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 JUNE 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 August 8, 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 Six Months Ended June 30, 2006 and 2005	1
Condensed Statements of Consolidated Comprehensive Income - Three and Six Months Ended June 30, 2006 and 2005	2
Condensed Statements of Consolidated Cash Flows - Six Months Ended June 30, 2006 and 2005	3
Condensed Consolidated Balance Sheets - June 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 Holdings’ 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 Holdings 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 47	FIN No. 47, “Accounting for Conditional Asset Retirement Obligations - An Interpretation of FASB Statement No. 143”
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes”
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
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
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)

ii

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
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 109	SFAS No. 109, “Accounting for Income Taxes”
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”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 144	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
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 Holdings, 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 units in Texas. While an affiliate of TXU Energy Holdings, TXU DevCo is not a subsidiary of, or a parent company to, TXU Energy Holdings.

iii

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 Holdings	refers to TXU Energy Company LLC, a subsidiary of US Holdings, and/or its consolidated subsidiaries, depending on context. This Form 10-Q and other SEC filings of TXU Energy Holdings occasionally make references to TXU Energy Holdings when describing actions, rights or obligations of its subsidiaries. These references reflect the fact that the subsidiaries are consolidated with TXU Energy Holdings for financial reporting purposes. However, these references should not be interpreted to imply that TXU Energy Holdings is actually undertaking the action or has the rights or obligations of its subsidiaries.
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 Holdings

iv

PART I. FINANCIAL INFORMATION

Item 1.FINANCIAL STATEMENTS

TXU ENERGY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(millions of dollars)
Operating revenues	$	2,468		$	2,276		$	4,478		$	4,097
Costs and expenses:
Fuel, purchased power costs and delivery fees		943			1,265			1,733			2,338
Operating costs		152			177			307			331
Depreciation and amortization		84			77			169			156
Selling, general and administrative expenses		121			113			242			227
Franchise and revenue-based taxes		27			24			54			50
Other income (Note 11)		(1	)		(6	)		(1	)		(8	)
Other deductions (Note 11)		205			12			195			13
Interest income		(45	)		(11	)		(76	)		(21	)
Interest expense and related charges (Note 13)		102			94			202			185
Total costs and expenses		1,588			1,745			2,825			3,271
Income from continuing operations before income taxes		880			531			1,653			826
Income tax expense		337			186			590			278
Income from continuing operations		543			345			1,063			548
Loss from discontinued operations, net of tax benefit (Note 4)		─			(1	)		─			(4	)
Net income	$	543		$	344		$	1,063		$	544

See Notes to Financial Statements.

1

TXU ENERGY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006		2005
	(millions of dollars)
Components related to continuing operations:
Income from continuing operations	$	543		$	345		$	1,063	$	548
Other comprehensive income:
Minimum pension liability adjustment (net of tax expense of $-, $4, $- and $4)		─			7			─		7
Cash flow hedges:
Net change in fair value of derivatives held at end of period (net of tax benefit (expense) of $39, $1, $(21) and $(7)) (See Note 10)		(74	)		(2	)		39		13
Derivative value net losses related to hedged transactions settled during the period and reported in net income (net of tax benefit of $6, $9, $5 and $19)		12			18			10		35
Total effect of cash flow hedges		(62	)		16			49		48
Comprehensive income from continuing operations		481			368			1,112		603
Comprehensive loss from discontinued operations		─			(1	)		─		(4	)
Comprehensive income	$	481		$	367		$	1,112	$	599

See Notes to Financial Statements.

2

TXU ENERGY COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2006			2005
	(millions of dollars)
Cash flows - operating activities:
Income from continuing operations	$	1,063		$	548
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		202			185
Deferred income taxes and investment tax credits - net		74			54
Impairment of natural gas-fired generation plants		198			─
Inventory write-off related to natural gas-fired generation plants		3			─
Net effect of unrealized mark-to-market valuations		(148	)		(18	)
Credit related to impaired leases		(4	)		(12	)
Change in retail clawback liability		─			(32	)
Charge related to coal contract counterparty claim		─			12
Net equity loss from unconsolidated affiliate		5			3
Stock-based compensation expense		4			6
Bad debt expense		29			19
Changes in operating assets and liabilities		668			(253	)
Cash provided by operating activities from continuing operations		2,094			512
Cash flows - financing activities:
Issuances of long-term debt		100			71
Retirements of debt		(603	)		(40	)
Change in notes payable:
Commercial paper		365			─
Banks		800			950
Decrease in income tax-related note payable to TXU Electric Delivery		(22	)		(32	)
Distribution paid to parent		(572	)		(350	)
Debt premium, discount, financing and reacquisition expenses		(14	)		(12	)
Cash provided by financing activities from continuing operations		54			587
Cash flows - investing activities:
Capital expenditures		(218	)		(135	)
Nuclear fuel		(30	)		(26	)
Proceeds from pollution control revenue bonds deposited with trustee		(99	)		─
Proceeds from sales of nuclear decommissioning trust fund securities		144			95
Investments in nuclear decommissioning trust fund securities		(151	)		(102	)
Advances to affiliates		(1,803	)		(934	)
Other		2			─
Cash used in investing activities from continuing operations		(2,155	)		(1,102	)
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		(7	)		(6	)
Cash and cash equivalents - beginning balance		12			70
Cash and cash equivalents - ending balance	$	5		$	64

See Notes to Financial Statements.

3

TXU ENERGY COMPANY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
	2006			2005
ASSETS	(millions of dollars)
Current assets:
Cash and cash equivalents	$	5		$	12
Restricted cash		3			8
Trade accounts receivable — net		843			1,178
Advances to parent		1,797			694
Note receivable from parent		1,500			1,500
Income taxes receivable from parent		─			361
Inventories		322			309
Commodity contract assets		607			1,603
Cash flow hedge and other derivative assets		86			63
Margin deposits related to commodity positions		70			247
Other current assets		332			244
Total current assets		5,565			6,219
Restricted cash		100			─
Investments		498			501
Advances to parent		700			─
Property, plant and equipment — net		9,839			9,958
Goodwill		517			517
Commodity contract assets		198			338
Cash flow hedge and other derivative assets		307			68
Other noncurrent assets		219			205
Total assets	$	17,943		$	17,806
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Notes payable:
Commercial paper	$	671		$	306
Banks		1,240			440
Long-term debt due currently		1			401
Trade accounts payable - nonaffiliates		683			879
Trade accounts and other payables to affiliates		369			355
Commodity contract liabilities		637			1,481
Cash flow hedge and other derivative liabilities		44			260
Margin deposits related to commodity positions		54			357
Accrued income taxes payable to parent		293			─
Accrued taxes other than income		55			51
Other current liabilities		323			415
Total current liabilities		4,370			4,945
Accumulated deferred income taxes		3,002			2,800
Investment tax credits		319			326
Commodity contract liabilities		234			516
Cash flow hedge and other derivative liabilities		302			44
Notes or other liabilities due affiliates		378			406
Other noncurrent liabilities and deferred credits		942			833
Long-term debt, less amounts due currently (Note 6)		2,949			3,055
Exchangeable preferred membership interests, net of discount ($213 and $222)		537			528
Total liabilities		13,033			13,453
Commitments and contingencies (Note 8)
Membership interests (Note 7):
Capital account		4,982			4,474
Accumulated other comprehensive loss		(72	)		(121	)
Total membership interests		4,910			4,353
Total liabilities and membership interests	$	17,943		$	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 Holdings is a wholly-owned subsidiary of US Holdings, which is a wholly-owned subsidiary of TXU Corp. TXU Energy Holdings 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 Holdings.

Basis of Presentation— The condensed, consolidated financial statements of TXU Energy Holdings 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. 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 dollars unless otherwise indicated.

A realignment of TXU Energy Holdings’ 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 quarter 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 $291 million in the second quarter and $641 million year-to-date.

Also, as previously disclosed, TXU Energy Holdings 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 Holdings 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 Holdings’ generation increasingly exceeding its retail load, the net balancing activity has more recently generally resulted in net sales of power. TXU Energy Holdings believes that presentation of this activity as a component of revenues more appropriately reflects TXU Energy Holdings’ market position. Accordingly, consistent with reporting for the first quarter 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 second quarter of 2006 totaled $32 million in net purchases and for the year-to-date totaled $26 million in net sales. The amounts reclassified for the second quarter and year-to-date periods of 2005 totaled $49 million and $66 million in net sales, respectively.

5

Discontinued Businesses— Note 4 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 Holdings’ 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 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 Holdings is currently evaluating the potential impact of this standard.

2.         IMPAIRMENT OF NATURAL GAS-FIRED GENERATION PLANTS

TXU Energy Holdings evaluates long-lived assets 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 Holdings determined that it is more likely than not that its gas-fired generation plants, which have generally been operated to meet peak demands for power, will 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 $198 million ($129 million after-tax) was recorded in the second quarter of 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.

3.        TEXAS MARGIN TAX

In May 2006, the Texas legislature enacted a new law 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 Holdings 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 will 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 Holdings 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 Holdings 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 Holdings will monitor these developments and make any appropriate changes to its estimate.

6

4.        DISCONTINUED OPERATIONS

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

	Three Months Ended			Six Months Ended
	June 30, 2005			June 30, 2005
Operating revenues	$	6		$	12
Operating costs and expenses		7			14
Operating loss before income taxes		(1	)		(2	)
Income tax benefit		─			─
Charges related to exit (after-tax)		─			(2	)
Loss from discontinued operations	$	(1	)	$	(4	)

5.        TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables— TXU Energy Holdings 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 Holdings sell trade accounts receivable to TXU Receivables Company, a 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 June 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 Holdings as of June 30, 2006 totaled $608 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 customer deposits if TXU Energy Holdings’ fixed charge coverage ratio is less than 2.5 times; 50% if TXU Energy Holdings’ coverage ratio is less than 3.25 times, but at least 2.5 times; and zero % if TXU Energy Holdings’ coverage ratio is 3.25 times or more. The originators’ customer deposits, which totaled $114 million, did not affect funding availability as TXU Energy Holdings’ coverage ratio was in excess of 3.25 times.

All new trade receivables under the program generated by TXU Energy Holdings 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 Holdings for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to TXU Energy Holdings that was funded by the sale of the undivided interests. The balance of the subordinated notes issued to TXU Energy Holdings, which is reported in accounts receivable, was $174 million and $154 million at June 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, as well as a servicing fee paid by TXU Receivables Company to TXU Business Services, a direct subsidiary of TXU Corp. The program fees (losses on sale for accounting purposes) for TXU Energy Holdings, which consist primarily of interest costs on the underlying financing, totaled $15 million and $7 million for the six-month periods ending June 30, 2006 and 2005 and averaged 5.4% and 3.7% (on an annualized basis) of the funding under the program for the first six months of 2006 and 2005, respectively. The servicing fee, which totaled approximately $2 million in the first six months of both 2006 and 2005, compensates TXU Business Services for its services as collection agent, including maintaining the detailed accounts receivable collection records. The program and servicing fees are reported in SG&A expenses.

7

The accounts receivable balance reported in the June 30, 2006 consolidated balance sheet has been reduced by $782 million face amount of trade accounts receivable sold to TXU Receivables Company, partially offset by the inclusion of $174 million of subordinated notes receivable from TXU Receivables Company. Funding under the program increased $26 million to $608 million for the six months ended June 30, 2006 and decreased $5 million to $406 million for the six months ended June 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 approximated fair value due to the short-term nature of the collection period.

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

	Six Months Ended June 30,
	2006			2005
Cash collections on accounts receivable	$	3,138		$	2,786
Face amount of new receivables purchased		(3,184	)		(2,718	)
Discount from face amount of purchased receivables		17			9
Program fees paid		(15	)		(7	)
Servicing fees paid		(2	)		(2	)
Increase (decrease) in subordinated notes payable		20			(63	)
Operating cash flows (provided to) used by TXU Energy Holdings under the program	$	(26	)	$	5

Upon termination of the program, cash flows to TXU Energy Holdings 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.

8

Trade Accounts Receivable—

	June 30,			December 31,
	2006			2005
Gross trade accounts receivable	$	1,467		$	1,791
Undivided interests in accounts receivable sold by TXU Receivables Company		(782	)		(736	)
Subordinated notes receivable from TXU Receivables Company		174			154
Allowance for uncollectible accounts related to undivided interests in receivables retained		(16	)		(31	)
Trade accounts receivable ― reported in balance sheet	$	843		$	1,178

Gross trade accounts receivable at June 30, 2006 and December 31, 2005 included unbilled revenues of $534 million and $443 million, respectively.

Allowance for Uncollectible Accounts —

	2006			2005
Allowance for uncollectible accounts receivable as of January 1	$	31		$	15
Increase for bad debt expense		29			19
Decrease for account write-offs		(41	)		(31	)
Changes related to receivables sold		13			18
Other (a)		(16	)		15
Allowance for uncollectible accounts receivable as of June 30	$	16		$	36
____________
(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 receivables sold are reported in current liabilities and totaled $16 million and $29 million at June 30, 2006 and December 31, 2005, respectively.

9

6.         SHORT-TERM AND LONG-TERM DEBT

Short-term Borrowings —At June 30, 2006, TXU Energy Holdings had outstanding short-term borrowings consisting of bank borrowings under credit facilities of $1.2 billion with a weighted average interest rate of 5.74% at the end of the period and commercial paper of $671 million with a weighted average interest rate of 5.46% at the end of the period.At December 31, 2005, TXU Energy Holdings had outstanding short-term borrowings consisting of bank borrowings under credit facilities of $440 million with a weighted average interest rate of 4.86% at the end of the period and commercial paper of $306 million with a weighted average interest rate of 4.48% at the end of the period.

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

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

		At June 30, 2006
Authorized	Maturity	Facility	Letters of	Cash
Borrowers	Date	Limit	Credit	Borrowings	Availability
TXU Energy Holdings	May 2007	$1,500	$   ―	$  ―	$1,500
TXU Energy Holdings, TXU Electric Delivery	June 2008	1,400	505	180	715
TXU Energy Holdings, TXU Electric Delivery	August 2008	1,000	―	495	505
TXU Energy Holdings, TXU Electric Delivery	March 2010	1,600	500	280	820
TXU Energy Holdings, TXU Electric Delivery	June 2010	500	―	240	260
TXU Energy Holdings	December 2009	500	455	45	―
Total		$6,500	$1,460	$1,240	$3,800

In May 2006, TXU Energy Holdings entered into a new $1.5 billion 364-day credit facility with terms comparable to its existing facilities.

The maximum amount TXU Energy Holdings 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 Holdings 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 June 30, 2006, there were no outstanding borrowings under these facilities.

All letters of credit and cash borrowings under the credit facilities as of June 30, 2006 are the obligations of TXU Energy Holdings. In addition, TXU Electric Delivery has outstanding commercial paper supported by these facilities totaling $592 million.

10

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

	June 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
3.980% 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
4.020% Floating Series 2001D due May 1, 2033(d)		268			268
5.350% Floating Taxable Series 2001I due December 1, 2036(d)		62			62
3.980% 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		8			9
Total TXU Energy Holdings		2,950			3,456
Less amount due currently		(1	)		(401	)
Total long-term debt	$	2,949		$	3,055

____________

(a)	These series are in the multiannual mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.
(b)	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 June 30, 2006. These series are in a weekly 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

Debt Issuances and Retirements in 2006— In June 2006, upon the scheduled mandatory tender date, TXU Energy Holdings 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 Holdings currently plans to remarket the bonds later this year.

In May 2006, upon the scheduled mandatory tender date, TXU Energy Holdings 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 Holdings currently plans to remarket these bonds later this year.

In March 2006, TXU Energy Holdings 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 Holdings 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 $400 million represent payments at scheduled maturity dates.

Fair Value Hedge —TXU Energy Holdings uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At June 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 hedge is 100% effective).

Long-term debt fair value adjustments —

		June 30, 2006
Long-term debt fair value adjustments related to an interest rate swap at beginning of period ― increase in debt carrying value	$	9
Amortization of net gains on settled fair value hedge (a)		(1)
Long-term debt fair value adjustments at end of period ― increase in debt carrying value (net in-the-money value of swap)	$	8

___________

(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

Under SFAS 123R, compensation expense related to TXU Corp.’s share-based awards to TXU Energy Holdings’ employees is accounted for as a noncash capital contribution from the parent. Accordingly, TXU Energy Holdings recorded a credit to its membership interests account of $2 million and $4 million for the three and six months ended June 30, 2006, respectively.

The increase in membership interests in 2006 also reflects excess tax benefits arising from the distribution date value of the share-based awards exceeding the reported compensation expense of the awards (which is based on fair value of the awards at grant date).

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 six months ended June 30, 2006:

	Capital Accounts			Accumulated  Other Comprehensive Gain (Loss)			Total Membership Interests
Balance at December 31, 2005	$	4,474		$	(121	)	$	4,353
Net income		1,063			─			1,063
Distributions paid to parent		(572	)		─			(572	)
Net effects of cash flow hedges (net of tax)		─			49			49
Effects of incentive compensation plans		15			─			15
Other		2			─			2
Balance at June 30, 2006	$	4,982		$	(72	)	$	4,910

8.         COMMITMENTS AND CONTINGENCIES

Guarantees — As discussed below, TXU Energy Holdings has entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions. Accounting rules require the recording of a liability for the fair value of guarantees entered into or modified subsequent to December 31, 2002.

Letters of credit— At June 30, 2006, TXU Energy Holdings had outstanding letters of credit under its revolving credit facilities in the amount of $471 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 June 30, 2006, approximately 77% of the obligations supported by these letters of credit mature within one year, and substantially all of the remainder mature in the next two years. Additionally, TXU Energy Holdings had outstanding letters of credit under its revolving credit facilities in the amount of $500 million at June 30, 2006 to support TXU DevCo’s commodity price hedge transactions under a long-term hedging program.

Further, TXU Energy Holdings has outstanding letters of credit under its revolving credit facilities totaling $455 million at June 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.

Debt obligation of TXU Corp. ―TXU Energy Holdings has provided a guarantee of the obligations under TXU Corp.’s financing lease (approximately $104 million at June 30, 2006) for its headquarters building.

13

Residual value guarantees in operating leases — TXU Energy Holdings is the lessee under various operating leases that obligate it to guarantee the residual values of the leased assets. At June 30, 2006, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled approximately $92 million. These leased assets consist primarily of mining equipment and rail cars. A significant portion of the maximum guarantee amount relates to leases entered into prior to December 31, 2002. The average life of the lease portfolio is approximately eight years.

Contractual Obligations — TXU Energy Holdings has entered into an engineering, procurement and construction contract for the development of two generation units.  Cancellation costs related to this agreement totaled $73 million at June 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 in the third quarter of 2006.

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., TXU Corp.’s reduction of its quarterly dividend in October 2002, and the following two previously disclosed claims against TXU Corp. and certain other persons named in such claims: (i) a lawsuit brought in April 2003 by a former employee of TXU Portfolio Management, William J. Murray (Murray Litigation) and (ii) various consolidated lawsuits brought by various shareholders of TXU Corp. during late 2002 and January 2003 (Shareholders’ Litigation). 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. Although TXU Corp. cannot predict the outcome of the SEC inquiry, TXU Corp. does not believe there was any basis for the claims made in the Murray Litigation, which has now been settled. A final settlement stipulation was signed and filed with the Court in the Shareholders’ Litigation and the Court has approved the settlement, although certain members of the settlement class who object to the approval of the settlement have appealed the Court’s order approving the settlement. TXU Corp. has cooperated with the SEC and completed the production of the documents requested by the subpoena and has 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." TXU Corp. has filed a Motion to Quash service for lack of personal jurisdiction. While the court has not issued a final order on TXU Corp.’s motion, it indicated in a preliminary hearing that TXU Corp.’s motion would be denied. 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 Holdings is, however, unable to estimate any possible loss or predict the outcome of these actions.

In addition to the above, TXU Energy Holdings 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.

14

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 Holdings 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 Holdings and its subsidiaries must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. TXU Energy Holdings 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 Holdings 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 trading purposes and include mark-to-market values of those derivative contracts that are not accounted for as cash flow hedges as well as contracts for which the “normal” purchase or sale exemption has not been elected under SFAS 133.

Current and noncurrent commodity contract assets totaling $805 million at June 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 $871 million at June 30, 2006 and $2.0 billion at December 31, 2005.

10.      CASH FLOW HEDGES UNDER SFAS 133

TXU Energy Holdings experienced net cash flow hedge ineffectiveness gains related to positions held at the end of the period of $150 million and $145 million for the three and six month periods ended June 30, 2006, respectively. For the corresponding quarter and year-to-date periods of 2005, the amounts were less than a million and a $1 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 $151 million and $150 million in net gains for the three and six month periods ended June 30, 2006, respectively, and $3 million and $6 million in net gains for the three and six month periods ended June 30, 2005, respectively.

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

Cash flow hedge amounts reported in the Statements of Consolidated Comprehensive Income exclude net losses and gains associated with cash flow hedges entered into and settled within the period. These totaled $14 million and $18 million in after-tax net gains for the three and six month periods ended June 30, 2006, respectively, and $2 million in after-tax net gains for both the corresponding periods of 2005.

TXU Energy Holdings expects that $6 million in after-tax net losses related to cash flow hedges included in accumulated other comprehensive net loss 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, $1 million in gains relate to commodity hedges and $7 million in losses relate to financing-related hedges.

16

11.     OTHER INCOME AND DEDUCTIONS

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006			2005
Other income:
Net gain on sales of assets	$	─	$	2	$	─		$	1
Power services agreement termination fee		─		4		─			4
Other		1		─		1			3
Total other income	$	1	$	6	$	1		$	8
Other deductions:
Charge for impairment of natural gas-fired generation plants	$	198	$	─	$	198		$	─
Charge (credit) related to coal contract counterparty claim		─		─		(12	)		12
Inventory write-off related to natural gas-fired generation plants		3		─		3			─
Capgemini outsourcing transition costs		─		2		─			6
Equity losses of affiliate holding investment in Capgemini		2		2		5			3
Employee severance		─		3		─			(1	)
Charge (credit) related to impaired leases		1		3		(1	)		(12	)
Other		1		2		2			5
Total other deductions	$	205	$	12	$	195		$	13

See Note 2 for discussion of impairment of natural gas-fired generation plants.

In the first quarter of 2006, TXU Energy Holdings 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.

Amounts recorded in 2005 for impaired leases relate to gas-fired combustion turbines that TXU Energy Holdings 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 Holdings:

·   TXU Energy Holdings incurs electricity delivery fees charged by TXU Electric Delivery. These fees totaled $285 million and $305 million for the three months ended June 30, 2006 and 2005, respectively, and $554 million and $618 million for the six months ended June 30, 2006 and 2005, respectively.

·   Under the terms of the Settlement Plan, TXU Electric Delivery issued an initial $500 million of securitization bonds in 2003 and issued $790 million in 2004 to recover generation-related regulatory assets. The incremental income taxes TXU Electric Delivery will pay on the increased delivery fees to be charged to TXU Electric Delivery’s customers related to the bonds will be reimbursed by TXU Energy Holdings. Therefore, TXU Energy Holdings’ financial statements reflect a noninterest bearing note payable to TXU Electric Delivery of $373 million at June 30, 2006 ($33 million reported as current liabilities) and $395 million at December 31, 2005 ($33 million reported as current liabilities).

·   TXU Energy Holdings 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 June 30, 2006 and 2005, respectively, and $27 million and $28 million for the six months ended June 30, 2006 and 2005, respectively.

·   Current and noncurrent advances to parent totaled $2.5 billion at June 30, 2006 and $694 million at December 31, 2005. The average daily balances of the advances to parent totaled $1.6 billion and $1.0 billion during the three months ended June 30, 2006 and 2005, respectively. Interest income earned on the advances totaled $22 million and $10 million for the three months ended June 30, 2006 and 2005, respectively. The weighted average annual interest rates were 5.3% and 3.7% for the three months ended June 30, 2006 and 2005, respectively. The average daily balance of the advances to parent were $1.2 billion and $853 million during the six months ended June 30, 2006 and 2005, respectively. Interest income earned on the advances totaled $32 million and $16 million for the six months ended June 30, 2006 and 2005, respectively. The weighted average annual interest rates were 5.2% and 3.7% for the six months ended June 30, 2006 and 2005, respectively.

·   In December 2005, TXU Energy Holdings 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 that is applicable to other affiliate receivable balances. Interest income related to this note totaled $19 million and $39 million for the three and six months ended June 30, 2006, respectively.

·   TXU Corp. charges TXU Energy Holdings for financial, accounting, environmental and other administrative services at cost. These costs, which are primarily reported in SG&A expenses, totaled $15 million and $14 million for the three months ended June 30, 2006 and 2005, respectively, and $35 million and $28 million for the six months ended June 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 Holdings’ balance sheet, is funded by a delivery fee surcharge billed to REPs by TXU Electric Delivery and remitted to TXU Energy Holdings, with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported in noncurrent liabilities on TXU Energy Holdings’ balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by TXU Energy Holdings are offset by a net change in the intercompany receivable/payable with TXU Electric Delivery, which in turn results in a change in a net regulatory asset/liability. The regulatory asset, which totaled $12 million and $8 million at June 30, 2006 and December 31, 2005, respectively, and is reported on TXU Electric Delivery’s balance sheet, represents the excess of the decommissioning liability over the trust fund balance.

18

·   In April 2004, TXU Corp. purchased TXU Energy Holdings’ exchangeable preferred membership interests from unaffiliated holders. Distributions and discount amortization (both reported as interest expense) related to the securities totaled $22 million for both the three months ended June 30, 2006 and 2005 and totaled $45 million and $43 million for the six months ended June 30, 2006 and 2005, respectively, and are reported in interest expense and related charges.

·   In December 2005, US Holdings entered into an agreement to purchase the owner participant interest in a trust that leases combustion turbines to TXU Energy Holdings. Therefore, TXU Energy Holdings’ financial statements reflect a $49 million liability payable to US Holdings ($11 million reported as due currently) at June 30, 2006 and $59 million ($15 million reported as due currently) at December 31, 2005. The liability relates to lease payments for combustion turbines that TXU Energy Holdings has ceased operating for its own benefit.

·   TXU Energy Holdings has a 53.1% limited partnership interest, with a carrying value of $19 million and $24 million at June 30, 2006 and December 31, 2005, respectively, in a TXU Corp. subsidiary holding Capgemini-related assets. Equity losses related to this interest totaled $2 million for both the three months ended June 30, 2006 and 2005 and totaled $5 million and $3 million for the six months ended June 30, 2006 and 2005, respectively. These losses primarily represent amortization of software assets held by the subsidiary.

·   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. TXU Energy Holdings had an income tax payable to TXU Corp. of $293 million at June 30, 2006 and an income tax receivable from TXU Corp. of $361 million at December 31, 2005.

·   In the second quarter of 2006, TXU Energy Holdings transferred its mineral interests in natural gas and oil to TXU Corp. at book value, which was zero. These mineral interests were acquired as part of land purchases over the years to support generation activities and not for the mineral development, and no value was attributed to the mineral interests at the time of acquisition.

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 Holdings pension and other postretirement benefit costs, respectively.

19

13.     SUPPLEMENTARY FINANCIAL INFORMATION

Interest Expense and Related Charges—

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Interest	$	86		$	72		$	166		$	139
Distributions on preferred membership interests		17			17			34			34
Amortization of discount and debt issuance costs		7			8			14			17
Interest capitalized in accordance with SFAS 34		(8	)		(3	)		(12	)		(5	)
Total interest expense and related charges	$	102		$	94		$	202		$	185

Restricted Cash—

	Balance Sheet Classification
	At June 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)	$	―	$	100	$	―	$	―
All other		3		―		8		―
Total restricted cash	$	3	$	100	$	8	$	―

Inventories by Major Category—

	June 30,		December 31,
	2006		2005
Materials and supplies	$	111	$	108
Gas stored underground		104		99
Fuel stock		95		81
Environmental energy credits and emission allowances		12		21
Total inventories	$	322	$	309

Investments—

	June 30,		December 31,
	2006		2005
Nuclear decommissioning trust	$	402	$	389
Assets related to employee benefit plans		45		54
Land		31		32
Investment in affiliate holding Capgemini-related assets		19		24
Miscellaneous other		1		2
Total investments	$	498	$	501

Property, Plant and Equipment— At June 30, 2006 and December 31, 2005, property, plant and equipment of $9.8 billion and $10.0 billion, respectively, is stated net of accumulated depreciation and amortization of $8.1 billion and $7.9 billion, respectively.

20

Asset Retirement Obligations — For TXU Energy Holdings, 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 during the six months ended June 30, 2006:

Asset retirement liability at December 31, 2005	$	558
Additions:
Accretion		18
Reductions:
Net change in mining land reclamation estimated liability		(4)
Reclamation payments		(14)
Asset retirement liability at June 30, 2006	$	558

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

	As of June 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	$	30	$	23	$	7	$	31	$	24	$	7
Capitalized software placed in service		11		4		7		7		3		4
Land easements		2		1		1		2		1		1
Total	$	43	$	28	$	15	$	40	$	28	$	12

Aggregate amortization expense for intangible assets totaled $0.7 million and $0.4 million for the three months ended June 30, 2006 and 2005, respectively, and totaled $1 million for both the six months ended June 30, 2006 and 2005. At June 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 June 30, 2006 and December 31, 2005 was stated net of previously recorded accumulated amortization of $60 million.

21

Pension and Other Postretirement Benefits — TXU Energy Holdings is a participating employer in the pension plan sponsored by TXU Corp. TXU Energy Holdings 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 other postretirement benefit costs applicable to TXU Energy Holdings totaled $4 million and less than $1 million for the three month periods ended June 30, 2006 and 2005, respectively, and $9 million and $7 million for the six month periods ended June 30, 2006 and 2005, respectively.

The discount rate reflected in net pension and other postretirement benefit 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 other postretirement benefits.

In June 2005, an amendment to PURA relating to pension and other postretirement benefits 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 other postretirement benefit costs for all applicable former employees of the regulated predecessor integrated electric utility (i.e., certain TXU Energy Holdings’ 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 Holdings have entered into an agreement whereby TXU Electric Delivery assumes responsibility for pension and other postretirement benefit costs for all applicable employees of TXU Energy Holdings. In connection with this agreement, TXU Energy Holdings transferred to TXU Electric Delivery pension-related assets of $8 million in 2006 and pension-related liabilities of $137 million in 2005.

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		(19)
Liability for severance costs as of June 30, 2006	$	7
___________
(a)Additions to the liability relate to an outsourcing of certain engineering services.

 Commodity Contract Positions and Margin Deposits — Commodity contract assets and liabilities and margin deposits reported in the consolidated balance sheets reflect counterparty netting in accordance with legal right of offset agreements.

 Supplemental Cash Flow Information—

	Six Months Ended June 30,
	2006			2005
Cash payments (receipts) related to continuing operations:
Interest (net of amounts capitalized)	$	195		$	166
Income taxes	$	(246	)	$	239
Noncash investing and financing activities:
Noncash contribution of pension-related assets	$	(8	)	$	157

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 Holdings”) as of June 30, 2006, and the related condensed statements of consolidated income and comprehensive income for the three-month and six-month periods ended June 30, 2006 and 2005, and of cash flows for the six-month periods ended June 30, 2006 and 2005. These interim financial statements are the responsibility of TXU Energy Holdings’ 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 Holdings 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

August 8, 2006

23

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

AND RESULTS OF OPERATIONS

BUSINESS

TXU Energy Holdings is a wholly-owned subsidiary of US Holdings, which is a wholly-owned subsidiary of TXU Corp. TXU Energy Holdings 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 Holdings.

RECENT DEVELOPMENTS

New Generation Development Program

In April 2006, TXU Corp. announced a plan to invest up to $10 billion to develop new generation units in Texas. This plan includes constructing 11 generation units that will be developed and owned by TXU DevCo, a subsidiary of TXU Corp. established for that purpose. The plan also includes $500 million for environmental control systems to voluntarily reduce emissions from TXU Energy Holdings’ 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 Holdings’ renewable energy portfolio to 1,400 MW by 2011.

In June 2006, TXU DevCo secured a commitment for $11 billion of financing to fund the development and construction of the 11 new generation units. The financing agreement is expected to close in the fall of 2006. Borrowings by TXU DevCo under the agreement are expected to be nonrecourse to TXU Corp. TXU DevCo’s borrowings under the facilities are expected to include amounts to reimburse TXU Corp. and other of its subsidiaries, primarily TXU Energy Holdings, for development spending prior to securing the air permits. Capital expenditures for the development program are expected to total approximately $1.2 billion in 2006, of which approximately $400 million is expected to be funded by borrowings under the facilities, with the remainder expected to be reimbursed in 2007.

Impairment of Natural Gas-fired Generation Plants

In consideration of the new generation development program and other factors, TXU Energy Holdings 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 of $198 million ($129 million after-tax).

Update of Hedging Program, Including New Collateral Arrangements

In October 2005, TXU Corp. commenced a long-term hedging program 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 Holdings have entered into market transactions involving natural gas-related financial instruments. Since February 2006, TXU Energy Holdings 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. 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 Holdings has experienced in recent years. Reported earnings included net unrealized pretax hedge ineffectiveness gains related to positions in the program totaling $149 million and $128 million for the three and six month periods ended June 30, 2006, respectively. 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 $78 million to $99 million in cash flow hedge ineffectiveness pretax gains or losses in the period of such change.

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.

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 Holdings have used cash and letters of credit to satisfy their collateral obligations. Considering the current and expected scale of its hedging program and the desire to reduce the potential effect on liquidity of collateral postings, TXU Energy Holdings expects that certain counterparties will be granted a first-lien security interest by TXU Big Brown in its two existing 595 MW lignite/coal-fired generation units to secure potential obligations under hedging transactions. This security interest (Big Brown Lien) may support hedging of revenues from the 11 new generation units as well as TXU Energy Holdings’ generation facilities.

As part of TXU Corp.’s overall hedging program, in June 2006 TXU DevCo entered into a related series of hedging transactions that will allow TXU DevCo to hedge movements in power prices through both new transactions and the novation of existing TXU Energy Holdings hedging transactions to TXU DevCo. TXU DevCo’s hedging transactions are initially supported by letters of credit aggregating $500 million issued by TXU Energy Holdings. It is anticipated that by the end of August 2006, the letters of credit will be replaced as collateral on an interim basis by the Big Brown Lien.

If the Big Brown Lien is not in place by September 4, 2006, TXU Energy Holdings, on behalf of TXU DevCo, will post additional letters of credit in the amount of $500 million (totaling $1 billion). If the Big Brown Lien (or a lien on another asset of equivalent value) is not in place by June 2007, then TXU DevCo will be required to post additional letters of credit, which would likely be posted by TXU Energy Holdings, in the amount of $1 billion (totaling $2 billion).

The Big Brown Lien will 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 certain of its 11 new generation units.

In accordance with the TXU DevCo hedging agreement, on December 31, 2007, TXU DevCo will determine the amount of hedging transactions that may be secured by liens on TXU DevCo assets. The hedge amounts will 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 Holdings and continue to be secured by the Big Brown Lien (or alternative collateral of equivalent value or letters of credit).

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 4 to Financial Statements regarding discontinued operations).

25

Sales Volume Data

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2006			2005			Change %			2006			2005			Change %
Sales volumes:
Retail electricity sales volumes (GWh):
Historical service territory:
Residential		6,825			7,100			(3.9	)		12,057			13,417			(10.1	)
Small business (a)		2,068			2,289			(9.7	)		3,795			4,323			(12.2	)
Total historical service territory		8,893			9,389			(5.3	)		15,852			17,740			(10.6	)
Other territories:
Residential		1,018			858			18.6			1,629			1,486			9.6
Small business (a)		169			165			2.4			301			304			(1.0	)
Total other territories		1,187			1,023			16.0			1,930			1,790			7.8
Large business and other customers		3,552			4,172			(14.9	)		6,785			8,534			(20.5	)
Total retail electricity		13,632			14,584			(6.5	)		24,567			28,064			(12.5	)
Wholesale electricity sales volumes (b)		7,585			12,585			(39.7	)		16,870			24,824			(32.0	)
Total sales volumes		21,217			27,169			(21.9	)		41,437			52,888			(21.7	)
Average volume (kWh) per retail customer (c):
Residential		4,012			3,809			5.3			6,975			7,091			(1.6	)
Small business		7,990			8,096			(1.3	)		14,460			15,028			(3.8	)
Large business and other customers		70,256			71,155			(1.3	)		130,966			129,342			1.3
Weather (service territory average) - percent of normal (d):
Percent of normal:
Cooling degree days		131.0	%		102.2	%					135.9	%		101.3	%

________________

(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 purchase volumes related to ERCOT balancing of 266 GWh in the second quarter of 2006 and 1,253 GWh of net sales volumes in the second quarter of 2005, and net sales volumes of 1,166 GWh and 2,012 GWh in the six months ended June 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

	Six Months Ended
	June 30,
	2006		2005		Change %
Customer counts:
Retail electricity customers (end of period and in thousands) (a):
Historical service territory:
Residential		1,716		1,865		(8.0	)
Small business (b)		271		294		(7.8	)
Total historical service territory		1,987		2,159		(8.0	)
Other territories:
Residential		227		193		17.6
Small business (b)		7		7		─
Total other territories		234		200		17.0
Large business and other customers		49		56		(12.5	)
Total retail electricity customers		2,270		2,415		(6.0	)

________________

(a)   Based on number of meters.

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

27

Revenue and Market Share Data

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2006			2005			Change %			2006			2005			Change %
Operating revenues:
Retail electricity revenues:
Historical service territory:
Residential	$	1,008		$	838			20.3		$	1,753		$	1,474			18.9
Small business (a)		309			270			14.4			566			498			13.7
Total historical service territory		1,317			1,108			18.9			2,319			1,972			17.6
Other territories:
Residential		160			99			61.6			248			156			59.0
Small business (a)		20			15			33.3			36			27			33.3
Total other territories		180			114			57.9			284			183			55.2
Large business and other customers		339			332			2.1			655			659			(0.6	)
Total retail electricity revenues		1,836			1,554			18.1			3,258			2,814			15.8
Wholesale electricity revenues (b)		447			598			(25.3	)		982			1,132			(13.3	)
Net gains (losses) from risk management and trading activities		106			47			─			62			(6	)		─
Other revenues		79			77			2.6			176			157			12.1
Total operating revenues	$	2,468		$	2,276			8.4		$	4,478		$	4,097			9.3
Risk management and trading activities:
Net realized gains (losses) on settled positions	$	(38	)	$	5					$	(86	)	$	(24	)
Reversal of prior years’ net unrealized
(gains)/losses on positions settled in current period		(2	)		(14	)					22			(23	)
Other net unrealized gains, including ineffectiveness		146			56						126			41
Total net gains (losses)	$	106		$	47					$	62		$	(6	)
Average revenues per MWh:
Residential	$	148.85		$	117.80			26.4		$	146.23		$	109.39			33.7
Small business	$	147.32		$	116.38			26.6		$	146.95		$	113.59			29.4
Large business and other customers	$	95.34		$	79.43			20.0		$	96.55		$	77.19			25.1
Estimated share of ERCOT retail markets (c)(d):
Historical service territory:
Residential											70	%		77	%
Small business											68	%		74	%
Total ERCOT:
Residential											38	%		42	%
Small business											28	%		30	%
Large business and other customers											17	%		20	%

__________________________

(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 second quarter of 2006 and $49 million of net sales in the second quarter of 2005, and net sales of $26 million and $66 million in the six months ended June 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									Six Months Ended
	June 30,									June 30,
	2006			2005			Change %			2006			2005			Change %
Fuel, purchased power costs and delivery fees
($ millions):
Nuclear fuel	$	22		$	18			22.2		$	43		$	38			13.2
Lignite/coal		113			119			(5.0	)		229			234			(2.1	)
Total baseload fuel		135			137			(1.5	)		272			272			─
Gas/oil fuel and purchased power		421			720			(41.5	)		689			1,252			(45.0	)
Other costs		50			70			(28.6	)		122			133			(8.3	)
Fuel and purchased power costs (a)		606			927			(34.6	)		1,083			1,657			(34.6	)
Delivery fees		337			338			(0.3	)		650			681			(4.6	)
Total	$	943		$	1,265			(25.5	)	$	1,733		$	2,338			(25.9	)
Fuel and purchased power costs (which excludes
generation plant operating costs) per MWh:
Nuclear generation	$	4.25		$	4.20			1.2		$	4.24		$	4.19			1.2
Lignite/coal generation (b)	$	12.67		$	12.02			5.4		$	12.33		$	11.98			2.9
Gas/oil generation and purchased power	$	63.40		$	54.92			15.4		$	61.76		$	52.47			17.7
Delivery fee per MWh	$	24.51		$	22.84			7.3		$	26.18		$	23.95			9.3
Production and purchased power volumes (GWh):
Nuclear		5,098			4,250			20.0			10,178			9,047			12.5
Lignite/coal		10,044			10,605			(5.3	)		20,918			21,125			(1.0	)
Total baseload generation		15,142			14,855			1.9			31,096			30,172			3.1
Gas/oil generation		1,350			1,005			34.3			1,539			1,265			21.7
Purchased power (a)		5,291			12,034			(56.0	)		9,616			22,599			(57.4	)
Total energy supply		21,783			27,894			(21.9	)		42,251			54,036			(21.8	)
Less line loss and power imbalances		566			725			(21.9	)		814			1,148			(29.1	)
Net energy supply volumes		21,217			27,169			(21.9	)		41,437			52,888			(21.7	)
Baseload capacity factors (%):
Nuclear		102.0	%		84.9	%		20.1			102.3	%		90.8	%		12.7
Lignite/coal		82.4	%		86.9	%		(5.2	)		86.4	%		87.3	%		(1.0	)
Total baseload		88.0	%		86.3	%		2.0			90.9	%		88.3	%		2.9

________________

(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

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

Operating revenues increased $192 million, or 8%, to $2.5 billion in 2006. Retail electricity revenues increased $282 million, or 18%, to $1.8 billion.

·   The retail revenue increase reflected $383 million in higher pricing due to increased price-to-beat rates, reflecting regulatory-approved fuel factor increases in May and October 2005, and higher pricing in the competitive business market, both resulting from the effects of higher natural gas prices.

·   The effect of higher pricing due to increased price-to-beat rates was partially offset by a $101 million effect of lower retail volumes. Total retail sales volumes declined 7% primarily reflecting a net loss of customers due to competitive activity partially offset by the effect of warmer weather. Excluding the estimated effect of warmer weather, average consumption per customer declined somewhat. Large business market volumes declined 15%, while residential and small business volumes fell 3%. The large business market decline reflected a continuing strategy to improve margins.

·   Retail electricity customer counts at June 30, 2006 declined 6% from June 30, 2005. Total residential and small business customer counts in the historical service territory declined 8% and in all combined territories declined 6%.

Wholesale electricity revenues decreased $151 million to $447 million. The change reflects the reporting of wholesale power trading activity on a net basis. In addition, ERCOT balancing activity reported in wholesale electricity revenues totaled $32 million in net purchases in 2006 and $49 million in net sales in 2005. The effects related to both the power trading and ERCOT balancing activities were partially offset by higher wholesale pricing. See Note 1 to Financial Statements.

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 $106 million in 2006 and $47 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:

·   $151 million in net unrealized cash flow hedge ineffectiveness gains largely associated with positions in the long-term hedging program;

·   $15 million in net realized gains primarily associated with positions in the long-term hedging program accounted for as cash flow hedges, the offsetting effects of which are reflected in electricity revenues;

·   $16 million in net realized losses associated with hedges entered into in prior years (largely 2003), the offsetting effects of which are reflected in electricity revenues and fuel and purchased power. This amount includes $11 million in losses related to positions that had been accounted for as cash flow hedges;

·   $20 million in reversals of previously recorded net unrealized gains on hedge positions (marked-to-market) that were settled in the current period, the offsetting effects of which are reflected in electricity revenues and fuel and purchased power costs; and

·   $28 million in net unrealized losses primarily relating to hedge positions that are marked-to-market.

30

Gross Margin

	Three Months Ended June 30,
	2006		% of Revenue			2005		% of Revenue
Operating revenues	$	2,468		100	%	$	2,276		100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		943		38			1,265		56
Generation plant operating costs		152		6			177		8
Depreciation and amortization		83		4			76		3
Gross margin	$	1,290		52	%	$	758		33	%

Gross margin is considered a key operating metric as it measures the effect of the change in sales volumes and pricing versus the variable and fixed costs to generate, purchase and deliver energy. Operating costs relate directly to generation plants. Depreciation and amortization expense included in gross margin relates to assets that are directly used in the generation of electricity.

Gross margin increased $532 million, or 70%, to $1.3 billion in 2006. This growth primarily reflected the relatively low fuel costs of the nuclear and lignite/coal-fired baseload plants, as well as overall higher baseload production, in an environment of higher wholesale prices. A 24% increase in wholesale power prices was driven by higher natural gas prices. Retail prices, including price-to-beat rates, were increased in response to higher wholesale prices. The gross margin performance was mitigated by the effect of lower retail sales volumes and higher purchased power prices.

Gross margin as a percent of revenues increased 19 percentage points to 52%. The improvement reflected:

·   higher pricing, as the average wholesale sales price per MWh rose 24%, and the average retail sales price per MWh rose 26% (11 percentage point margin increase);

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

·   lower operating costs and higher gains from risk management and trading activities (two percentage point margin increase),

partially offset by a 15% increase in combined per MWh purchase power costs and fuel costs in gas/oil-fired generation, due to rising natural gas prices (two percentage point margin decrease).

Operating costs decreased $25 million, or 14%, to $152 million in 2006. The decrease reflected:

·   $20 million in lower maintenance costs due largely to the absence in 2006 of costs incurred in 2005 for the nuclear generation plant refueling outage; and

·   $3 million in lower property taxes due to lower overall property valuation estimates,

partially offset by $4 million in transition costs associated with generation outsourcing services agreements entered into in 2006.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) increased $7 million, or 9%, to $84 million reflecting higher expense associated with mining reclamation obligations.

31

SG&A expenses increased by $8 million, or 7%, to $121 million in 2006. The increase reflected:

·   $9 million in higher bad debt expense reflecting higher retail accounts receivable balances; and

·   $4 million in higher fees related to the sale of accounts receivable program due to higher interest rates,

partially offset by $4 million in lower consulting fees primarily reflecting expenses in 2005 for the development and implementation of the TXU Operating System to improve productivity.

Other income totaled $1 million in 2006 and $6 million in 2005. Other deductions totaled $205 million in 2006, which included a $198 million impairment charge related to natural gas-fired generation plants, and $12 million in 2005. See Note 11 to Financial Statements for additional detail.

Interest income increased by $34 million to $45 million in 2006 reflecting $20 million due to higher average advances to affiliates and $14 million due to higher average rates.

Interest expense and related charges increased by $8 million, or 9%, to $102 million in 2006 reflecting $6 million due to higher average borrowings and $7 million due to higher average rates, partially offset by higher capitalized interest.

Income tax expense on income from continuing operations totaled $337 million in 2006 compared to $186 million in 2005. The 2005 amount reflected a charge of $10 million related to the settlement of the IRS audit for the 1994 to 1996 years. The 2006 amount included a charge of $42 million representing an adjustment to net deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 3 to the Financial Statements. Excluding the impact of these two items, the effective tax rate was 33.5% in 2006 compared to 33.1% in 2005. This increase reflected the significant increase in pretax income combined with the effect of comparable amounts of tax benefits such as amortization of investment tax credits, lignite depletion and the production deduction.

Income from continuing operations increased $198 million, or 57%, to $543 million in 2006 driven by improved gross margin, partially offset by a charge for the write-down of the natural gas-fired generation plants.

32

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Operating revenues increased $381 million, or 9%, to $4.5 billion in 2006. Retail electricity revenues increased $444 million, or 16%, to $3.3 billion.

·   The retail revenue increase reflected $795 million in higher pricing due to increased price-to-beat rates, reflecting regulatory-approved fuel factor increases in May and October 2005, and higher pricing in the competitive business market, both resulting from the effects of higher natural gas prices.

·   The effect of higher pricing due to increased price-to-beat rates was partially offset by a $351 million effect of lower retail volumes. Total retail sales volumes declined 12% reflecting a net loss of customers due to competitive activity and lower average consumption per customer in residential and small business markets. Large business market volumes declined 20% and residential and small business volumes fell by 9%. The large business market decline reflected a continuing strategy to improve margins.

·   Retail electricity customer counts at June 30, 2006 declined 6% from June 30, 2005. Total residential and small business customer counts in the historical service territory declined 8% and in all combined territories declined 6%.

Wholesale electricity revenues decreased $150 million to $982 million. The change reflects the reporting of wholesale power trading activity on a net basis. In addition, ERCOT balancing activity reported in wholesale electricity revenues totaled net sales of $26 million in 2006 and $66 million in 2005. The effects related to both the power trading and ERCOT balancing activities were partially offset by higher wholesale pricing and nontrading volumes. See Note 1 to Financial Statements.

The increase in other revenues of $19 million primarily reflects an increase in retail commercial and industrial natural gas revenues, driven by higher prices, and an increase in retail electric late fees driven by higher average customer bills.

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 $62 million in 2006 and net losses of $6 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:

·   $150 million in net unrealized cash flow hedge ineffectiveness gains largely associated with positions in the long-term hedging program;

·   $22 million in net realized gains primarily associated with positions in the long-term hedging program accounted for as cash flow hedges, the offsetting effects of which are reflected in electricity revenues;

·   $30 million in net realized losses associated with hedges entered into in prior years (largely 2003), the offsetting effects of which are reflected in electricity revenues and fuel and purchased power. This amount includes $19 million in losses related to positions that had been accounted for as cash flow hedges;

·   $31 million in reversals of previously recorded net unrealized gains on hedge positions (marked-to-market) that were settled in the current period, the offsetting effects of which are reflected in electricity revenues and fuel and purchased power costs;

·   $27 million in net unrealized losses primarily relating to hedge positions that are marked-to-market; and

·   $20 million in net realized losses on settlement of various commodity trading positions.

33

Gross Margin

	Six Months Ended June 30,
	2006		% of Revenue			2005		% of Revenue
Operating revenues	$	4,478		100	%	$	4,097		100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,733		38			2,338		57
Generation plant operating costs		307		7			331		8
Depreciation and amortization		166		4			154		4
Gross margin	$	2,272		51	%	$	1,274		31	%

Gross margin increased $998 million, or 78%, to $2.3 billion in 2006. This growth primarily reflected the relatively low fuel costs of the nuclear and lignite/coal-fired baseload plants, as well as overall higher baseload production, in an environment of higher wholesale prices. A 28% increase in wholesale power prices was driven by higher natural gas prices. Retail prices, including price-to-beat rates, were increased in response to higher wholesale prices. The gross margin performance was mitigated by the effect of lower retail sales volumes and higher purchased power prices.

Gross margin as a percent of revenues increased 20 percentage points to 51%. The improvement reflected:

·   higher pricing, as the average wholesale sales price per MWh rose 28%, and the average retail sales price per MWh rose 32% (15 percentage point margin increase); and

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

partially offset by an 18% increase in combined per MWh purchase power costs and fuel costs in gas/oil-fired generation, due to rising natural gas prices (two percentage point margin decrease).

Operating costs decreased $24 million, or 7%, to $307 million in 2006. The decrease reflected $29 million in lower maintenance costs largely due to the absence in 2006 of costs incurred in 2005 for the nuclear generation plant refueling outage, partially offset by $10 million in transition costs associated with generation outsourcing services agreements entered into in 2006.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) increased $13 million, or 8%, to $169 million reflecting higher expense associated with mining reclamation obligations.

SG&A expenses increased by $15 million, or 7%, to $242 million in 2006. The increase reflected:

·   $10 million in higher bad debt expense reflecting higher retail accounts receivable balances;

·   $8 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 $7 million in lower consulting fees primarily reflecting expenses in 2005 for the development and implementation of the TXU Operating System to improve productivity.

34

Other income totaled $1 million in 2006 and $8 million in 2005. Other deductions totaled $195 million in 2006, which included a $198 million impairment charge related to natural gas-fired generation plants, and $13 million in 2005. See Note 11 to Financial Statements for additional detail.

Interest income increased by $55 million to $76 million in 2006 reflecting $35 million due to higher average advances to affiliates and $20 million due to higher average rates.

Interest expense and related charges increased by $17 million, or 9%, to $202 million in 2006. The increase reflects $12 million due to higher average borrowings and $12 million due to higher average interest rates, partially offset by higher capitalized interest.

Income tax expense on income from continuing operations totaled $590 million in 2006 compared to $278 million in 2005. The 2005 amount reflected a charge of $10 million related to the settlement of the IRS audit for the 1994 to 1996 years. The 2006 amount included a charge of $42 million representing an adjustment to deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 3 to the Financial Statements. Excluding the impact of these items, the effective tax rate was 33.2% in 2006 compared to 32.4% in 2005. This increase resulted from the significant increase in pretax income combined with the effects of tax benefits such as amortization of investment tax credits, lignite depletion and the production deduction, which did not increase in proportion to pretax earnings.

Income from continuing operations increased $515 million, or 94%, to $1.1 billion in 2006 driven by improved gross margin, partially offset by a charge for the write-down of the natural gas-fired generation fleet.

35

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

The table below summarizes the changes incommodity contract assets and liabilities for the six months ended June 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 six months ended June 30, 2006, this effect totaled $2 million in unrealized net losses, which represented $24 million in net losses on open (unsettled) positions less $22 million in reversals of net losses recognized in prior periods on positions settled in the current period. These positions represent economic hedging and proprietary trading activities.

		Six Months
		Ended
		June 30, 2006
Net commodity contract liability at beginning of period	$	(56)
Settlements of positions included in the opening balance (1)		22
Unrealized mark-to-market valuations of positions held at end of period		(24)
Other activity (2)		(8)
Net commodity contract liability at end of period	$	(66)

__________________________

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

(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 $20 million of natural gas received related to physical swap transactions as well as $12 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					Six Months Ended
	June 30,					June 30,
	2006			2005		2006			2005
Unrealized gains/(losses) related to contracts marked-to-market	$	(8	)	$	39	$	(2	)	$	12
Ineffectiveness gains related to cash flow hedges (a)		151			3		150			6
Total unrealized gains related to commodity contracts	$	143		$	42	$	148		$	18

__________________________

(a) See Note 10 to Financial Statements.

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

36

Maturity Table— Included in the net commodity contract liability above at June 30, 2006 is a net asset of $34 million representing cumulative unrealized mark-to-market net gains that have been recognized in current and prior years’ earnings. More than offsetting this net asset is a net liability of $100 million included in the June 30, 2006 balance sheet that is comprised principally of amounts representing current and prior years’ net receipts of cash or other consideration, including $97 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 asset arising from mark-to-market accounting as of June 30, 2006, scheduled by contractual settlement dates of the underlying positions.

	Maturity dates of unrealized net commodity contract assets (liabilities) at June 30, 2006
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	103		$	30		$	9		$	─		$	142
Prices provided by other
external sources		(127	)		20			(18	)		─			(125	)
Prices based on models		17			─			─			─			17
Total	$	(7	)	$	50		$	(9	)	$	─		$	34
Percentage of total fair value		(21	)%		147	%		(26	)%		─	%		100	%

As the above table indicates, all of the net unrealized mark-to-market valuation gains at June 30, 2006 mature within five 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 and natural gas generally extend through 2010 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 June 30,						Six Months Ended June 30,
	2006			2005			2006		2005
Net increase (decrease) in fair value of cash flow hedges (all commodity) held
at end of period	$	(74	)	$	(2	)	$	39	$	13
Derivative value net losses related to hedged transactions settled during the period and reported in net income:
Commodities		10			17			7		33
Financing - interest rate swaps		2			1			3		2
		12			18			10		35
Total income (loss) effect of cash flow hedges reported in other comprehensive
income related to continuing operations	$	(62	)	$	16		$	49	$	48

TXU Energy Holdings 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 settled and affect 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 six months ended June 30, 2006 totaled $2.1 billion for an increase of $1.6 billion over the six months ended June 30, 2005. The improvement reflected higher operating earnings after taking into account noncash charges and credits identified in the Condensed Statements of Consolidated Cash Flows as well as:

·   a favorable change in income taxes payable of approximately $770 million primarily driven by net operating losses arising from the expected reporting on the 2005 federal income tax return of a market value loss related to a power sales agreement; and

·   a favorable change of $176 million in working capital (accounts receivable, accounts payable and inventories) principally reflecting higher wholesale gas receivables in 2005, due to higher natural gas prices and sales volumes, as well as increased proceeds from the accounts receivable sales program in 2006.

Cash flows provided by financing activities declined $533 million as summarized below:

	Six Months Ended June 30,
	2006			2005
Inflow from net issuances, repurchases and repayments of borrowings	$	648		$	969
Decrease in note payable to TXU Electric Delivery		(22	)		(32	)
Distributions paid to parent		(572	)		(350	)
Total	$	54		$	587

Cash flows used in investing activities increased $1.1 billion as summarized below:

	Six Months Ended June 30,
	2006			2005
Capital expenditures, including nuclear fuel	$	(248	)	$	(161	)
Deposit of proceeds from pollution control revenue bonds with trustee		(99	)		―
Net investments in nuclear decommissioning trust fund securities		(7	)		(7	)
Advances to affiliates		(1,803	)		(934	)
Other		2			―
Total	$	(2,155	)	$	(1,102	)

Capital expenditures in 2006 include approximately $30 million of spending related to the new generation development program.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $33 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.

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

	Issuances		Retirements
Pollution control revenue bonds	$	100	$	203
Senior notes		―		400
Total	$	100	$	603

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

39

Credit Facilities— At July 25, 2006, TXU Energy Holdings, jointly with TXU Electric Delivery, had access to credit facilities totaling $6.5 billion of which $4.1 billion was unused. The facilities expire on various dates between May 2007 and June 2010. TXU Energy Holdings 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 for 2006 are expected to total approximately $570 million primarily for maintenance and upgrades of generation assets.

Short-term Borrowings — At July 25, 2006, TXU Energy Holdings had $1.0 billion of commercial paper outstanding and $940 million of borrowings under the credit facilities. The commercial paper funds short-term liquidity requirements.

Sale of Accounts Receivable— TXU Energy Holdings 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 Holdings sell trade accounts receivable to TXU Receivables Company, a 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 Holdings are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding to TXU Energy Holdings under the program totaled $608 million at June 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 in termination of the program.

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

·   $54 million in cash has been received from counterparties as collateral;

·   $70 million in cash has been posted with counterparties as collateral; and

·   $971 million in letters of credit have been posted as collateral by TXU Energy Holdings including $500 million to support a related series of hedge transactions entered into by TXU DevCo in June 2006. (See discussion above under “Recent Developments”.)

With respect to collateral received, TXU Energy Holdings 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 Holdings 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 Holdings’ liquidity.

With respect to hedging positions under the program as of July 14, 2006, for each $1.00 per MMBtu increase in natural gas prices, TXU Energy Holdings could be required to post up to approximately $900 million in additional collateral and/or financial margining. Transactions requiring daily margining account for approximately 80% of the total hedge program and are generally met by cash postings. For the remainder, collateral settlements are being met by a combination of letters of credit and cash postings as required periodically by counterparties.

40

Asset Transfer— In the second quarter of 2006, TXU Energy Holdings transferred its mineral interests in natural gas and oil to TXU Corp. at book value, which was zero. These mineral interests were acquired as part of land purchases over the years to support generation activities and not for the mineral development, and no value was attributed to the mineral interests at the time of acquisition. The fair value of these interests has not been determined. TXU Corp. is currently exploring potential initiatives with respect to the interests.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions— The terms of certain financing arrangements of TXU Energy Holdings contain financial covenants that require maintenance of specified fixed charge coverage ratios and leverage ratios and/or contain minimum net worth covenants. As of June 30, 2006, TXU Energy Holdings 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 Holdings
	(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 Holdings and TXU Electric Delivery. Fitch’s outlook is negative for TXU Corp., US Holdings and TXU Energy Holdings and stable for TXU Electric Delivery. S&P’s outlook is negative for TXU Corp., US Holdings, TXU Energy Holdings 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 Holdings and TXU Electric Delivery has been 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 Holdings 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 Holdings’ credit rating to below investment grade, a letter of credit of approximately $104 million at June 30, 2006 would need to be provided within 30 days of any such rating decline.

Under the terms of a rail car lease with $52 million in remaining lease payments (principal amount as of June 30, 2006), if TXU Energy Holdings’ credit rating were downgraded to below investment grade by any specified rating agency, TXU Energy Holdings 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 Holdings has entered into certain commodity contracts that in some instances give the other party the right, but not the obligation, to request TXU Energy Holdings to post collateral in the event that its credit rating falls below investment grade. Based on its commodity contract positions at June 30, 2006, in the event TXU Energy Holdings 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 Holdings to post $87 million in additional collateral requirements. Should TXU Energy Holdings be downgraded two levels below investment grade, counterparties would have the option to request additional collateral of up to approximately $43 million. The amount TXU Energy Holdings could be required to post under these transactions depends in part on the value of the contracts at the time of any downgrade.

41

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 Holdings’ credit rating were downgraded to below investment grade by any specified rating agency, TXU Energy Holdings could be required to post collateral of approximately $34 million as of June 30, 2006.

Other arrangements of TXU Energy Holdings, 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 Holdings.

Material Cross Default Provisions

Certain financing arrangements contain provisions that would result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.

A default by TXU Energy Holdings or TXU Electric Delivery or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million would result in a cross default under joint credit facilities totaling $4.5 billion. Under these credit facilities, a default by TXU Energy Holdings or any subsidiary thereof would cause the maturity of outstanding balances under such facility to be accelerated as to TXU Energy Holdings but not as to TXU Electric Delivery. Also, under these credit facilities, a default by TXU Electric Delivery or any subsidiary thereof would cause the maturity of outstanding balances under such facility to be accelerated as to TXU Electric Delivery but not as to TXU Energy Holdings.

In addition, a default by TXU Energy Holdings 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 cause the maturity of outstanding balances (none as of June 30, 2006) under such facility to be accelerated.

The accounts receivable securitization program (see Note 5 to Financial Statements) 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 or TXU Receivables Company defaults on indebtedness of the applicable threshold, the facility could terminate.

TXU Energy Holdings 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 Holdings 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 Holdings’ 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 $470 million and in the more than five year period increased $326 million.

42

OFF BALANCE SHEET ARRANGEMENTS

Subsidiaries ofTXU Energy Holdings 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

During 2006, TXU Energy Holdings’ 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.

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 Holdings 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 have 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 Holdings and certain members of the retail market coalition oppose these proposed revisions. Final disposition of the proposed revisions is currently unknown. Although certain Texas legislators asked the Governor to open the Texas Legislature’s special session, which commenced in April 2006, to the issue of electricity prices, the session closed with no changes to the market structure or the price-to-beat statute.

On June 29, 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 that will prevent the POLR price from interfering with competitive market prices.

43

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 this summer;

·   Elderly low-income customers who contact their electric provider will also not be disconnected through September 30, 2006, regardless of whether the customer makes payments for electricity use, though the Commissioners encouraged customers to pay as much as they can to avoid building up significant unpaid balances. These customers will be entitled to enter into a deferred payment arrangement with 25% of their balance due in October and the balance of the deferred bills paid over the next five months;

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

These actions are expected to result in increased bad debt expenses, but the estimated amounts are not expected to be material to the results of TXU Energy Holdings.

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 Holdings’ 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 Holdings’ annual state franchise tax expense by approximately $40 million beginning in 2007. Also see Note 3 to Financial Statements.

The property tax relief law is expected to reduce school taxes assessed to TXU Energy Holdings 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).

44

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 and that this market design is to be implemented on or about January 1, 2009. 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 Holdings) 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 held a hearing on ERCOT’s application on July 21, 2006 but has not yet issued a final decision on ERCOT’s surcharge application. At this time, TXU Energy Holdings is unable to predict the impact of the proposed nodal wholesale market design on its operations or financial results.

Summary— Although TXU Energy Holdings 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

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 Holdings is currently evaluating the potential impact of this standard.

45

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Market risk is the risk that TXU Energy Holdings may experience a loss in value as a result of changes in market conditions affecting commodity prices and interest rates, which TXU Energy Holdings is exposed to in the ordinary course of business. TXU Energy Holdings’ 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 Holdings 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 Holdings’ 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 Holdings 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 Holdings’ 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 Holdings’ 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 Holdings 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 Holdings 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 “Recent Developments” for an update of the program, including potential effects on reported results.

46

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.

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 Holdings 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 Holdings may add or eliminate other metrics in the future in its disclosures of risks.

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. Assumptions in determining this VaR include using a 95% confidence level and a holding period ranging from five to 60 days (based on the forward tenor). A probabilistic simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio’s value based on assumed market conditions for liquid markets.

		June 30,		December 31,
		2006		2005
Period-end MtM VaR	$	13	$	19
Average Month-end MtM VaR	$	11	$	20

Earnings at Risk (EaR) — EaR measures the estimated potential reduction of expected pretax earnings for the year presented due to changes in market conditions. EaR metrics include the owned generation assets, estimates of retail load, all contractual positions that are marked-to-market in net income and positions not marked-to-market in net income that are expected to be settled within the fiscal year. For this purpose, cash flow hedges are included with transactions that are not marked-to-market in net income. Assumptions include using a 95% confidence level and a holding period ranging from five to 60 days (based on forward tenor) under normal market conditions.

		June 30,		December 31,
		2006		2005
EaR	$	22	$	32

INTEREST RATE RISK

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

47

CREDIT RISK

Credit Risk— Credit risk relates to the risk of loss associated with nonperformance by counterparties. TXU Energy Holdings 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 agreements that allow for netting of positive and negative exposures associated with a single counterparty. TXU Energy Holdings 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 Holdings or its subsidiaries. Additionally, TXU Energy Holdings 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 Holdings’ gross exposure to credit risk, which totaled approximately $2 billion at June 30, 2006, represents trade accounts receivable, as well as net asset positions arising from commodity hedging and trading activities.

Gross assets subject to credit risk include approximately $800 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 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. The exposure to credit risk from these customers and counterparties, excluding credit collateral, as of June 30, 2006, is $1.2 billion net of standardized master netting contracts and agreements that provide the right of set-off of positive and negative credit exposures with individual customers and counterparties. When considering collateral currently held by TXU Energy Holdings’ subsidiaries (cash, letters of credit and other security interests), the net credit exposure is $1 billion. Of this amount, 81% of the associated exposure is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and TXU Energy Holdings’ 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 Holdings routinely monitors and manages its credit exposure to these customers and counterparties on this basis.

TXU Energy Holdings 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 stable outlook for Cap Gemini S. A.

48

 The following table presents the distribution of credit exposure as of June 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	$	946		$	154		$	792		$	521	$	125	$	146	$	792
Noninvestment grade		246			55			191			159		22		10		191
Totals	$	1,192		$	209		$	983		$	680	$	147	$	156	$	983
Investment grade		79	%		74	%		81	%
Noninvestment grade		21	%		26	%		19	%

 TXU Energy Holdings’ subsidiaries are exposed to credit risk related to its long-term hedging program. Of the transactions in the program, over 96% of the volumes are with counterparties with an A credit rating or better, and 99% are at least investment grade.

TXU Energy Holdings had credit exposure to two counterparties having an exposure greater than 10% of the net exposure of $983 million at June 30, 2006. These two counterparties represented 15% and 11%, respectively, of the net exposure. TXU Energy Holdings views its exposure with these two counterparties to be within an acceptable level of risk tolerance. Additionally, approximately 69% of the credit exposure, net of collateral held, has a maturity date of two years or less. TXU Energy Holdings does not anticipate any material adverse effect on its financial position or results of operations due to nonperformance by any customer or counterparty.

49

FORWARD-LOOKING STATEMENTS

This report and other presentations made by TXU Energy Holdings 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 Holdings 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 Holdings’ 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 Holdings 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 Holdings 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 Holdings’ 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 Holdings’ 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 Holdings’ financial instruments;

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

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

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

·   actions by credit rating agencies; and

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

50

Any forward-looking statement speaks only as of the date on which it is made, and TXU Energy Holdings 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 Holdings 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 Holdings’ 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 Holdings’ 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 Holdings’ internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, TXU Energy Holdings’ internal control over financial reporting.

51

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 report on Form 10-Q for the quarterly period ended March 31, 2006 (“March 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 and March 2006 10-Q.

TXU Energy Holdings’ retail business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or results of operations of the retail business.

TXU Energy Holdings’ retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. The retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. A security breach may occur, despite security measures taken by the retail business and required of vendors. If a significant or widely publicized breach occurred, the reputation of the retail business may be adversely affected, customer confidence may be diminished, or the retail business may be subject to legal claims, any of which may contribute to customer attrition and have a negative impact on the business and/or results of operations of the retail business.

52

ITEM 6.    EXHIBITS

(a)     Exhibits provided as part of Part II are:
Exhibits	Previously Filed With File Number*	As Exhibit
	Material Contracts.
	Credit Agreements.
10(a)	333-108876 Form 8-K (filed June 2, 2006)	10.1		$1.5 Billion Revolving Credit Agreement, dated May 26, 2006, by and among TXU Energy Company LLC, certain lenders parties thereto, Credit Suisse, Cayman Islands Branch, as administrative agent, and as fronting bank, and Lehman Brothers Bank, as fronting bank.
	Other Material Contracts.
10(b)	1-12833 Form 10-Q (filed August 7, 2006)	10(k)		Confirmation Agreement by TXU Generation Development Company LLC, dated June 6, 2006 (confidential treatment has been requested for portions of this exhibit).
(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 June 30, 2006.

* Incorporated herein by reference.

53

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
	Senior Vice President and Controller

Date: August 11, 2006