to TXU Energy Company's facilities for 2006 are expected to total approximately $480 million primarily for maintenance and upgrades of generation assets.

Short-term Borrowings — At October 23, 2006, TXU Energy Company had $464 million of commercial paper outstanding and $295 million of borrowings under the credit facilities. The commercial paper funds short-term liquidity requirements.

Sale of Accounts Receivable — TXU Energy Company participates in an accounts receivable securitization program established by TXU Corp. for certain of its subsidiaries, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of TXU Energy Company 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 TXU Energy Company are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding to TXU Energy Company under the program totaled $626 million at September 30, 2006 and $582 million at December 31, 2005. See Note 5 to Financial Statements for a more complete description of the program including the impact on the financial statements for the periods presented and the contingencies that could result upon the termination of the program.

Liquidity Effects of Risk Management and Trading Activities — As of September 30, 2006, TXU Energy Company has received/posted cash and letters of credit for margin requirements, miscellaneous credit support or as otherwise required by a counterparty as follows:

· $669 million in cash has been received related to daily margin settled transactions primarily associated with positions in the long-term hedging program;

· $52 million in cash has been received from counterparties as collateral;

· $30 million in cash has been posted with counterparties as collateral; and

· $449 million in letters of credit have been posted as collateral.

With respect to collateral received, TXU Energy Company has the contractual right, but not the obligation, to request collateral from certain counterparties based on the value of the contract and the credit worthiness of the counterparty. This collateral is typically held by TXU Energy Company in the form of cash or letters of credit. Collateral received in cash is used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities. Unless otherwise specified in the contract, counterparties may generally elect to substitute posted cash collateral with letters of credit, reducing TXU Energy Company’s liquidity.

40

With respect to positions under the long-term hedging program as of October 23, 2006, for each $1.00 per MMBtu increase in natural gas prices, TXU Energy Company could be required to post up to approximately $1 billion in additional collateral and/or financial margining. Transactions requiring daily margining account for approximately 52% of the long-term hedge positions and are generally met by cash postings. For the remainder, collateral settlements are being met by a combination of the Big Brown Lien, letters of credit and cash postings as required periodically by counterparties.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain financing arrangements of TXU Energy Company contain financial covenants that require maintenance of specified fixed charge coverage ratios and leverage ratios and/or contain minimum net worth covenants. As of September 30, 2006, TXU Energy Company was in compliance with all such applicable covenants.

Credit Ratings

Current credit ratings for TXU Corp. and certain of its subsidiaries are presented below:

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

Moody’s currently maintains a stable outlook for TXU Corp., US Holdings, TXU Energy Company and TXU Electric Delivery. Fitch’s outlook is negative for TXU Corp., US Holdings and TXU Energy Company and stable for TXU Electric Delivery. S&P’s outlook is negative for TXU Corp., US Holdings, TXU Energy Company and TXU Electric Delivery. These ratings are investment grade, except for Moody’s and S&P’s rating of TXU Corp.’s senior unsecured debt and S&P’s rating of US Holdings’ senior unsecured debt, which are one notch below investment grade.

Commercial paper issued by TXU Energy Company and TXU Electric Delivery is rated P2 by Moody’s and F2 by Fitch and has not been rated by S&P.

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.

Material Credit Rating Covenants

TXU Energy Company has provided a guarantee of the obligations under TXU Corp.’s lease of its headquarters building. In the event of a downgrade of TXU Energy Company’s credit rating to below investment grade, a letter of credit of approximately $99 million at September 30, 2006 would need to be provided within 30 days of any such rating decline.

Under the terms of a rail car lease with $51 million in remaining lease payments (principal amount as of September 30, 2006), if TXU Energy Company’s credit rating were downgraded to below investment grade by any specified rating agency, TXU Energy Company could be required to sell the interest in the lease, assign the lease to a new obligor that is investment grade, post a letter of credit or defease the lease.

TXU Energy Company has entered into certain commodity contracts that in some instances give the other party the right, but not the obligation, to request TXU Energy Company to post collateral in the event that its credit rating falls below investment grade. Based on its commodity contract positions at September 30, 2006, in the event TXU Energy Company were downgraded to one level below investment grade by specified rating agencies, counterparties would have the option, based on reduced credit thresholds, to request TXU Energy Company to post up to $113 million in additional collateral requirements. Should TXU Energy Company be downgraded two levels below investment grade, counterparties would have the option to request additional collateral of up to approximately $36 million. The amount TXU Energy Company could be required to post under these transactions depends in part on the value of the contracts at the time of any downgrade.

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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 TXU Energy Company’s credit rating were downgraded to below investment grade by any specified rating agency, TXU Energy Company could be required to post collateral of approximately $25 million as of September 30, 2006.

Additionally, a downgrade of TXU Energy Company’s credit rating to below investment grade could result in approximately $8 million of cash collateral held by TXU Energy Company becoming restricted cash.

The adverse liquidity effect in the event of a downgrade of TXU Energy Company’s credit rating to one level below investment grade as discussed above totals $296 million at September 30, 2006. There could be an additional $36 million (totaling $332 million) adverse liquidity effect in the event of a downgrade to two levels below investment grade as discussed above.

Other arrangements of TXU Energy Company, including credit facilities and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on credit ratings of TXU Energy Company.

Material Cross Default Provisions

Certain financing arrangements contain provisions that may 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 may result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.

A default by TXU Energy Company or TXU Electric Delivery or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross default under joint credit facilities totaling $4.5 billion. Under these credit facilities, a default by TXU Energy Company or any subsidiary thereof may cause the maturity of outstanding balances ($1.2 billion at September 30, 2006) under such facility to be accelerated as to TXU Energy Company but not as to TXU Electric Delivery. Also, under these credit facilities, a default by TXU Electric Delivery or any subsidiary thereof may cause the maturity of outstanding balances (none as of September 30, 2006) under such facility to be accelerated as to TXU Electric Delivery but not as to TXU Energy Company.

In addition, a default by TXU Energy Company or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross-default under its 364-day credit facility totaling $1.5 billion and may cause the maturity of outstanding balances (none as of September 30, 2006) under such facility to be accelerated.

The accounts receivable securitization 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 Company each have a cross default threshold of $50 thousand. If either an originator, TXU Business Services Company or TXU Receivables Company defaults on indebtedness of the applicable threshold, the facility could terminate.

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

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

Long-termContractual Obligations and Commitments — TXU Energy Company’s contractual cash obligations under commodity purchase agreements have increased since December 31, 2005, as disclosed in the 2005 Form 10-K. Obligations in the one to three year period increased $653 million and in the more than five year period increased $311 million.

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OFF BALANCE SHEET ARRANGEMENTS

Subsidiaries ofTXU Energy Company participate in an accounts receivable securitization program. See discussion above under “Sale of Accounts Receivable” and in Note 5 to Financial Statements.

Also see Note 8 to Financial Statements regarding guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 8 to Financial Statements for discussion of commitments and contingencies.

REGULATION AND RATES

Wholesale Market Activity Investigation — See Note 8 to Financial Statements for discussion.

Retail Product Service Offerings — During 2006, TXU Energy Company’s retail electricity business has launched several nonprice-to-beat competitive product service offerings. The offerings contain varying terms such as guaranteed pricing for fixed contract periods, variable rates indexed to market natural gas rates, time-of-use rates and several renewable power options.

Price-to-Beat Inquiry — In December 2005, the Commission staff issued an extensive list of questions regarding the price-to-beat rate mechanism, including transition away from the price-to-beat rate on January 1, 2007. TXU Energy Company was instrumental in forming a coalition (the retail market coalition) including almost all of the major REPs in Texas. The retail market coalition drafted and submitted comments to the Commission detailing the public policy and legal reasons that the price-to-beat rate-setting methodology should remain unchanged through 2006 and then expire as scheduled on January 1, 2007. However, other parties submitted proposals to the Commission seeking changes to the price-to-beat rule, and the Chairman of the Commission proposed sweeping reforms to the rule, including a price-to-beat rate reset effective in December 2006. Although the Commission ultimately voted not to propose a price-to-beat rate reset, it did publish for comment certain proposed price-to-beat rule revisions, including proposed mandatory bill inserts and a proposed requirement that the incumbent REPs provide lists of their price-to-beat rate customers to competitors. TXU Energy Company and certain members of the retail market coalition oppose these proposed revisions. While it remains possible for the Commission to change the rules before the end of the year, the likelihood of such changes continues to diminish substantially with the passage of time. Although certain Texas legislators asked the Governor to open the Texas Legislature’s special session to the issue of electricity prices, the session closed with no changes to the market structure or the price-to-beat statute.

Provider of Last Resort Rule— In June 2006, the Commission approved a revised Provider Of Last Resort (POLR) rule which will become fully effective in January 2007. The rule modifies the existing POLR price structure and creates a rate no longer tied to the price-to-beat rate. Importantly, the newly adopted POLR price structure is designed to compensate POLR providers for the costs and risks associated with providing POLR service and also contains a POLR price floor designed to prevent the POLR price from interfering with competitive market prices.

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Disconnect Rulemaking— In late June 2006, the Office of Public Utility Counsel and other groups filed a petition asking the Commission to adopt an emergency rule that would bar disconnection of electric service to residential customers during the 2006 summer months. The Commission adopted such a rule on July 21, 2006, which became effective immediately. The new rule requires the following for residential customers:

· For customers who have been designated as “critical care” because interruption or suspension of electric service will create a dangerous or life-threatening condition, there shall be no disconnection through September 30, 2006, regardless of whether the customer makes payments for electricity use;

· With respect to elderly low-income customers who contacted their electric provider, disconnection was also prohibited through September 30, 2006, regardless of whether the customer made payments for electricity use. The Commission did encourage customers to pay as much as they could to avoid building up significant unpaid balances. These customers were entitled to enter into a deferred payment arrangement with 25% of their balance due in October and the balance of the deferred bills to be paid over the next five months; and

· All other low-income customers were able to avoid disconnection through September 30, 2006 by paying 25% of their current month’s bill and entering into a deferred payment arrangement that spread remaining amounts over the next five months. In each of July, August and September 2006, the customer was able to avoid disconnection by paying 25% of that particular month’s bill and also paying the deferral installment that is due for that month.

These actions have resulted in an increase to bad debt expense, but the amounts have not been material to TXU Corp.’s results.

Texas Legislative Special Session— The 79^th Texas Legislature completed its 3^rd special session in May 2006. The session resulted in a reform to the Texas franchise tax system and the enactment of a property tax relief law.

The Texas franchise tax system is being replaced with a new tax system, referred to as the Texas margin tax. The Texas margin tax is a significant change in Texas tax law because it generally makes all legal entities subject to tax, including general and limited partnerships, while the current franchise tax system applies only to corporations and limited liability companies. TXU Energy Company’s subsidiaries conduct significant operations through Texas limited partnerships that will become subject to the new Texas margin tax. The effective date of the Texas margin tax is January 1, 2008 for calendar year-end companies and the computation of tax liability will be based on 2007 revenues as reduced by certain deductions. The new margin tax is expected to increase TXU Energy Company’s annual state franchise tax expense by approximately $40 million beginning in 2007. Also see Note 4 to Financial Statements.

The property tax relief law is expected to reduce school taxes assessed to TXU Energy Company by an estimated $5 million in 2006 and $21 million annually in 2007 and subsequent years (based on current property values and without regard to any property additions).

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Wholesale Market Design—In August 2003, the Commission adopted a rule that, when implemented, will 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).

The Commission has determined that ERCOT will implement a market design that utilizes nodal pricing for resources. In light of this decision, ERCOT filed a set of Nodal Protocols for Commission approval that describes the operation of an ERCOT wholesale nodal market design. The Commission approved the Nodal Protocols in March 2006 and set an implementation date of no later than January 1, 2009. In May 2006, ERCOT filed an Application and Request for Interim Relief, seeking approval of a nodal surcharge imposed on all Qualified Scheduling Entities in ERCOT (including subsidiaries of TXU Energy Company) for the purpose of financing approximately 38% of ERCOT’s expected nodal implementation cost. Additionally, ERCOT requested that an interim nodal surcharge be made effective as soon as possible in the amount of $0.0663 per MWh, subject to ERCOT’s providing an updated project implementation cost estimate in mid-September and subsequent Commission approval. The Commission adopted an interim order approving ERCOT’s surcharge application on August 28, 2006, with the surcharge taking effect on October 1, 2006. ERCOT’s current nodal project timeline shows the start of the nodal real-time market to be December 1, 2008, followed by day-ahead market startup on December 8, 2008. TXU Energy Company expects that the annual impact of the surcharge will be approximately $3 million to $4 million in additional expense; however, TXU Energy Company is unable to predict the ultimate impact of the proposed nodal wholesale market design on its operations or financial results.

2007 Texas Legislative Session — The Texas Legislature will convene in its regular biennial session beginning January 9, 2007. This session is not a “sunset” session for the Commission, so there is no requirement that the Legislature consider any electric-industry-related bills. However, public statements by key legislators, including the current Chairman of the House Committee on Regulated Industries, which has jurisdiction over electric-industry issues, indicate a high likelihood that various measures pertaining to the electric industry will be considered. Potential measures that could be introduced and debated or voted upon include initiatives that could affect the competitive framework of the retail electricity market, encourage energy conservation, restore state funding for the low-income customer discount under the “system benefit fund” mechanism, encourage construction of new infrastructure, or enhance customer education regarding the market. TXU Energy Company supports continued development of a fully competitive wholesale and retail power market and will actively monitor and provide input regarding legislation that could be material to the electric industry. TXU Energy Company is unable to predict the outcome of the 2007 legislative process or its effect, if any, on its ongoing business.

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

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to Financial Statements for a discussion of changes in accounting standards.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Market risk is the risk that TXU Energy Company may experience a loss in value as a result of changes in market conditions affecting commodity prices and interest rates, which TXU Energy Company is exposed to in the ordinary course of business. TXU Energy Company’s exposure to market risk is affected by a number of factors, including the size, duration and composition of its energy and financial portfolio, as well as the volatility and liquidity of markets. TXU Energy Company enters into instruments such as interest rate swaps to manage interest rate risks related to its indebtedness, as well as exchange traded, over-the-counter contracts and other contractual commitments to manage commodity price risk as part of its wholesale activities.

RISK OVERSIGHT

TXU Energy Company’s wholesale business manages the market, credit and operational risk related to commodity prices of the unregulated energy business within limitations established by senior management and in accordance with TXU Corp.’s overall risk management policies. Interest rate risks are managed centrally by the corporate treasury function. Market risks are monitored daily by risk management groups that operate and report independently of the wholesale commercial operations, utilizing industry accepted practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (VaR) methodologies.

TXU Corp. has a corporate risk management organization that is headed by a Chief Risk Officer. The Chief Risk Officer, through his designees, enforces all applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in the various businesses of TXU Energy Company and their associated transactions. Key risk control activities include, but are not limited to, credit review and approval, operational and market risk measurement, validation of transaction capture, portfolio valuation and daily portfolio reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

COMMODITY PRICE RISK

TXU Energy Company’s businesses are subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products they market or purchase. TXU Energy Company’s businesses actively manage their portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. These businesses, similar to other participants in the market, cannot fully manage the long-term value impact of structural declines or increases in natural gas, power and oil prices and spark spreads (differences between the market price of electricity and its cost of production).

In managing energy price risk, subsidiaries of TXU Energy Company enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities in the wholesale operations include hedging, the structuring of long-term contractual arrangements and proprietary trading. The wholesale business continuously monitors the valuation of identified risks and adjusts the portfolio based on current market conditions. Valuation adjustments or reserves are established in recognition that certain risks exist until full delivery of energy has occurred, counterparties have fulfilled their financial commitments and related contracts have either matured or are closed out. TXU Energy Company strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

Long-term Hedging Program— See discussion above under “Significant Developments in 2006” for an update of the program, including potential effects on reported results.

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VaR Methodology— A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio’s potential for loss given a specified confidence level and considers among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities. Stress testing of market variables is also conducted to simulate and address abnormal market conditions.

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

TXU Energy Company regularly reviews its risk analysis metrics. In the course of this review, it was determined that the Cash Flow at Risk metric is not a meaningful measure of actionable commodity price risk. Other metrics that measure the effect of such risk on the value of its mark-to-market contract portfolio and earnings continue to be disclosed. TXU Energy Company may add or eliminate other metrics in the future in its disclosures of risks.

In a review of the holding period for VaR calculations, TXU Energy Company determined that a holding period of five to 60 days, instead of the five-day holding period previously assumed, would be more reflective of the time it would take to liquidate the portfolio, considering the increase in longer-dated positions (principally related to the long-term hedging program) and the associated liquidity effects.

VaR for Energy Contracts Subject to Mark-to-Market Accounting — This measurement estimates the potential loss in economic value, due to changes in market conditions, of all energy-related contracts subject to mark-to-market accounting (excluding those accounted for as cash flow hedges), based on a specific confidence level and an assumed holding period. A 95% confidence level is assumed in determining this VaR.

	September 30, 2006				December 31, 2005
	Five to 60 day holding period		Five-day holding period		Five-day holding period
Period-end MtM VaR	$	246	$	77	$	19
Average Month-end MtM VaR	$	48	$	21	$	20

VaR Earnings at Risk (EaR) — This measurement estimates the potential reduction of expected pretax earnings for the year presented, due to changes in market conditions, of all energy-related contracts subject to mark-to-market accounting and positions not marked-to-market in net income that are expected to be settled within the fiscal year (for example margin from generation activity and retail load). For this purpose, cash flow hedges are included with transactions that are not marked-to-market in net income. A 95% confidence level is assumed in determining this EaR.

	September 30, 2006				December 31, 2005
	Five to 60 day holding period		Five-day holding period		Five-day holding period
EaR	$	241	$	72	$	32

The increases in the five-day holding period risk measures (MtM VaR and EaR) above are driven by the significant increase in number of positions in the long-term hedging program.

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INTEREST RATE RISK

See Note 6 to Financial Statements for a discussion of debt-related activity since December 31, 2005.

CREDIT RISK

Credit Risk — Credit risk relates to the risk of loss associated with nonperformance by counterparties. TXU Energy Company and its subsidiaries maintain credit risk policies with regard to their 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 master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. TXU Energy Company has standardized documented processes for monitoring and managing credit exposure of its businesses 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 for TXU Energy Company or its subsidiaries. Additionally, TXU Energy Company 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 — TXU Energy Company’s gross exposure to credit risk, which totaled approximately $2.2 billion at September 30, 2006, represents trade accounts receivable as well as net asset positions arising from hedging and trading activities.

Gross assets subject to credit risk includes $848 million in accounts receivable from the retail sale of electricity to residential and small business customers. The risk of material loss (after consideration of allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience and market or operational conditions.

Most of the remaining trade accounts receivable is with large business retail customers and wholesale counterparties. These counterparties include major energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of September 30, 2006, the exposure to credit risk from these customers and counterparties totaled $1.3 billion taking into account standardized master netting contracts and agreements described above and $148 million in credit collateral (cash, letters of credit and other security interests) held by TXU Energy Company subsidiaries.

Of this $1.3 billion exposure, 86% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and TXU Energy Company’s internal credit evaluation process. Those customers and counterparties 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. TXU Energy Company routinely monitors and manages its credit exposure to these customers and counterparties on this basis.

TXU Energy Company is also exposed to credit risk related to the Capgemini put option with a carrying value of $103 million. Subject to certain terms and conditions, Cap Gemini North America, Inc. and its parent, Cap Gemini S.A., have guaranteed the performance and payment obligations of Capgemini under the services agreement, as well as the payment in connection with a put option. S&P currently maintains a BB+ rating with a positive for Cap Gemini S. A.

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The following table presents the distribution of credit exposure as of September 30, 2006, for retail trade accounts receivable from large business customers, wholesale trade accounts receivable as well as net asset positions arising from hedging and trading activities, by investment grade and noninvestment grade, credit quality and maturity.

										Net Exposure byMaturity
	Exposure before Credit Collateral			Credit Collateral			Net Exposure			2 years or less		Between 2-5 years		Greater than 5 years		Total
Investment grade	$	1,230		$	64		$	1,166		$	766	$	254	$	146	$	1,166
Noninvestment grade		266			84			182			144		17		21		182
Totals	$	1,496		$	148		$	1,348		$	910	$	271	$	167	$	1,348
Investment grade		82	%		43	%		86	%
Noninvestment grade		18	%		57	%		14	%

Approximately 68% of the net $1.3 billion credit exposure has a maturity date of two years or less. TXU Energy Company does not anticipate any material adverse effect on its financial position or results of operations due to nonperformance by any customer or counterparty.

TXU Energy Company had credit exposure to two counterparties having an exposure greater than 10% of the net exposure of $1.3 billion at September 30, 2006. These two counterparties represented 14% and 12%, respectively, of the net exposure. TXU Energy Company views its exposure with these two counterparties to be within an acceptable level of risk tolerance.

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by TXU Energy Company contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that TXU Energy Company expects or anticipates to occur in the future, including such matters as projections, capital allocation and cash distribution policy, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power production assets, market and industry developments and the growth of TXU Energy Company’s business and operations (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “projection,” “target,” “outlook”), are forward-looking statements. Although TXU Energy Company believes that in making any such forward-looking statement its expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors discussed under “Risk Factors” and the following important factors, among others, that could cause the actual results of TXU Energy Company to differ materially from those projected in such forward-looking statements:

· prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, FERC, the Commission, the RRC, the NRC, the EPA and the TCEQ, with respect to:

·allowed prices;

·industry, market and rate structure;

·purchased power and recovery of investments;

·operations of nuclear generating facilities;

·acquisitions and disposal of assets and facilities;

·development, construction and operation of 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;

·continued implementation of the 1999 Restructuring Legislation;

·legal and administrative proceedings and settlements;

·general industry trends;

·TXU Energy Company’s ability to attract and retain profitable customers;

·delays in implementing any future price-to-beat fuel factor adjustments;

·changes in wholesale electricity prices or energy commodity prices;

·unanticipated changes in market heat rates in the Texas electricity market;

·TXU Energy Company’s ability to effectively hedge against changes in commodity prices and market heat rates;

·weather conditions and other natural phenomena, and acts of sabotage, wars or terrorist activities;

·unanticipated population growth or decline, and changes in market demand and demographic patterns;

·changes in business strategy, development plans or vendor relationships;

·access to adequate transmission facilities to meet changing demands;

·unanticipated changes in interest rates, commodity prices or rates of inflation;

·unanticipated changes in operating expenses, liquidity needs and capital expenditures;

·commercial bank market and capital market conditions;

·competition for new energy development and other business opportunities;

·inability of various counterparties to meet their obligations with respect to TXU Energy Company’s financial instruments;

·changes in technology used by and services offered by TXU Energy Company;

·significant changes in TXU Energy Company’s relationship with its employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;

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·significant changes in critical accounting policies material to TXU Energy Company;

·actions by credit rating agencies; and

·the ability of TXU Energy Company to implement cost reduction initiatives and effectively execute its growth strategy.

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

ITEM 4. CONTROLS AND PROCEDURES

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

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Reference is made to the discussion in Note 8 regarding legal proceedings.

ITEM 1A. RISK FACTORS

Other than risk factors presented below, there have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the 2005 Form 10-K as updated by the risk factors disclosed under the heading “Risk Factors” in Item 1A of the reports on Form 10-Q for the quarterly periods ended March 31, 2006 (March 2006 10-Q) and June 30, 2006 (June 2006 10-Q). The risk factors below update, and should be read in conjunction with, the risk factors disclosed in the 2005 Form 10-K, March 2006 10-Q and June 2006 10-Q.

TXU Corp.’s generation development program is subject to risks that could ultimately impact TXU Energy Company.

TXU Corp’s ability to finance the construction of the new generation facilities is subject to a variety of risks that could ultimately impact TXU Energy Company. The ability to finance the projects on a non-recourse basis is contingent on a number of factors, including the terms of the engineering, procurement and construction contracts, construction costs, capital and bank market conditions as well as the project finance entity’s separateness from TXU Corp. and its other subsidiaries, particularly TXU Energy Company. To the extent TXU Corp. is not able to use non-recourse financing or if the rating agencies attribute a material amount of the project finance debt to TXU Corp.’s credit, the financing of the plants could have a negative impact on the credit ratings of TXU Corp. and its other subsidiaries. While TXU Corp. currently intends to develop and finance the new facilities through TXU DevCo and other development subsidiaries, TXU Corp. could ultimately decide to develop and finance some of the new facilities in TXU Energy Company, which would subject TXU Energy Company to significant capital expenditure requirements and all of the risks inherent in the development of new generation facilities.

TXU Energy Company has made capital expenditures (approximately $127 million), and may continue to make capital expenditures, on behalf of TXU DevCo with an expectation that TXU Energy Holdings will be reimbursed for such amounts once TXU DevCo receives funding under it proposed financing. Reimbursement is expected to occur in 2007 following the closing of TXU DevCo’s proposed financing and the issuance of applicable air permits. While TXU Energy Company expects to be reimbursed for such capital expenditures, there can be no guarantee that TXU Energy Company will ultimately be reimbursed for such capital expenditures.

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ITEM 6.EXHIBITS

(a)Exhibits provided as part of Part II are:
Exhibits	Previously Filed With File Number*	As Exhibit
3(ii)	By-laws.
3(a)			—	Third Amended and Restated Limited Liability Company Agreement of TXU Energy Company LLC, dated as of September 29, 2006.
	Material Contracts.
10(a)	1-12833 Form 10-Q (filed November 9, 2006)	10(d)	—	Deed of Trust, Assignment of Rents, Security Agreement, Financing Statement and Fixture Filing, dated as of August 28, 2006, regarding the Big Brown Lien.
(31)	Rule 13a - 14(a)/15d - 14(a) Certifications.
31(a)			—	Certification of M. S. Greene, Chairman of the Board, President and Chief Executive of TXU Energy Company LLC, pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of David A. Campbell, Manager and Acting Chief Financial Officer of TXU Energy Company LLC, pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32)	Section 1350 Certifications.
32(a)			—	Certification of M. S. Greene, Chairman of the Board, President and Chief Executive of TXU Energy Company LLC, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)			—	Certification of David A. Campbell, Manager and Acting Chief Financial Officer of TXU Energy Company LLC, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99)	Additional Exhibits
99			—	Condensed Statements of Consolidated Income - Twelve Months Ended September 30, 2006.

* Incorporated herein by reference.

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SIGNATURE

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

	TXU ENERGY COMPANY LLC
By:	/s/ Stan Szlauderbach
	Stan Szlauderbach
	Senior Vice President and Controller

Date: November 9, 2006

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