Energy Future (TXU) 10-Q 2006 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006

— OR —

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-12833

TXU Corp.

(Exact Name of Registrant as Specified in its Charter)

Texas	75-2669310
(State of Incorporation)	(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  x    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  x    Accelerated filer  ¨    Non-Accelerated filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Common Stock outstanding at November 6, 2006: 459,240,549 shares, without par value.

TABLE OF CONTENTS

		PAGE
GLOSSARY		ii
PART I.	FINANCIALINFORMATION
Item 1.	Financial Statements
	Condensed Statements of Consolidated Income – Three and Nine Months Ended September 30, 2006 and 2005	1
	Condensed Statements of Consolidated Comprehensive Income – Three and Nine Months Ended September 30, 2006 and 2005	2
	Condensed Statements of Consolidated Cash Flows – Nine Months Ended September 30, 2006 and 2005	3
	Condensed Consolidated Balance Sheets – September 30, 2006 and December 31, 2005	5
	Notes to Condensed Consolidated Financial Statements	6
	Report of Independent Registered Public Accounting Firm	33
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	78
Item 4.	Controls and Procedures	83
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	84
Item 1A.	Risk Factors	84
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	85
Item 4.	Submission of Matters to a Vote of Security Holders	85
Item 6.	Exhibits	86
SIGNATURE		88

TXU Corp. 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 Corp. 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 Corp.’s Annual Report on Form 10-K for the year ended December 31, 2005
Capgemini	Capgemini Energy LP, a subsidiary of Cap Gemini North America Inc. that provides business support services to TXU Corp. and its subsidiaries
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
ERISA	Employee Retirement Income Security Act
FASB	Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting
FERC	US Federal Energy Regulatory Commission
FIN	Financial Accounting Standards Board Interpretation
FIN 45	FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others – An Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34”
FIN 46R	FIN No. 46R (Revised 2003), “Consolidation of Variable Interest Entities”
FIN 48	FIN No. 48, “Accounting for Uncertainty in Income Taxes”
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
FSP AUG AIR-1	FASB Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities”
GW	gigawatts
GWh	gigawatt-hours

ii

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)
MW	megawatts
MWh	megawatt-hours
NRC	US Nuclear Regulatory Commission
price-to-beat rate	residential and small business customer electricity rates established by the Commission that (i) were required to be charged in a REP’s historical service territories until the earlier of January 1, 2005 or the date when 40% of the electricity consumed by such customer classes is supplied by competing REPs, adjusted periodically for changes in fuel costs, and (ii) are required to be made available to those customers until January 1, 2007
PURA	Texas Public Utility Regulatory Act
reference plants	eight new power generation units to be built by subsidiaries of TXU Corp. with a proprietary standardized “reference” plant design and construction planning process
REP	retail electric provider
S&P	Standard & Poor’s Ratings Services, a division of the McGraw Hill Inc. Companies (a credit rating agency)
SEC	US Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards issued by the FASB
SFAS 87	SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 88	SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and Termination Benefits”
SFAS 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 132R	SFAS No. 132R (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted

iii

SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement 125”
SFAS 144	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 158	SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”
SG&A	selling, general and administrative
Short-cut method	refers to the short-cut method under SFAS 133 that allows entities to assume no hedge ineffectiveness in a hedging relationship of interest rate risk if certain conditions are met
TCEQ	Texas Commission on Environmental Quality
TXU Big Brown	TXU Big Brown Company LP, a Texas limited partnership and subsidiary of TXU Energy Company, which owns two lignite/coal-fired generation units in Texas
TXU Corp.	Refers to TXU Corp., a holding company, and/or its consolidated subsidiaries, depending on context. This Form 10-Q and other SEC filings of TXU Corp. and its subsidiaries occasionally make references to TXU Corp., TXU Energy Company or TXU Electric Delivery when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company.
TXU DevCo	Refers to TXU Generation Development Company LLC, a Delaware limited liability company and holding company subsidiary of TXU Corp., which has been established for the purpose of developing and constructing new lignite/coal-fired generation facilities in Texas. While an affiliate of TXU Energy Company, TXU DevCo is not a subsidiary of, or a parent company to, TXU Energy Company
TXU Electric Delivery	Refers to TXU Electric Delivery Company, a subsidiary of TXU Corp., and/or its consolidated bankruptcy remote financing subsidiary, TXU Electric Delivery Transition Bond Company LLC, depending on context. This Form 10-Q and other SEC filings of TXU Corp. and its subsidiaries occasionally make references to TXU Corp., TXU Energy Company or TXU Electric Delivery when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company.

iv

TXU Energy Company	Refers to TXU Energy Company LLC, a subsidiary of TXU Corp., and/or its consolidated subsidiaries, depending on context, engaged in electricity generation and wholesale and retail energy markets activities. This Form 10-Q and other SEC filings of TXU Corp. and its subsidiaries occasionally make references to TXU Corp., TXU Energy Company or TXU Electric Delivery when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company.
TXU Energy Holdings	Refers to the TXU Corp. business segment that includes TXU Energy Company, TXU DevCo, activities of other TXU Corp. development subsidiaries to identify opportunities for generation development in markets outside Texas and a lease trust holding certain combustion turbines.
TXU Energy Retail	Refers to TXU Energy Retail Company LP, a subsidiary of TXU Energy Company engaged in the retail sale of power to residential and business customers.
TXU Europe	TXU Europe Limited, a former subsidiary of TXU Corp.
TXU Gas	TXU Gas Company, a former subsidiary of TXU Corp.
TXU Portfolio Management	TXU Portfolio Management Company LP, a subsidiary of TXU Energy Company
US	United States of America
US GAAP	accounting principles generally accepted in the US
US Holdings	TXU US Holdings Company, a subsidiary of TXU Corp. and parent of TXU Energy Company

v

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

TXU CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(millions of dollars, except per share amounts)
Operating revenues	$	3,510		$	3,314		$	8,481		$	7,907
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,002			1,449			2,182			3,169
Operating costs		334			345			1,018			1,039
Depreciation and amortization		216			203			628			580
Selling, general and administrative expenses		211			200			582			559
Franchise and revenue-based taxes		102			93			276			258
Other income (Note 14)		(36	)		(35	)		(91	)		(104	)
Other deductions (Note 14)		23			11			244			49
Interest income		(10	)		(16	)		(30	)		(35	)
Interest expense and related charges (Note 16)		209			207			640			591
Total costs and expenses		2,051			2,457			5,449			6,106
Income from continuing operations before income taxes		1,459			857			3,032			1,801
Income tax expense		475			286			1,036			441
Income from continuing operations		984			571			1,996			1,360
Income (loss) from discontinued operations, net of tax effect (Note 3)		20			(6	)		81			6
Net income	$	1,004		$	565		$	2,077		$	1,366
Preference stock dividends		—			—			—			10
Net income available to common shareholders	$	1,004		$	565		$	2,077		$	1,356
Average shares of common stock outstanding (millions):
Basic		459			478			460			477
Diluted		466			489			469			487
Per share of common stock - Basic:
Net income from continuing operations available for common stock	$	2.15		$	1.19		$	4.33		$	2.84
Discontinued operations, net of tax effect		0.04			(0.01	)		0.18			0.01
Net income available for common stock	$	2.19		$	1.18		$	4.51		$	2.85
Per share of common stock – Diluted:
Net income from continuing operations available for common stock	$	2.11		$	1.17		$	4.26		$	1.75
Discontinued operations, net of tax effect		0.04			(0.01	)		0.17			0.01
Net income available for common stock	$	2.15		$	1.16		$	4.43		$	1.76
Dividends declared	$	0.413		$	0.282		$	1.239		$	0.844

See Notes to Financial Statements.

1

TXU CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
	(millions of dollars)
Components related to continuing operations:
Income from continuing operations	$	984	$	571		$	1,996	$	1,360
Other comprehensive income (loss):
Cash flow hedges:
Net change in fair value of derivatives held at end of period (net of tax (expense) benefit of ($216), $38, ($232) and $31) (See Note 12)		401		(71	)		431		(58	)
Derivative value net losses reported in net income that relate to hedged transactions recognized in the period (net of tax benefit of $6, $11, $12 and $33)		11		18			22		59
Total effect of cash flow hedges		412		(53	)		453		1
Comprehensive income from continuing operations		1,396		518			2,449		1,361
Comprehensive income (loss) from discontinued operations		20		(6	)		81		6
Comprehensive income	$	1,416	$	512		$	2,530	$	1,367

See Notes to Financial Statements.

2

TXU CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2006			2005
	(millions of dollars)
Cash flows – operating activities:
Income from continuing operations	$	1,996		$	1,360
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		676			627
Deferred income tax expense, including utilization of net operating loss carryforwards		712			99
Net effect of unrealized mark-to-market valuations		(214	)		87
Impairment of natural gas-fired generation plants		198			—
Bad debt expense		53			37
Net gains on sale of assets, including amortization of deferred gains		(46	)		(48	)
Stock-based incentive compensation expense		17			24
Litigation settlement insurance recovery		(15	)		—
Net equity loss from unconsolidated affiliate		10			—
Amortization of losses on dedesignated cash flow hedges		9			18
Amortization of gain on dedesignated fair value hedges		(6	)		(8	)
Asset writedown charges		6			—
Charge (credit) related to impaired leases		2			(12	)
Change in regulatory-related liabilities		—			(60	)
Charge related to coal contract counterparty claim		—			12
Changes in operating assets and liabilities		647			(81	)
Cash provided by operating activities from continuing operations		4,045			2,055
Cash flows – financing activities:
Issuances of securities:
Long-term debt		100			71
Common stock		180			6
Retirements/repurchases of securities:
Equity-linked debt		(179	)		(31	)
Long-term debt		(1,368	)		(236	)
Common stock		(1,012	)		(548	)
Preference stock		—			(300	)
Preferred stock of subsidiary		—			(38	)
Change in short-term borrowings:
Commercial paper		617			—
Banks		(145	)		390
Cash dividends paid:
Common stock		(575	)		(408	)
Preference stock		—			(11	)
Excess tax benefit on stock-based incentive compensation		47			28
Debt premium, discount, financing and reacquisition expenses		(17	)		(35	)
Cash used in financing activities from continuing operations	$	(2,352	)	$	(1,112	)

See Notes to Financial Statements.

3

TXU CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Continued)

(Unaudited)

	Nine Months Ended September 30,
	2006			2005
	(millions of dollars)
Cash flows – investing activities:
Capital expenditures	$	(1,409	)	$	(735	)
Nuclear fuel		(77	)		(57	)
Proceeds from sale of assets		15			76
Purchase of lease trust		(69	)		—
Proceeds from pollution control revenue bonds deposited with trustee		(99	)		—
Proceeds from sales of nuclear decommissioning trust fund securities		165			127
Investments in nuclear decommissioning trust fund securities		(177	)		(138	)
Investment in unconsolidated affiliate		(15	)		—
Costs to remove retired property		(33	)		(34	)
Other		(6	)		7
Cash used in investing activities from continuing operations		(1,705	)		(754	)
Discontinued operations:
Cash used in operating activities		(1	)		(37	)
Cash used in investing activities		—			(3	)
Cash used in discontinued operations		(1	)		(40	)
Net change in cash and cash equivalents		(13	)		149
Cash and cash equivalents – beginning balance		37			106
Cash and cash equivalents – ending balance	$	24		$	255

See Notes to Financial Statements.

4

TXU CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2006		December 31, 2005
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	24	$	37
Restricted cash		60		54
Trade accounts receivable — net		1,123		1,328
Income taxes receivable		—		14
Inventories		380		364
Commodity contract assets		428		1,603
Cash flow hedge and other derivative assets		680		65
Accumulated deferred income taxes		254		717
Margin deposits related to commodity positions		30		247
Other current assets		201		129
Total current assets		3,180		4,558
Restricted cash		118		16
Investments		690		643
Property, plant and equipment — net		18,044		17,192
Goodwill		542		542
Regulatory assets — net		1,759		1,826
Commodity contract assets		167		338
Cash flow hedge and other derivative assets		219		75
Other noncurrent assets		388		349
Total assets	$	25,107	$	25,539
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	1,270	$	798
Long-term debt due currently		390		1,250
Trade accounts payable		908		1,026
Commodity contract liabilities		509		1,481
Cash flow hedge and other derivative liabilities		52		275
Margin deposits related to commodity positions		721		357
Other current liabilities		1,076		1,163
Total current liabilities		4,926		6,350
Accumulated deferred income taxes		4,110		3,697
Investment tax credits		369		384
Commodity contract liabilities		245		516
Cash flow hedge and other derivative liabilities		101		91
Long-term debt, less amounts due currently		10,721		11,332
Other noncurrent liabilities and deferred credits		2,939		2,694
Total liabilities		23,411		25,064
Commitments and Contingencies (Note 9)
Shareholders’ equity (Note 8):
Common stock without par value: Authorized shares: 1,000,000,000 Outstanding shares: 459,240,459 and 470,845,978		5		5
Additional paid-in capital		1,096		1,840
Retained earnings (deficit)		344		(1,168	)
Accumulated other comprehensive income (loss)		251		(202	)
Total shareholders’ equity		1,696		475
Total liabilities and shareholders’ equity	$	25,107	$	25,539

See Notes to Financial Statements.

5

TXU CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS

Description of Business— TXU Corp. is a holding company whose operations are conducted principally through TXU Electric Delivery and subsidiaries of TXU Energy Company. TXU Energy Company is a holding company whose subsidiaries are engaged in electricity generation, residential and business retail electricity sales as well as wholesale energy markets activities primarily in Texas. TXU Electric Delivery is engaged in regulated electricity transmission and distribution operations in Texas. TXU DevCo and its subsidiaries are engaged in the development of new lignite/coal-fired generation facilities in Texas.

TXU Corp. has two reportable segments: the TXU Energy Holdings segment (which includes TXU DevCo’s activities) and the TXU Electric Delivery segment. (See Note 13 for further information concerning reportable business segments.)

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

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

6

Also, as previously disclosed, TXU Corp. 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 Corp. 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 Corp.’s generation increasingly exceeding its retail load, the net balancing activity has more recently generally resulted in net sales of power. TXU Corp. believes that presentation of this activity as a component of revenues more appropriately reflects TXU Corp.’s market position. Accordingly, consistent with reporting for the first and second quarters of 2006, net power balancing transactions are reported in revenues and the prior years’ amounts have been reclassified. The amount reported in revenues for the third quarter and year-to-date periods of 2006 totaled $32 million and $6 million in net purchases, respectively. The amounts reclassified for the third quarter and year-to-date periods of 2005 totaled $123 million and $189 million in net sales, respectively.

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

Stock Split — All common stock share and per share amounts reflect a two-for-one stock split completed in December 2005.

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

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

Purchase of Lease Trust Interest —As previously disclosed, in December 2005 a subsidiary of TXU Corp. entered into an agreement to purchase, for $69 million in cash, the owner participant interest in a trust established to lease combustion turbines to another subsidiary of TXU Corp. The trust is a variable interest entity, and in accordance with FIN 46R, the trust was consolidated at December 31, 2005, with the trust’s combustion turbine assets and related debt recorded at estimated fair market values of $35 million and $96 million, respectively. The transaction was closed on March 31, 2006. In the fourth quarter of 2005, TXU Corp. recorded an extraordinary loss of $50 million (net of a $28 million tax benefit) for the excess of the purchase price over the fair value of the trust’s net assets, net of the reversal of a previously established liability of $59 million related to the combustion turbine lease.

7

Earnings Per Share —Basic earnings per share available to common shareholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share include the effect of all potential issuances of common shares under stock-based incentive compensation arrangements and certain debt securities.

Year-to-date 2005 diluted earnings per share were reduced by $1.02 due to certain effects of the November 2004 accelerated share repurchase program. In November 2004, TXU Corp. entered into an agreement with a broker-dealer counterparty under which TXU Corp. repurchased and retired 105 million shares of its outstanding common stock for an initial price totaling $3.4 billion. Under the agreement, the counterparty immediately borrowed shares that were sold to and canceled by TXU Corp. and in turn purchased shares in the open market over a subsequent time period. The agreement was therefore subject to a contingent purchase price adjustment based on the actual price of the shares purchased by the counterparty. Because TXU Corp. intended to settle in cash the difference between the initial price of the shares and the actual costs of the shares purchased by the counterparty under the program (the true-up), accounting rules require that earnings used in the diluted earnings per share calculation be reduced by the change in the estimated fair value of the true-up liability. In May 2005, TXU Corp. paid $523 million (including related fees and expenses) in cash to the counterparty in full settlement of the transaction. The counterparty had repurchased the shares at an average price per share of $36.91.

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

Also, in September 2006, the FASB issued SFAS 158, which will be effective December 31, 2006 for TXU Corp. SFAS 158 revises SFAS 87, 88, 106 and 132(R) and requires reporting in the balance sheet of the funded status of defined benefit pension and other postretirement employee benefit (OPEB) plans. For TXU Corp., the initial recognition of the funded status on the financial statements is expected to be largely reflected as an increase in the defined benefit obligation and an increase in regulatory assets. The recording of a regulatory asset, instead of a reduction in the accumulated other comprehensive income component of shareholders’ equity as set forth in SFAS 158, is based on the regulatory recovery of retirement benefits under the June 2005 amendment to PURA discussed in Note 10. SFAS 158 does not change the measurement or reporting of net periodic benefit costs in the income statement.

Following is an indicative estimate of the effect on the consolidated balance sheet of the adoption of SFAS 158 based on a December 31, 2005 measurement:

	Increase (Decrease) to September 30, 2006 Balances
Noncurrent assets:
Regulatory assets – net	$	514
Noncurrent liabilities:
Accumulated deferred income taxes	$	(20	)
Defined benefit pension and OPEB obligation	$	554
Shareholders’ equity:
Accumulated other comprehensive income	$	(20	)

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

8

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

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 Corp. is currently evaluating the potential impact of this standard.

2. IMPAIRMENT OF NATURAL GAS-FIRED GENERATION PLANTS

As previously disclosed, TXU Corp. performed an evaluation of its natural gas-fired generation plants for impairment in accordance with the requirements of SFAS 144, which provides that long-lived assets should be tested for recovery whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In consideration of the new lignite/coal-fired generation plant development program, among other factors, TXU Corp. determined that it was more likely than not that its gas-fired generation plants, which have generally been operated to meet peak demands for power, would be sold or otherwise disposed of before the end of their previously estimated useful lives and should be tested for impairment as an asset group. As a result, it was determined that an impairment existed, and a charge of $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 and included in the results of the TXU Energy Holdings segment.

3. DISCONTINUED OPERATIONS

Results from discontinued operations in 2006 include a $20 million ($31 million pretax) credit recorded in the third quarter representing an insurance recovery associated with the 2005 TXU Europe settlement agreement. Results in 2006 also included a net $60 million benefit recorded in the first quarter, substantially all of which represented a reversal of a TXU Gas income tax reserve due to favorable resolution of an IRS audit matter relating to a business sold in 2000. (Also see discussion in Note 9 under “Income Tax Contingencies.”)

Results from discontinued operations in 2005 totaled $6 million in after-tax expense in the third quarter and a net after-tax credit of $6 million year-to-date. The amounts in both periods included adjustments to the sales price of the TXU Gas business, which was disposed of in October 2004, arising from changes in estimates of working capital sold. The amounts in both periods also included the results of a discontinued business as presented below.

9

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

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

4. TAX BENEFIT RELATED TO TXU EUROPE

A net income tax expense of $441 million for the nine months ended September 30, 2005 includes $138 million in additional tax benefit recorded in the first quarter of 2005 related to the 2002 TXU Europe worthlessness deduction. The tax benefit reflects identification of tax planning strategies TXU Corp. would implement to ensure utilization of capital losses associated with the write-off of the investment in TXU Europe. Also see Note 9 regarding income tax contingencies.

5. TEXAS MARGIN TAX

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

In accordance with the provisions of SFAS 109, which require that deferred tax assets and liabilities be adjusted for the effects of new income tax legislation in the period of enactment, TXU Corp. estimated and recorded a net charge to deferred tax expense of $41 million in the second quarter of 2006, essentially all of which was reported in the TXU Energy Holdings segment. 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 Corp. 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 Corp. will monitor these developments and make appropriate changes to its estimate.

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6. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables — Subsidiaries of TXU Corp. participate in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of TXU Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities). The current program is subject to renewal in June 2008.

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

All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, 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 the originators for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originators that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is eliminated in consolidation, was $664 million and $201 million at September 30, 2006 and December 31, 2005, respectively.

The discount from face amount on the purchase of receivables principally funds program fees paid by TXU Receivables Company to the funding entities. The discount also funds a servicing fee paid by TXU Receivables Company to TXU Business Services Company, a direct subsidiary of TXU Corp. The program fees, also referred to as losses on sale of the receivables under SFAS 140, consist primarily of interest costs on the underlying financing and totaled $29 million and $14 million for the nine-month periods ending September 30, 2006 and 2005, respectively, and averaged 5.7% and 3.4% (on an annualized basis) of the funding under the program for the first nine months of 2006 and 2005, respectively. The servicing fee, which totaled approximately $3 million for the first nine months of both 2006 and 2005 compensates TXU Business Services Company for its services as collection agent, including maintaining the detailed accounts receivable collection records. The program fees represent essentially all the net incremental costs of the program on a consolidated basis and are reported in SG&A expenses.

The accounts receivable balance reported in the September 30, 2006 consolidated balance sheet includes $1,364 million face amount of trade accounts receivable of TXU Energy Company and TXU Electric Delivery sold to TXU Receivables Company, such amount having been reduced by $700 million of undivided interests sold by TXU Receivables Company. Funding under the program increased $29 million for the nine months ended September 30, 2006 and increased $226 million for the nine months ended September 30, 2005. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.

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

	Nine Months Ended September 30,
	2006			2005
Cash collections on accounts receivable	$	6,150		$	5,298
Face amount of new receivables purchased		(6,642	)		(5,601	)
Discount from face amount of purchased receivables		32			17
Program fees paid		(29	)		(14	)
Servicing fees paid		(3	)		(3	)
Increase in subordinated notes payable		463			77
Operating cash flows provided to TXU Corp. under the program	$	(29	)	$	(226	)

Upon termination of the program, cash flows to TXU Corp. 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.

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Trade Accounts Receivable —

	September 30, 2006			December 31, 2005
Gross trade accounts receivable	$	1,855		$	2,035
Undivided interests in accounts receivable sold by TXU Receivables Company		(700	)		(671	)
Allowance for uncollectible accounts related to undivided interests in receivables retained		(32	)		(36	)
Trade accounts receivable — reported in balance sheet	$	1,123		$	1,328

Gross trade accounts receivable at September 30, 2006 and December 31, 2005 included unbilled revenues of $497 million and $494 million, respectively.

Allowance for Uncollectible Accounts Receivable—

	2006			2005
Allowance for uncollectible accounts receivable as of January 1	$	36		$	16
Increase for bad debt expense		53			37
Decrease for account write-offs		(55	)		(43	)
Changes related to receivables sold		13			25
Other (a)		(15	)		15
Allowance for uncollectible accounts receivable as of September 30	$	32		$	50

(a) Reflects an allowance established in 2005 for a coal contract dispute that was reversed upon settlement in 2006. See Note 14.

Allowances related to undivided interests in receivables sold are reported in current liabilities and totaled $17 million and $30 million at September 30, 2006 and December 31, 2005, respectively.

7. SHORT-TERM AND LONG-TERM DEBT

Short-term Borrowings— At September 30, 2006 and December 31, 2005, the outstanding short-term borrowings of TXU Corp. and its subsidiaries consisted of the following:

	At September 30, 2006				At December 31, 2005
	Outstanding Amount		Interest Rate (a)		Outstanding Amount		Interest Rate (a)
Commercial paper	$	975	5.53	%	$	358	4.49	%
Bank borrowings		295	5.88	%		440	4.86	%
Total	$	1,270			$	798

(a) Weighted average interest rate at the end of the period.

Under the commercial paper programs, TXU Energy Company and TXU Electric Delivery may issue up to $2.4 billion and $1.0 billion, respectively, of these securities. These programs are supported by existing credit facilities.

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Credit Facilities — At September 30, 2006, subsidiaries of TXU Corp. had access to credit facilities with the following terms:

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

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

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

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

All letters of credit and cash borrowings under the credit facilities as of September 30, 2006 are the obligations of TXU Energy Company. Outstanding commercial paper supported by these facilities totaled $360 million for TXU Energy Company and $615 million for TXU Electric Delivery as of September 30, 2006.

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

	September 30, 2006		December 31, 2005
TXU Energy Company
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39	$	39
5.400% Fixed Series 1994B due May 1, 2029, remarketing date May 1, 2006(a) (b)		—		39
5.400% Fixed Series 1995A due April 1, 2030, remarketing date May 1, 2006(a) (b)		—		50
5.050% Fixed Series 1995B due June 1, 2030, remarketing date June 19, 2006(a) (c)		—		114
7.700% Fixed Series 1999A due April 1, 2033		111		111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013(a)		16		16
7.700% Fixed Series 1999C due March 1, 2032		50		50
3.850% Floating Series 2001A due October 1, 2030 (d)		71		71
4.750% Fixed Series 2001B due May 1, 2029, remarketing date November 1, 2006(a)		19		19
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011(a)		217		217
3.790% Floating Series 2001D due May 1, 2033 (d)		268		268
5.310% Floating Taxable Series 2001I due December 1, 2036(d)		62		62
3.850% Floating Series 2002A due May 1, 2037(d)		45		45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)		44		44
6.300% Fixed Series 2003B due July 1, 2032		39		39
6.750% Fixed Series 2003C due October 1, 2038		52		52
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014(a)		31		31
5.000% Fixed Series 2006 due March 1, 2041		100		—
Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021		51		51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011(a)		91		91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011(a)		107		107
5.200% Fixed Series 2001C due May 1, 2028		70		70
5.800% Fixed Series 2003A due July 1, 2022		12		12
6.150% Fixed Series 2003B due August 1, 2022		45		45
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028		14		14
5.000% Fixed Series 2001A due May 1, 2027, remarketing date November 1, 2006(a)		37		37
Other:
6.125% Fixed Senior Notes due March 15, 2008 (swapped to variable) (e)		250		250
7.000% Fixed Senior Notes due March 15, 2013		1,000		1,000
4.920% Floating Rate Senior Notes due January 17, 2006 (interest rate in effect at December 31, 2005)		—		400
Capital lease obligations		101		103
Fair value adjustments related to interest rate swaps		10		9
Total TXU Energy Company	$	2,952	$	3,456

15

	September 30, 2006			December 31, 2005
TXU Electric Delivery
6.375% Fixed Senior Notes due May 1, 2012	$	700		$	700
7.000% Fixed Senior Notes due May 1, 2032		500			500
6.375% Fixed Senior Notes due January 15, 2015 (swapped to variable) (e)		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
5.000% Fixed Debentures due September 1, 2007 (swapped to variable) (e)		200			200
7.000% Fixed Debentures due September 1, 2022		800			800
Unamortized discount		(17	)		(17	)
Sub-total		3,033			3,033
TXU Electric Delivery Transition Bond Company LLC:(g)
2.260% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2007		8			44
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		122			122
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		130			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009		189			215
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		221			221
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290
Total TXU Electric Delivery Transition Bond Company LLC		1,105			1,167
Total TXU Electric Delivery		4,138			4,200
US Holdings
7.170% Fixed Senior Debentures due August 1, 2007		10			10
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		85			91
9.580% Fixed Notes due in semiannual installments through December 4, 2019		65			65
8.254% Fixed Notes due in quarterly installments through December 31, 2021		60			62
6.289% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037(f)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized premium		5			5
Total US Holdings		234			242
TXU Corp.
6.375% Fixed Senior Notes Series C due January 1, 2008 (swapped to variable) (e)		200			200
6.375% Fixed Senior Notes Series J due June 15, 2006		—			683
4.446% Fixed Senior Notes Series K due November 16, 2006		50			50
5.800% Fixed Senior Notes Series M due May 16, 2008 (h)		—			179
4.800% Fixed Senior Notes Series O due November 15, 2009 ($450 swapped to variable) (e)		1,000			1,000
5.550% Fixed Senior Notes Series P due November 15, 2014 ($500 swapped to variable) (e)		1,000			1,000
6.500% Fixed Senior Notes Series Q due November 15, 2024 ($700 swapped to variable) (e)		750			750
6.550% Fixed Senior Notes Series R due November 15, 2034		750			750
8.820% Building Financing due semiannually through February 11, 2022		99			109
7.007% Floating Convertible Senior Notes due July 15, 2033(f)		25			25
Fair value adjustments related to interest rate swaps		(78	)		(53	)
Unamortized discount		(9	)		(9	)
Total TXU Corp.		3,787			4,684
Total TXU Corp. consolidated		11,111			12,582
Less amount due currently		(390	)		(1,250	)
Total long-term debt	$	10,721		$	11,332

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

(b) Repurchased on May 1, 2006 for remarketing at a later date.

(c) Repurchased on June 19, 2006 for remarketing at a later date.

(d) Interest rates in effect at September 30, 2006. These series are in a weekly interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(e) Interest rates swapped to variable on $2.8 billion of $3.9 billion aggregate principal amount.

(f) Interest rates in effect at September 30, 2006.

(g) These bonds are nonrecourse to TXU Electric Delivery and were issued to recover a regulatory asset.

(h) Equity-linked.

16

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

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

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

In May 2006, the equity-linked Series M Senior Notes with an aggregate principal amount of $179 million were remarketed to fund the settlement of the associated common stock purchase contracts. TXU Corp. participated in the remarketing and purchased all of the outstanding Series M Senior Notes at a price of 100.5% of par and immediately retired the notes resulting in a loss on retirement of $1 million.

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

Other retirements of long-term debt in 2006 totaling $1.2 billion represented payments at scheduled maturity dates and included $683 million of TXU Corp. senior notes and $400 million of TXU Energy Company senior notes.

Fair Value Hedges— TXU Corp. uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At September 30, 2006, $2.8 billion of fixed rate debt had been effectively converted to variable rates through interest rate swap transactions, expiring through 2024. These swaps qualified for and have been designated as fair value hedges in accordance with SFAS 133 (under the short-cut method as the conditions for assuming no ineffectiveness are met).

Long-term debt fair value adjustments—

	September 30, 2006
Long-term debt fair value adjustments related to interest rate swaps at beginning of period — net reduction in debt carrying value	$	(44	)
Fair value adjustments during the period		(18	)
Amortization of net gains on settled fair value hedges (a)		(6	)
Long-term debt fair value adjustments at end of period — net reduction in debt carrying value (net out-of-the-money value of swaps)	$	(68	)

(a) Net value of settled in-the-money fixed-to-variable swaps 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.

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8. SHAREHOLDERS’ EQUITY

Dividend declarations — During 2006, TXU Corp. declared and paid the following dividends:

Declaration Date	Record Date	Payment Date	Dividend Per Share
August 2006	September 1, 2006	October 2, 2006	$	0.4125
May 2006	June 2, 2006	July 3, 2006	$	0.4125
February 2006	March 3, 2006	April 3, 2006	$	0.4125

Dividend Restrictions— At September 30, 2006, there were no material restrictions on TXU Corp.’s ability to pay regular quarterly dividends. To pay these dividends, TXU Corp. depends, in part, on the dividends it receives from its subsidiaries.

Common Stock Repurchases and Issuances—In November 2005, the TXU Corp. board of directors authorized the repurchase of up to 34 million shares of common stock through the end of 2006. Under this authority, TXU Corp. has repurchased and retired approximately 31 million shares, including 12 million shares in November 2005 and 19 million shares during the nine months ended September 30, 2006 at an average price of $49.51 and $51.77 per share, respectively, (including related fees and expenses).

In May 2006, TXU Corp. settled the purchase contracts associated with its remaining equity-linked debt securities. In connection with the settlement, TXU Corp. issued 5.7 million shares of common stock, resulting in an increase in additional paid-in capital of $180 million.

In May 2006, TXU Corp. issued an additional 1.4 million shares under its stock-based incentive compensation plan. The fair value of the share-based awards under the plan is determined at grant date and amortized to expense over the applicable vesting period with an offsetting credit to additional paid-in capital.

The increase in additional paid-in capital in 2006 in the table below also reflects the excess tax benefit of $47 million arising from the distribution date value of the stock-based incentive awards exceeding the reported compensation expense.

18

The following table presents the changes to common stock equity during the nine months ended September 30, 2006:

	Common Stock		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Gain (Loss)			Total Shareholders’ Equity
Balance at December 31, 2005	$	5	$	1,840		$	(1,168	)	$	(202	)	$	475
Common stock issuances		—		180			—			—			180
Common stock repurchases		—		(1,012	)		—			—			(1,012	)
Net effects of cash flow hedges		—		—			—			453			453
Dividends		—		—			(570	)		—			(570	)
Net income		—		—			2,077			—			2,077
Effects of stock-based incentive compensation plans		—		64			—			—			64
Cost of Thrift Plan shares issued by LESOP trustee		—		8			—			—			8
Effects of executive deferred compensation plan		—		11			—			—			11
Other		—		5			5			—			10
Balance at September 30, 2006	$	5	$	1,096		$	344		$	251		$	1,696

9. COMMITMENTS AND CONTINGENCIES

Wholesale Market Activity Investigation — On October 6, 2006, TXU Portfolio Management Company was notified that the Commission had begun an investigation of its 2005 activities in the ERCOT wholesale electricity market as a result of observations noted in the2005 State of the Market Report for the ERCOT Wholesale Electricity Market performed by Potomac Economics, an economic consulting firm. Although it has not yet received any information requests from the Commission, TXU Portfolio Management Company believes that the investigation will focus on activities involving bids to sell balancing energy and generation unit commitments. Balancing energy represents approximately five to ten percent of the total energy sold in the ERCOT wholesale market. TXU Portfolio Management Company intends to cooperate fully with the Commission in its investigation.

Generation Development Program —In April 2006, TXU Corp. announced a plan for the development and construction of 11 new lignite/coal-fired power generation facilities in Texas. To facilitate meeting this timeline, subsidiaries of TXU Corp. have placed orders for critical long lead-time equipment, including boilers, turbine generators and air quality control systems, prior to securing final air permits from the TCEQ. Contingent cancellation costs related to these orders, the Oak Grove equipment orders and the Sandow engineering, procurement and construction agreement totaled approximately $675 million at September 30, 2006. This amount could be reduced by recovery values related to the assets acquired and for owned assets that are intended to be utilized in the program.

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

Disposed TXU Gas operations —In connection with the TXU Gas transaction in October 2004, TXU Corp. agreed, for a period of three years from the disposition date, to indemnify Atmos Energy Corporation for certain qualified environmental claims that may arise in relation to the assets acquired by Atmos Energy Corporation. TXU Corp. is not required to indemnify Atmos Energy Corporation until the aggregate of all such qualified claims exceeds $10 million, and TXU Corp. is only required to indemnify Atmos Energy Corporation for 50% of qualified claims between $10 million and $20 million. The maximum amount that TXU Corp. would be required to pay Atmos Energy Corporation pursuant to this environmental indemnity is $192.5 million. In addition, TXU Corp. agreed to indemnify Atmos Energy Corporation for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos Energy Corporation, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. In each case, TXU Corp.’s indemnification is limited to 10 years from the disposition date. The maximum aggregate amount that TXU Corp. may be required to pay is $1.925 billion. The estimated fair value of the indemnification recorded upon completion of the TXU Gas transaction was $2.5 million. To date, TXU Corp. has not been required to make any payments to Atmos Energy Corporation under this indemnity obligation and no such payments are currently anticipated.

In 1992, a discontinued engineering and construction business of TXU Gas completed construction of a plant, the performance of which is guaranteed by TXU Gas through 2008. The maximum contingent liability under the guarantee is approximately $109 million. No claims have been asserted under the guarantee and none are currently anticipated. TXU Corp. retains this contingent liability under the terms of the TXU Gas transaction agreement.

Residual value guarantees in operating leases — TXU Corp. or a subsidiary is the lessee under various operating leases that guarantee the residual values of the leased facilities. At September 30, 2006, the aggregate maximum amount of residual values guaranteed was approximately $131 million with an estimated residual recovery of approximately $128 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the lease portfolio is approximately seven years. A significant portion of the maximum guarantee amount relates to leases entered into prior to December 31, 2002.

Indebtedness guarantee —In 1990, US Holdings repurchased an electric co-op’s minority ownership interest in the Comanche Peak nuclear generation plant and assumed the co-op’s indebtedness to the US government for the facilities. The indebtedness is included in long-term debt reported in the consolidated balance sheet. US Holdings is making principal and interest payments to the co-op in an amount sufficient for the co-op to make payments on its indebtedness. US Holdings guaranteed the co-op’s payments, and in the event that the co-op fails to make its payments on the indebtedness, the US government would assume the co-op’s rights under the agreement, and such payments would then be owed directly by US Holdings. At September 30, 2006, the balance of the indebtedness was $125 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities.

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

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

Income Tax Contingencies — TXU Corp. and certain of its subsidiaries are currently under audit by the IRS with respect to tax returns for various tax periods as discussed below, and are subject to audit by other taxing authorities and by the IRS for subsequent tax periods. The amount and timing of any tax assessments resulting from these audits are uncertain, and could have a material effect on TXU Corp.’s liquidity and results of operations. Certain audit matters as to which management believes there is a reasonable possibility of a material future tax assessment are discussed below.

TXU Corp. 1997-2002 Audit — The IRS is currently examining TXU Corp.’s federal income tax returns for 1997-2002. A tax basis step-up of a business that occurred at ENSERCH Corporation prior to its 1997 acquisition by TXU Corp. resulted in a TXU Corp. audit issue as a result of the 2000 sale of the business. The issue was resolved in the first quarter of 2006, and a reserve of $62 million was released (see Note 3). In addition to proposed adjustments with respect to the worthlessness of TXU Corp.’s investment in TXU Europe (discussed separately below), the IRS has issued notices of proposed adjustment with respect to several other items. The IRS is expected to complete its examination before year-end 2006. TXU Corp. expects to protest a number of adjustments, and expects that the protested issues will not be resolved until after 2006. Management believes that tax reserves recorded for potential adjustments to TXU Corp.’s 1997-2002 tax returns are adequate to provide for the expected outcome of the IRS’s proposed adjustments.

TXU Corp. 2003-2005 Audit— TXU Corp. expects that the IRS will commence an examination of its 2003 through 2005 tax returns during 2007. Consistent with its experience in prior audits, TXU Corp. expects that the IRS will propose adjustments to the tax returns and that TXU Corp. will incur some liability to resolve those proposed adjustments with the IRS. The precise nature and amount of any such proposed adjustments is uncertain but the likelihood of occurrence is probable. TXU Corp. has recorded reserves related to potential audit adjustments, representing the estimated tax expense to be incurred as a result of such audit adjustments.

TXU Gas (formerly ENSERCH Corporation) Audits — The IRS audits of the 1993 and 1994-1997 ENSERCH tax returns have been closed. See discussion above concerning the TXU Corp. 1997-2002 audit.

TXU Europe — On its US federal income tax return for calendar year 2002, TXU Corp. claimed an ordinary loss deduction related to the worthlessness of TXU Corp.’s investment in TXU Europe, the tax benefit of which is estimated to be $983 million (assuming the deduction is sustained on audit). Due to a number of uncertainties regarding the proper tax treatment of the worthlessness loss, no portion of the tax benefit related to TXU Corp.’s 2002 write-off of its investment in TXU Europe was recognized in income prior to the second quarter of 2004.

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In June 2004, the IRS issued a preliminary notice of proposed adjustment (subsequently amended in September 2004) proposing to disallow the 2002 worthlessness deduction and treat the worthlessness as a capital loss (deductible only against capital gains). In addition, in 2004 TXU Corp. revised the estimates of capital losses and ordinary deductions expected from the worthlessness deduction utilization. Accordingly, in 2004 TXU Corp. recorded a tax benefit of $755 million ($680 million classified as discontinued operations) related to the TXU Europe worthlessness deduction, which reflects expected utilization of the capital loss deduction against capital gains realized in 2004 and prior periods. The benefit recognized also included $220 million for deductions related to the write-off of the investment in TXU Europe expected to be sustained as ordinary as a result of the preliminary notice.

The tax benefits recognized are based on the notice of proposed adjustment, adjusted to exclude the effects of elements of the IRS notice that TXU Corp. believes are without merit and unlikely to be sustained. While the notice of proposed adjustment is not binding on the IRS and therefore it is uncertain what positions the IRS might ultimately assert or what, if any, tax liability might result, TXU Corp. believes that the possibility of the IRS adopting a more adverse position is remote.

If TXU Corp.’s ordinary loss deduction claimed on the 2002 tax return is not sustained, TXU Corp. would be required to repay approximately $480 million in tax refunds previously received (including interest) based on the assumptions used to determine the tax benefits recognized after receipt of the notice of proposed adjustments, and before taking into account other potential IRS adjustments to TXU Corp.’s 1997-2002 tax returns. In addition, TXU Corp. would owe additional tax of $118 million related to 2004. These amounts are reported as other noncurrent liabilities on the September 30, 2006 balance sheet. No material earnings charge is expected with respect to any such repayment. TXU Corp. is unable to predict the timing of any such repayment, but currently expects that it would not be made prior to 2007.

TXU Corp. believes that its original tax reporting of the worthlessness of its investment in TXU Europe as an ordinary deduction was proper and intends to protest the IRS’s proposed adjustments. If TXU Corp.’s position is sustained, a credit of approximately $79 million would be recognized in earnings.

Legal Proceedings — On September 6, 2005 a lawsuit was filed in the United States District Court for the Northern District of Texas, Dallas Division against TXU Corp. and C. John Wilder. The plaintiff’s amended complaint asserts claims on behalf of the plaintiffs and a putative class of owners of certain TXU Corp. securities who tendered such securities in connection with a tender offer conducted by TXU Corp. in 2004. The amended complaint alleges violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5. The allegations relate to a tender offer conducted in September and October 2004 for certain equity-linked securities in which it was expressly disclosed that TXU Corp. management was evaluating whether it should recommend to the board of directors that the board reevaluate TXU Corp.’s dividend policy. After the tender offer was closed, and consistent with the disclosure, management did make a recommendation to the board to reevaluate the dividend policy and the board elected to increase the quarterly dividend. The plaintiffs contend that such disclosure in connection with the tender offer was inadequate. TXU Corp. maintains that the disclosure provided in connection with the tender offer regarding the evaluation of the dividend policy was complete and accurate at the time the tender offer was initiated as well as when it was closed. A Motion to Dismiss was filed by the defendants, and the District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice on August 30, 2006. The Plaintiff filed a timely notice of appeal. While TXU Corp. is unable to estimate any possible loss or predict the outcome of this litigation in the event the Fifth Circuit Court of Appeals reverses the District Court, TXU Corp. believes the claims made in this litigation are without merit and, accordingly, intends to vigorously defend this litigation, including the appeal of the District Court’s order dismissing the litigation.

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

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

In November 2002 and February and March 2003, three lawsuits were filed in the United States District Court for the Northern District of Texas, Dallas Division, asserting claims under ERISA on behalf of a putative class of participants in and beneficiaries of various employee benefit plans of TXU Corp. These ERISA lawsuits were consolidated, and a consolidated complaint was filed in February 2004 against TXU Corp., the directors of TXU Corp. serving during the putative class period as well as certain officers of the company who were the members of the TXU Thrift Plan Committee. The plaintiffs seek to represent a class of participants in such employee benefit plans during the period between April 26, 2001 and October 11, 2002. The plaintiffs filed an initial motion for class certification and, after class certification discovery was completed, the District Court denied plaintiffs’ initial class certification motion without prejudice and granted plaintiffs’ leave to amend their complaint. Plaintiffs’ second class certification motion, filed on the basis of their amended complaint, was denied and the case was ordered dismissed without prejudice on September 29, 2005. The plaintiffs filed an appeal of the dismissal to the Fifth Circuit Court of Appeals and the appeal is pending. TXU Corp. believes the claims are without merit and intends to vigorously defend the lawsuit, including the appeal. TXU Corp. is, however, unable to estimate any possible loss or predict the outcome of this action in the event the Fifth Circuit reverses the dismissal and remands the case to the District Court or the suit is refiled by the plaintiffs or others seeking to assert similar claims.

On October 23, 2002, a derivative lawsuit was filed by a purported shareholder on behalf of TXU Corp. in the 116th Judicial District Court of Dallas County, Texas. The plaintiff alleged claims including breach of fiduciary duty and breach of duties of loyalty and good faith. Defendants in the suit maintained that the plaintiff in such suit failed to make a demand upon the directors as is required by law, and TXU Corp. never agreed to waive the requirements for such a demand and did not take any action inconsistent with insistence upon a demand. The defendants filed pleadings seeking to have the case dismissed due to plaintiffs’ failure to make the statutorily required presuit demand; however, the Court had not ruled on the requested dismissal when TXU Corp. reached an agreement in principle with the plaintiff to settle this litigation. The Court entered a judgment on August 21, 2006 approving the settlement, and no appeals were taken from the judgment; thus the settlement is final. The settlement amount was not material to TXU Corp.’s results of operations or financial condition.

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In October, November and December 2002 and January 2003, a number of lawsuits were filed in, removed to or transferred to the United States District Court for the Northern District of Texas, Dallas Division, against TXU Corp. and certain of its officers and directors. These lawsuits were consolidated and lead plaintiffs were appointed by the Court. The consolidated complaint alleged violations of the Securities Exchange Act of 1934, as amended, Rule 10b-5 and the Securities Act of 1933, as amended. On January 20, 2005, TXU Corp. executed a memorandum of understanding settling this litigation. After preliminary certification of a settlement class and notice to such class, the District Court conducted a hearing and thereafter on November 8, 2005 granted final approval of the settlement. Certain members of the settlement class who objected to the plan of allocation, the plaintiffs’ attorneys’ fees and other matters related to the approval of the settlement have appealed the orders approving the settlement to the Fifth Circuit Court of Appeals and the appeal remains pending. TXU Corp. believes that the issues raised on appeal are without merit but cannot predict whether the appeal might result in a remand to the District Court for reconsideration of the notice to the settlement class, the Plaintiffs’ attorneys’ fees or other matters, and while TXU Corp. cannot predict the effect of the appeal being sustained, it does not believe that the appeal will result in reversal of the approval of the settlement.

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

Environmental Contingencies — The federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on sulfur dioxide and nitrogen oxide emissions produced by electricity generation plants. The capital requirements of TXU Corp. 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 Corp. and its subsidiaries must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. TXU Corp. 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 to existing 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 Corp. or its subsidiaries may be asserted to be potential responsible parties.

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10. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS

Net pension and other postretirement employee benefit (OPEB) costs for the three and nine months ended September 30, 2006 and 2005 are comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Components of net pension costs:
Service cost	$	10		$	9		$	31		$	28
Interest cost		34			33			102			98
Expected return on assets		(37	)		(37	)		(110	)		(109	)
Amortization of unrecognized prior service cost		1			1			2			2
Amortization of net loss		8			5			24			15
Net pension cost		16			11			49			34
Components of net OPEB costs:
Service cost		4			4			10			10
Interest cost		15			14			45			42
Expected return on assets		(6	)		(5	)		(16	)		(15	)
Amortization of unrecognized net transition asset		—			—			1			1
Amortization of unrecognized prior service cost		(1	)		(1	)		(3	)		(2	)
Amortization of net loss		8			6			23			17
Net OPEB costs		20			18			60			53
Net pension and OPEB costs		36			29			109			87
Less amounts deferred principally as a regulatory asset or property		(20	)		(13	)		(61	)		(42	)
Net amounts recognized as expense	$	16		$	16		$	48		$	45

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

Legislation enacted in the second quarter of 2005 resulted in a reduction of pension and OPEB costs recognized in earnings, as it provides for regulatory recovery of additional amounts of such costs. See discussion immediately below.

Regulatory Recovery of Pension and OPEB Costs — In June 2005, an amendment to PURA relating to TXU Corp.’s pension and OPEB plans was enacted by the Texas Legislature. This amendment, which was retroactively effective January 1, 2005, provides for the recovery by TXU Electric Delivery of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, primarily TXU Energy Company’s active and retired employees, related to employee service prior to the unbundling of TXU Corp.’s electric utility business and the deregulation of the Texas electricity industry effective January 1, 2002. The amendment additionally authorizes TXU Electric Delivery to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Accordingly, in the second quarter of 2005 TXU Electric Delivery began deferring (principally as a regulatory asset or property) additional pension and OPEB costs for the effect of the amendment. Amounts deferred are ultimately subject to regulatory approval. Amounts recorded as a regulatory asset in 2006 totaled $8 million for the quarter and $24 million year-to-date.

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11. COMMODITY CONTRACT ASSETS AND LIABILITIES

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

Current and noncurrent commodity contract assets totaling $595 million at September 30, 2006 and $1.9 billion at December 31, 2005 are stated net of applicable credit (collection) and performance reserves totaling $9 million and $12 million, respectively. Performance reserves are provided for direct, incremental costs to settle the contracts.

Current and noncurrent commodity contract liabilities totaled $754 million at September 30, 2006 and $2.0 billion at December 31, 2005. The balance at September 30, 2006 includes a $109 million ($71 million after-tax) “day one” loss recorded in the second quarter of 2006 associated with a related series of hedging contracts entered into at below market prices. The contracts, the value of which are based on natural gas prices, are intended to hedge exposure to future changes in power prices. The loss was recorded as a reduction of revenues, consistent with other mark-to-market gains and losses, and is included in the results of the TXU Energy Holdings segment. Future changes in fair value of the contracts, to the extent effective, will largely be reflected in other comprehensive income due to designation as cash flow hedges.

12. CASH FLOW HEDGES UNDER SFAS 133

TXU Corp. experienced cash flow hedge ineffectiveness net gains related to positions held at the end of the period of $150 million and $289 million for the three and nine month periods ended September 30, 2006, respectively. For the corresponding periods of 2005, the amounts were $1 million and $2 million in net gains, respectively. These amounts are pretax and are reported in revenues.

The net effect of recording unrealized mark-to-market gains and losses arising from hedge ineffectiveness (versus recording gains and losses upon settlement) includes the above amounts as well as the effect of reversing unrealized ineffectiveness gains and losses recorded in previous periods to offset realized gains and losses in the current period. Such net effect totaled $157 million and $301 million in net gains for the three and nine month periods ended September 30, 2006, respectively, and $2 million and $8 million in net gains for the three and nine month periods ended September 30, 2005, respectively.

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

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

TXU Corp. expects that $127 million of after-tax net gains related to cash flow hedges included in accumulated other comprehensive net income will be reclassified into net income during the next twelve months as the related hedged transactions are settled and affect net income. Of this amount, $135 million in gains relate to commodity hedges and $8 million in losses relate to financing-related hedges.

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13. SEGMENT INFORMATION

TXU Corp.’s operations are aligned into two reportable segments: TXU Energy Holdings and TXU Electric Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

TXU Energy Holdings segment – consists of electricity generation, residential and business retail electricity sales as well as wholesale energy markets activities primarily in Texas. These activities are conducted principally by subsidiaries of TXU Energy Company. The results of this segment also include the activities of TXU DevCo and its subsidiaries to develop lignite/coal-fired generation facilities in Texas, activities of other TXU Corp. development subsidiaries to identify opportunities for generation development in markets outside of Texas and a lease trust holding certain combustion turbines.

TXU Electric Delivery segment – consists of operations involving the transmission and distribution of electricity in Texas. The activities of the TXU Electric Delivery segment are largely regulated by the Commission. The segment includes TXU Electric Delivery’s financing subsidiary.

Corporate and Other – remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses and interest on debt at the TXU Corp. level.

TXU Corp. evaluates segment performance based on income from continuing operations. TXU Corp. accounts for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating revenues:
TXU Energy Holdings	$	3,148		$	2,994		$	7,507		$	7,091
TXU Electric Delivery		708			706			1,874			1,820
Corporate and Other		13			7			35			19
Eliminations		(359	)		(393	)		(935	)		(1,023	)
Consolidated	$	3,510		$	3,314		$	8,481		$	7,907
Regulated revenues included in operating revenues:
TXU Energy Holdings	$	—		$	—		$	—		$	—
TXU Electric Delivery		708			706			1,874			1,820
Corporate and Other		—			—			—			—
Eliminations		(344	)		(384	)		(894	)		(999	)
Consolidated	$	364		$	322		$	980		$	821
Affiliated revenues included in operating revenues:
TXU Energy Holdings	$	3		$	3		$	6		$	7
TXU Electric Delivery		344			384			894			999
Corporate and Other		12			6			35			17
Eliminations		(359	)		(393	)		(935	)		(1,023	)
Consolidated	$	—		$	—		$	—		$	—
Income from continuing operations:
TXU Energy Holdings	$	900		$	459		$	1,879		$	1,007
TXU Electric Delivery		131			145			282			302
Corporate and Other		(47	)		(33	)		(165	)		51
Consolidated	$	984		$	571		$	1,996		$	1,360

No customer provided more than 10% of consolidated revenues.

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14. OTHER INCOME AND DEDUCTIONS

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006			2005
Other income:
Gain on contract settlement	$	—		$	—	$	26		$	—
Amortization of deferred gain on 2004 sale of gas transportation business		12			12		35			35
Net gain on sale of other properties, businesses and interests		11			12		11			13
Insurance recovery of litigation settlement		15			—		15			35
Insurance recovery of damage claim		—			6		—			6
Power services agreement termination fee		—			—		—			4
Other		(2	)		5		4			11
Total other income	$	36		$	35	$	91		$	104
Other deductions:
Charge for impairment of natural gas-fired generation plants	$	—		$	—	$	198		$	—
Equity losses in unconsolidated affiliate engaged in broadband-over-powerline activities		3			—		10			—
Charge (credit) related to coal contract counterparty claim		—			—		(12	)		12
Charge related to cities rate settlement		6			—		6			—
Transition costs related to InfrastruX Energy Services joint venture		3			—		3			—
Asset writedowns		3			—		6			—
Employee retirement benefit costs related to discontinued businesses		8			4		18			12
Capgemini outsourcing transition costs		—			4		—			13
Charge (credit) related to impaired leases		(1	)		—		4			(12	)
Litigation settlements		—			—		1			11
Other		1			3		10			13
Total other deductions	$	23		$	11	$	244		$	49

In the second quarter of 2006, TXU Corp. recorded income of $26 million upon the settlement of a contract dispute related to antenna site rentals by a telecommunications company. (Reported in Corporate and Other nonsegment operations.)

In the third quarter of 2006, TXU Corp. recorded a $10 million gain related to the sale of mineral interests. (Reported in Corporate and Other nonsegment operations.)

In both the third quarter of 2006 and second quarter of 2005, TXU Corp. recorded insurance recoveries related to the 2005 settlement of the shareholders’ litigation totaling $15 million and $35 million, respectively. (Reported in Corporate and Other nonsegment operations.)

See Note 2 for discussion of impairment of natural gas-fired generation plants. (Reported in the TXU Energy Holdings segment.)

In the first quarter of 2006, TXU Corp. 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. (Reported in the TXU Energy Holdings segment.)

In the third quarter of 2006, TXU Corp. recorded $6 million in expense related to the cities rate settlement as discussed in Note 15. (Reported in the TXU Electric Delivery segment.)

Amounts recorded in 2005 for impaired leases relate to gas-fired combustion turbines that TXU Corp. 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. (Reported in the TXU Energy Holdings segment.)

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15. CITIES RATE SETTLEMENT

In January 2006, TXU Electric Delivery agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the Commission to no later than June 30, 2008 (based on a test year ending December 31, 2007), unless the Cities and TXU Electric Delivery mutually agree that such a filing is unnecessary. TXU Electric Delivery has extended the benefits of the agreement to 292 nonlitigant cities. Based on the final agreements, including the participation of the nonlitigant cities, expected payments to the cities are estimated to total approximately $70 million, including incremental franchise taxes.

This amount is being recognized in earnings over the period from May 2006 through June 2008. Amounts recognized in 2006 totaled $7 million in the third quarter and $10 million year-to-date and have been reported in the other deductions (see Note 14) and franchise and revenue-based taxes line items in the Condensed Statements of Consolidated Income.

16. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations —

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating revenues:
Regulated	$	708		$	706		$	1,874		$	1,820
Unregulated		3,161			3,001			7,542			7,110
Intercompany sales eliminations – regulated		(344	)		(384	)		(894	)		(999	)
Intercompany sales eliminations – unregulated		(15	)		(9	)		(41	)		(24	)
Total operating revenues		3,510			3,314			8,481			7,907
Costs and operating expenses:
Fuel, purchased power costs and delivery fees – unregulated (a)		1,002			1,449			2,182			3,169
Operating costs – regulated		194			193			579			556
Operating costs – unregulated		140			152			439			483
Depreciation and amortization – regulated		128			122			359			334
Depreciation and amortization – unregulated		88			81			269			246
Selling, general and administrative expenses – regulated		43			48			132			138
Selling, general and administrative expenses – unregulated		168			152			450			421
Franchise and revenue-based taxes – regulated		71			65			189			179
Franchise and revenue-based taxes – unregulated		31			28			87			79
Other income		(36	)		(35	)		(91	)		(104	)
Other deductions		23			11			244			49
Interest income		(10	)		(16	)		(30	)		(35	)
Interest expense and related charges		209			207			640			591
Total costs and operating expenses		2,051			2,457			5,449			6,106
Income from continuing operations before income taxes	$	1,459		$	857		$	3,032		$	1,801

(a) Includes cost of fuel consumed of $317 million and $332 million for the three months ended September 30, 2006 and 2005, respectively, and $732 million and $736 million for the nine months ended September 30, 2006 and 2005, respectively. The balance in each period represents energy purchased for resale and delivery fees net of intercompany eliminations.

The operations of the TXU Energy Holdings segment are included above as unregulated as the Texas market is open to competition. However, retail pricing to residential customers in the historical service territory is subject to certain price controls (price-to-beat rate) until December 31, 2006.

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Interest Expense and Related Charges—

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Interest	$	217		$	208		$	655		$	587
Amortization of debt discounts, premiums and issuance costs		4			2			12			14
Capitalized interest, including debt portion of allowance for borrowed funds used during construction		(12	)		(5	)		(27	)		(13	)
Preferred stock dividends of subsidiaries		—			2			—			3
Total interest expense and related charges	$	209		$	207		$	640		$	591

Restricted Cash —

	Balance Sheet Classification
	At September 30, 2006				At December 31, 2005
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Pollution control revenue bond funds held by trustee (See Note 7)	$	—	$	101	$	—	$	—
Amounts related to securitization (transition) bonds		57		17		46		13
All other		3		—		8		3
Total restricted cash	$	60	$	118	$	54	$	16

Inventories by Major Category —

	September 30, 2006		December 31, 2005
Materials and supplies	$	182	$	163
Environmental energy credits and emission allowances		15		21
Fuel stock		95		81
Natural gas in storage		88		99
Total inventories	$	380	$	364

Investments—

	September 30, 2006		December 31, 2005
Nuclear decommissioning trust	$	424	$	389
Assets related to employee benefit plans, principally employee savings programs		195		187
Land		35		35
Note receivable from Capgemini		25		25
Investment in unconsolidated affiliates		8		3
Miscellaneous other		3		4
Total investments	$	690	$	643

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Property, Plant and Equipment— As of September 30, 2006 and December 31, 2005, property, plant and equipment of $18.0 billion and $17.2 billion, respectively, is stated net of accumulated depreciation and amortization of $12.4 billion and $11.9 billion, respectively.

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

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

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

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

	As of September 30, 2006						As of December 31, 2005
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Intangible assets subject to amortization included in property, plant and equipment:
Capitalized software placed in service	$	415	$	343	$	72	$	386	$	314	$	72
Land easements		178		65		113		178		63		115
Mineral rights and other		31		24		7		31		24		7
Total	$	624	$	432	$	192	$	595	$	401	$	194

Aggregate TXU Corp. amortization expense for intangible assets for the three months ended September 30, 2006 and 2005 was $13 million and $6 million, respectively. Aggregate TXU Corp. amortization expense for intangible assets for the nine months ended September 30, 2006 and 2005 was $31 million and $17 million, respectively. At September 30, 2006, the weighted average remaining useful lives of capitalized software, land easements and mineral rights and other assets were 5 years, 69 years and 40 years, respectively. The estimated aggregate amortization expense for each of the five succeeding fiscal years from December 31, 2005 is as follows:

Year	Amortization Expense
2006	$	25
2007		22
2008		19
2009		11
2010		3

Goodwill of $542 million reported in the consolidated balance sheet as of September 30, 2006 and December 31, 2005 includes $517 million related to TXU Energy Company and $25 million related to TXU Electric Delivery.

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Regulatory Assets and Liabilities—

	September 30, 2006		December 31, 2005
Regulatory assets:
Generation-related regulatory assets securitized by transition bonds	$	1,354	$	1,461
Securities reacquisition costs		114		119
Recoverable deferred income taxes — net		94		107
Storm-related costs		136		110
Employee retirement costs		148		89
Nuclear decommissioning cost under-recovery		—		8
Employee severance costs		42		33
Total regulatory assets		1,888		1,927
Regulatory liabilities:
Investment tax credit and protected excess deferred taxes		69		71
Over-collection of securitization (transition) bond revenues		38		28
Nuclear decommissioning cost over-recovery		2		—
Other regulatory liabilities		20		2
Total regulatory liabilities		129		101
Net regulatory assets	$	1,759	$	1,826

Regulatory assets reported above that have been reviewed and approved by the Commission and are earning a return totaled $121 million at both September 30, 2006 and December 31, 2005. The net assets that have been approved by the Commission and are not earning a return total $1,379 million and have a remaining recovery period of 10 to 45 years, including the regulatory assets securitized by transition bonds that have a remaining recovery period of 10 years.

Severance Liabilities Related to Strategic Initiatives—

	TXU Energy Holdings			TXU Electric Delivery			Total
Liability for severance costs as of December 31, 2005	$	18		$	4		$	22
Additions to liability (a)		8			8			16
Payments charged against liability		(23	)		(3	)		(26	)
Other adjustments to liability		(1	)		(1	)		(2	)
Liability for severance costs as of September 30, 2006	$	2		$	8		$	10

(a) TXU Energy Company and TXU Electric Delivery additions to liability are both related to services agreements entered into with certain providers. TXU Electric Delivery amount was recorded with an offset to a regulatory asset.

Supplemental Cash Flow Information—

	Nine Months Ended September 30,
	2006		2005
Cash payments related to continuing operations:
Interest (net of amounts capitalized)	$	608	$	540
Income taxes	$	50	$	90
Cash payments related to discontinued operations:
Income taxes	$	—	$	30
Noncash investing and financing activities:
Capital lease for generation plant rail spur	$	—	$	95

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of TXU Corp.:

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

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

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

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

/s/ Deloitte & Touche LLP

Dallas, Texas

November 9, 2006

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

BUSINESS

TXU Corp. is a holding company whose operations are conducted principally through TXU Electric Delivery and subsidiaries of TXU Energy Company. TXU Energy Company is a holding company whose subsidiaries are engaged in electricity generation, retail electricity sales to residential and business customers as well as wholesale energy markets activities primarily in Texas. TXU Electric Delivery is engaged in regulated electricity transmission and distribution operations in Texas. TXU DevCo and its subsidiaries are engaged in the development of new lignite/coal-fired generation facilities in Texas.

TXU Corp. has two reportable segments. The TXU Energy Holdings segment consists of TXU Energy Company, TXU DevCo and its subsidiaries, activities of TXU Corp. development subsidiaries to identify opportunities for generation development in markets outside of Texas and a lease trust holding certain combustion turbines. The TXU Electric Delivery segment consists of TXU Electric Delivery and its financing subsidiary. (See Note 13 to Financial Statements for further information concerning reportable business segments.)

SIGNIFICANT DEVELOPMENTS IN 2006

New Generation Development Programs

Coal-Fired Generation Development Program in Texas and Related Financing Arrangements

As previously disclosed, TXU Corp., through TXU DevCo, intends to develop and construct up to 11 lignite/coal-fired generation units in Texas, with a total net capacity estimated at 9,079 MW. Aggregate capital expenditures for all 11 units are expected to be in excess of $10 billion. The 11 facilities consist of four units at existing TXU Corp. lignite/coal-fired generation plant sites (Big Brown, Martin Lake, Monticello and Sandow), five units at existing TXU Corp. gas-fired generation plant sites (Lake Creek, Morgan Creek, Valley and two units at Tradinghouse) and two units at a site (Oak Grove) owned by TXU Corp. and originally slated for the construction of a generation plant a number of years ago. The units currently are expected to be constructed and owned by TXU DevCo and its subsidiaries.

In order to minimize design and construction costs and speed development of the facilities, eight of the units to be constructed at existing generation plant sites are expected to be built with a proprietary, standardized plant design and construction planning process. These units, which are expected to be fueled by Powder River Basin coal, are referred to as the “reference” plants.

Under this development program, TXU Corp. expects that total emissions of sulfur dioxide, nitrogen oxide and mercury from its lignite/coal-fired generation fleet, including existing plants and the 11 new units, will be reduced by 20% from 2005 levels. To accomplish this reduction, the program includes up to $2 billion for investments in state-of-the-art emissions controls for the new TXU DevCo units. Further, TXU Corp. expects additional capital expenditures for environmental control systems at existing generation facilities totaling approximately $550 million. While TXU Corp. believes that technology to capture and sequester carbon dioxide (CO2) is not yet commercially viable, the design of the reference plants is expected to allow for future retrofit CO2 capture and sequestration installations.

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In an initiative separate from but related to the planned generation development and emissions controls investment spending, subsidiaries of TXU Corp. expect to invest up to $2 billion for the development and commercialization of cleaner power plant technologies, including integrated gasification combined cycle, the next generation of more efficient ultra-supercritical coal and pulverized coal emissions technology to reduce carbon intensity. Funding for this initiative may be sourced from cash flows from operations, debt or other project financing over the next five to seven years. TXU Corp. has already initiated a number of efforts, including research and development investments and partnerships, to develop cleaner coal-fired generation technologies. Subsidiaries of TXU Corp. have also launched a renewable energy initiative involving the purchase of power from, and/or investment in, wind-generated power facilities that is expected to double its renewable energy portfolio to 1,400 MW by 2011.

TXU Corp. expects the TCEQ to issue final air permits for the Oak Grove facility by early 2007 and for the reference plants in mid-2007. Construction of each unit is expected to commence immediately following the issuance of the related air permit. The expected on-line dates of the units are as follows: Sandow by the first quarter of 2009, Oak Grove’s two units by the second quarter and fourth quarter of 2009 and the first reference plant in the fall of 2009 with the remainder in sequence through mid-2010.

TXU Corp. subsidiaries have made substantial progress in negotiating engineering, procurement and construction (EPC) agreements with respect to the new facilities, including executing agreements with Bechtel Power Corporation (Bechtel) for the Sandow unit and the reference plants and with Fluor Enterprises Inc. (Fluor) for the Oak Grove units. The Sandow EPC contract provides for a fixed-price with limited contingencies. With respect to the reference plants, TXU DevCo has entered into an umbrella agreement that provides for a process that would culminate in turnkey, fixed price EPC contracts. With respect to the Oak Grove EPC contract, TXU DevCo and Fluor are conducting a process to determine the final terms, which is expected to be completed by year-end 2006. TXU DevCo and the EPC contractors are also exploring alternative contract pricing terms, considering means for optimizing the risk/reward profile of the contracts while achieving targeted per kilowatt capital costs. In addition, to facilitate meeting the expected timeline for the start-up of the new facilities, TXU DevCo or the EPC contractors have placed orders for critical, long lead-time equipment, including boilers, turbine generators and air quality control systems. See Note 9 to Financial Statements regarding contingent cancellation costs.

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 commitment includes a mix of first and second-lien senior credit facilities that will be secured by TXU DevCo’s assets. The credit facilities are expected to close in the first half of 2007. Borrowings by TXU DevCo under the agreement are expected to be nonrecourse to TXU Corp. While the closing of the credit facilities is not conditioned on the issuance of air permits for the units, funding for the development and construction costs of each unit will be conditioned on the issuance of an air permit for each such unit. TXU DevCo’s borrowings under the facilities are expected to include amounts to reimburse TXU Corp. and other of its subsidiaries for development spending prior to securing the air permits. Capital expenditures for the development program are expected to total approximately $1.3 billion in 2006, with reimbursement expected to follow the closing of the credit facilities and the issuance of permits in 2007.

TXU DevCo has been pursuing opportunities to sell ownership positions in the new generation facilities. TXU DevCo expects to enter into definitive agreements for sales of equity interests in the Oak Grove and one or more other facilities of up to 850 MW by the end of the first quarter of 2007.

TXU DevCo has also been pursuing the forward sale of power under long-term sales agreements. Forward power sales are targeted at 1,000 to 2,000 MW per year. TXU DevCo is currently negotiating with several electric municipalities and cooperatives for long-term (at least twenty years) power sales agreements totaling 1,360 MW. It is anticipated that more than half of these power sales opportunities will be closed in the first quarter of 2007. TXU DevCo is also actively engaged in discussions with multiple industrial companies for medium-term (five to ten years) power sales contracts.

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Additionally, TXU Corp. is pursuing the sale of up to 49 percent of the total equity of TXU DevCo. Final investor proposals are expected in the first quarter of 2007 with selection of the anchor investors, if any, anticipated in the second quarter of 2007.

Coal-Fired Generation Opportunities in Other US Regions

TXU Corp. has been exploring a number of other opportunities to develop and construct coal-fired generation facilities outside of Texas. In its evaluation of these development efforts, TXU Corp. plans to adhere to rigorous capital investment and value creation thresholds that reflect the inherent risks of investing in large, capital-intensive, commodity-sensitive assets like coal-fired generation plants. TXU Corp. is pursuing a potential 7,000 to 14,000 MW of new net generation capacity and exploring multiple channels to develop, construct and operate a low-cost fleet of baseload coal-fired generation plants. This potential includes displacement of existing aging coal and natural gas-fired facilities with efficient, cost effective and clean burning coal-fired generation. It is expected that these development efforts will employ a mix of sell-forward, sell-down and project financing vehicles to secure the necessary funds and mitigate risks associated with each project.

TXU Corp. has been focusing on opportunities to develop generation facilities as a competitive, wholesale supplier of power in the PJM market, which spans parts of the mid-Atlantic and Midwest regions, and expects to make definitive announcements before the end of 2006 with respect to 2,000 to 4,000 MW of new capacity in that market. Additionally, TXU Corp. subsidiaries are considering partnering with several municipalities and cooperatives to construct and operate 2,500 MW of advanced coal-fired generation facilities in other regions. These customer solutions contemplate TXU Corp. building and operating the new facilities while delivering a majority of the power to the customer in a combination of long-term power purchase agreements and equity ownership. TXU Corp. subsidiaries are in various stages of discussions with other customers for an additional 7,500 MW.

Potential Nuclear Generation Development

Also, in August 2006, TXU Corp. announced plans to develop applications to file for combined construction and operating licenses for 2,000 to 6,000 MW of new nuclear-fueled power generation capacity at one to three sites in Texas. TXU Corp. expects to submit the applications in 2008, which could facilitate bringing the new capacity on-line between 2015 and 2020. TXU Corp. believes that nuclear power generation capital costs are currently not competitive with other technologies. TXU Corp. intends to employ a technical and economic feasibility process with original equipment manufacturers to design a safe and reliable nuclear generation facility while driving down per kilowatt capital costs by 30 to 40 percent from average public industry estimates. TXU Corp. also plans to partner with others in developing the new capacity to take full advantage of the benefits of scale while sharing the risk of such large investments with long-term investors.

Impairment of Natural Gas-Fired Generation Plants

As previously disclosed, in consideration of the new generation development program and other factors, TXU Corp. performed a test of recoverability of the carrying value of its natural gas-fired generation plants. See Note 2 to Financial Statements for a discussion of the impairment of the plants, resulting in a charge in the second quarter of 2006 of $198 million ($129 million after-tax).

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Long-term Hedging Program and Related Collateral Arrangements

As previously disclosed, TXU Corp. commenced a long-term hedging program in October 2005 designed to reduce exposure to changes in future power prices due to changes in the price of natural gas. Under the program, subsidiaries of TXU Corp. have entered into market transactions involving natural gas-related financial instruments. Including the TXU DevCo hedge transactions discussed immediately below, as of October 13, 2006, subsidiaries of TXU Corp. had effectively sold forward a net 1.5 billion MMBtu of natural gas for the period from 2006 to 2012, including a net 1.3 billion MMBtu in instruments that are being accounted for as cash flow hedges of future energy transactions. The balance of the hedge transactions are marked-to-market in net income. While there is significant correlation in the movement of natural gas prices and wholesale power prices in ERCOT because marginal demand is generally met with gas-fired generation plants, power prices do not always move in tandem with natural gas prices. Given the size of the hedge program and the cross-commodity nature of the hedges, the program may result in greater volatility of net income due to hedge ineffectiveness gains and losses, as well as greater mark-to-market gains and losses largely reported in other comprehensive income, than TXU Corp. has experienced in recent years. The effect on reported earnings of unrealized hedge ineffectiveness net gains and mark-to-market net gains recorded under SFAS 133 (versus settlement accounting) totaled $185 million and $191 million pretax for the three and nine month periods ended September 30, 2006, respectively, for positions in the program. Based on the current size of the long-term hedging program, a parallel 0.1 (or approximately 1%) change in market heat rate across each year of the program may cause up to an estimated $105 million to $140 million in cash flow hedge ineffectiveness pretax gains or losses in the period of such change. The other positions in the hedging program that are marked-to-market could, with a similarly parallel $1.00/MMBtu move in gas prices, result in an estimated $250 million of unrealized mark-to-market pre-tax gains or losses.

See Note 11 to Financial Statements for a discussion of a loss of $109 million ($71 million after-tax) recorded upon inception of hedging transactions entered into in the second quarter of 2006.

As part of the overall hedging program, in June 2006 TXU DevCo entered into a related series of hedging transactions that allow hedging of movements in power prices through both new transactions and the novation of existing TXU Energy Company hedging transactions to TXU DevCo. TXU DevCo will pay a fee for transactions that are novated.

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 Corp. have used cash and letters of credit to satisfy their collateral obligations. TXU DevCo’s hedging transactions were initially supported by letters of credit aggregating $500 million issued by TXU Energy Company. Considering the current and expected scale of its hedging program and the desire to reduce the potential effect on liquidity of collateral postings, on August 30, 2006, the $500 million of TXU Energy Company letters of credit were replaced with a first-lien security interest in the assets of TXU Big Brown consisting of two existing lignite/coal-fired generation units. This security interest (Big Brown Lien) supports a portion of the positions in the long-term hedging program.

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

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

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New Joint Venture and TXU Electric Delivery Services Agreement

As previously disclosed, TXU Corp. and InfrastruX Group announced the formation of a joint venture, InfrastruX Energy Services, that expects to provide utility construction, power restoration, maintenance and other services. TXU Corp. also announced an agreement between TXU Electric Delivery and InfrastruX Energy Services under which TXU Electric Delivery will receive services from the joint venture. The services agreement has a total value of $8.7 billion over the ten-year term. The arrangement is conditional upon InfrastruX Group refinancing its debt obligations prior to the final execution of the agreement.

TXU Corp. anticipates closing the transaction in the first half of 2007; however, the Commission recently expressed its desire to gather further information regarding the joint venture. TXU Corp. cannot predict the ultimate outcome of this process, including its possible effect on the timing of closure of the transaction. (Also see discussion below under “Regulation and Rates”.)

Under the terms of the arrangement, over 2,000 TXU Electric Delivery employees are expected to be transferred to the joint venture. These employees represent essentially all of TXU Electric Delivery’s field operations personnel, consisting primarily of construction, maintenance and engineering staff. InfrastruX Group expects to contribute all its operations to the joint venture, including its 3,000 current employees. These operations generated revenues of approximately $400 million in 2005. In addition, TXU Corp. expects to contribute approximately $30 million in tools and other equipment to the joint venture and also expects to sell approximately $60 million in inventory, principally poles and wire, to the joint venture in exchange for a 10-year note receivable. TXU Electric Delivery now expects to incur transition expenses related to the arrangement of up to $19 million, of which $3 million was expensed in the third quarter of 2006. TXU Corp. and InfrastruX Group will have equal representation on the joint venture’s board of directors. Allocations and distributions of profits, losses and cash from the joint venture to the partners are to be primarily based upon the performance of the TXU Corp.-related and InfrastruX-related legacy operations.

TXU Energy Retail Customer Initiatives

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

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

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

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

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

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

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RESULTS OF OPERATIONS

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

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

TXU Corp. Consolidated

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

Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.

TXU Corp.’s operating revenues increased $196 million, or 6%, to $3.5 billion in 2006.

• Operating revenues in the TXU Energy Holdings segment increased $154 million, or 5%, to $3.1 billion. The increase was driven by a $219 million increase in retail electricity revenues. The increase in retail electricity revenues reflected higher pricing, partially offset by the effect of a 9% decline in retail sales volumes. Higher retail prices reflected increases in natural gas prices that resulted in the regulatory-approved price-to-beat rate increase implemented in October 2005 and January 2006. The decline in retail sales volumes reflected a net loss of customers due to competitive activity and lower average consumption per residential and small business customer.

• Operating revenues in the TXU Electric Delivery segment increased $2 million to $708 million in 2006. The revenue increase reflected higher transmission and distribution tariffs and growth in delivery points, partially offset by the effect of lower delivered volumes reflecting lower average consumption per end-user.

• Consolidated revenue growth reflected a $40 million reduction in the intercompany sales elimination, primarily reflecting lower sales by TXU Electric Delivery to REP subsidiaries of TXU Energy Company, while its sales to nonaffiliated REPs increased.

39

Gross Margin

	Three Months Ended September 30,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	3,510	100	%	$	3,314	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,002	29			1,449	44
Operating costs		334	9			345	10
Depreciation and amortization		211	6			200	6
Gross margin	$	1,963	56	%	$	1,320	40	%

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

Gross margin increased $643 million, or 49%, to $2.0 billion in 2006.

• The TXU Energy Holdings segment’s gross margin increased $648 million, or 70%, to $1.6 billion. The gross margin increase reflected the regulatory-approved price-to-beat increase implemented in October 2005 and January 2006, $185 million in unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of positions in the long-term hedging program and improved productivity of the baseload generation plants.

• The TXU Electric Delivery segment’s gross margin decreased $5 million to $386 million in 2006, driven by higher depreciation and amortization.

Fuel, purchased power costs and delivery fees declined $447 million, or 31%, to $1.0 billion reflecting the reporting of wholesale trading activity on a net basis as discussed in Note 1 to the Financial Statements, as well as the decline in retail sales volumes and improved baseload generation plant productivity.

Operating costs decreased $11 million, or 3%, to $334 million in 2006.

• TXU Energy Holdings’ operating costs decreased $10 million, or 7%, primarily reflecting lower maintenance expenses due to timing of maintenance projects.

• TXU Electric Delivery’s operating costs increased $1 million, or 1%, driven primarily by increased fees paid to third-party transmission entities.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the gross margin table above) increased $13 million, or 6%, to $216 million in 2006. The increased expense reflects higher depreciation related to normal additions and replacements of property, a $4 million adjustment related to capitalized software costs and higher expense associated with mining reclamation obligations.

40

SG&A expenses increased $11 million, or 6%, to $211 million in 2006. The increase reflected:

• $15 million in costs associated with the new generation development programs, principally salaries and consulting expenses;

• $6 million in higher bad debt expense reflecting higher retail accounts receivable balances due to higher prices; and

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

partially offset by:

• $5 million in lower stock-based incentive compensation and deferred compensation expenses;

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

• $3 million benefit from cost reduction initiatives; and

• $2 million in lower consulting fees related to various strategic initiatives.

Franchise and revenue-based taxes increased $9 million, or 10%, to $102 million reflecting higher state gross receipts taxes due to higher revenues and higher city franchise assessments under the TXU Electric Delivery cities rate settlement. See Note 15 to Financial Statements.

Other income totaled $36 million in 2006 and $35 million in 2005. Other deductions totaled $23 million in 2006 and $11 million in 2005. See Note 14 to Financial Statements for detail of other income and deductions.

Interest expense and related charges increased $2 million to $209 million in 2006. The increase reflected $15 million from higher average interest rates (including the effect of interest rate swap transactions), partially offset by $7 million in higher capitalized interest and $6 million due to lower average borrowings.

Income tax expense on income from continuing operations totaled $475 million in 2006 compared to $286 million in 2005. The effective tax rate was 32.6% in 2006 compared to 33.4% in 2005. The lower 2006 effective tax rate reflects increased estimated tax benefits of lignite depletion and the production deduction.

Income from continuing operations (an after-tax measure) increased $413 million, or 72%, to $984 million in 2006.

• Earnings in the TXU Energy Holdings segment increased $441 million, or 96%, to $900 million driven by improved gross margin.

• Earnings in the TXU Electric Delivery segment decreased $14 million, or 10%, to $131 million reflecting increased franchise taxes and other deductions, including $7 million related to the cities rate settlement and $3 million in transition costs related to the InfrastruX joint venture. See Note 15 to Financial Statements.

• Corporate and Other expenses generally consist of interest expense on debt at the TXU Corp. parent, including interest on advances from its subsidiaries, as well as corporate general and administrative expenses. Corporate and other expenses totaled $47 million in 2006 and $33 million in 2005. The increase was driven by higher interest expense on advances from subsidiaries driven by higher average advance balances.

Net pension and other postretirement employee benefit costs reduced income from continuing operations by $10 million in both 2006 and 2005. See Note 10 to Financial Statements.

Results from discontinued operations (an after-tax measure) totaled income of $20 million in 2006 and a loss of $6 million in 2005. See Note 3 to Financial Statements for details.

41

Diluted earnings per share of common stock totaled $2.15 in 2006 and $1.16 in 2005. Diluted earnings per share in 2006 reflected a $0.12 favorable impact from the repurchase of approximately 31 million shares since September 30, 2005. Basic average common shares outstanding decreased 4% to 459 million shares reflecting these share repurchases. Diluted average common shares decreased 5% to 466 million shares. (See Note 1 to Financial Statements.)

TXU Corp. Consolidated

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

TXU Corp.’s operating revenues increased $574 million, or 7%, to $8.5 billion in 2006.

• Operating revenues in the TXU Energy Holdings segment increased $416 million, or 6%, to $7.5 billion. The increase was driven by a $664 million increase in retail electricity revenues. The increase in retail electricity revenues reflected higher pricing, partially offset by the effect of an 11% decline in retail sales volumes. Higher average retail prices reflected increases in natural gas prices that resulted in the regulatory-approved price-to-beat rate increases implemented in May 2005, October 2005 and January 2006. The decline in retail sales volumes reflected a net loss of customers due to competitive activity and lower average consumption per residential and small business customer.

• Operating revenues in the TXU Electric Delivery segment increased $54 million, or 3%, to $1.9 billion in 2006. The revenue increase reflected higher transmission and distribution tariffs, as well as a 1% increase in delivered volumes as a result of warmer weather and growth in points of delivery, partially offset by lower average consumption per end-user.

• Consolidated revenue growth reflected a $104 million reduction in the intercompany sales elimination, primarily reflecting lower sales by TXU Electric Delivery to REP subsidiaries of TXU Energy Company, while its sales to nonaffiliated REPs increased.

Gross Margin

	Nine Months Ended September 30,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	8,481	100	%	$	7,907	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		2,182	26			3,169	40
Operating costs		1,018	12			1,039	13
Depreciation and amortization		615	7			571	7
Gross margin	$	4,666	55	%	$	3,128	40	%

Gross margin increased $1.5 billion, or 49%, to $4.7 billion in 2006.

• The TXU Energy Holdings segment’s gross margin increased $1.5 billion, or 69%, to $3.7 billion. The gross margin increase reflected the regulatory-approved price-to-beat increases implemented in May 2005, October 2005 and January 2006, $191 million in unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of positions in the long-term hedging program, and improved productivity of the baseload generation plants.

• The TXU Electric Delivery segment’s gross margin increased $7 million, or 1%, to $937 million in 2006, driven by higher revenues.

Fuel, purchased power costs and delivery fees declined $987 million, or 31%, to $2.2 billion reflecting the reporting of wholesale trading activity on a net basis as discussed in Note 1 to the Financial Statements, as well as the decline in retail sales volumes and improved baseload generation plant productivity.

42

Operating costs decreased $21 million, or 2%, to $1.0 billion in 2006.

• TXU Energy Holdings’ operating costs decreased $40 million, or 8%, primarily reflecting maintenance costs incurred in 2005 for the nuclear generation plant refueling outage, partially offset by costs related to outsourcing of generation engineering services in 2006.

• TXU Electric Delivery’s operating costs increased $23 million, or 4%, driven primarily by fees paid to third-party transmission entities and increased spending for vegetation management.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the gross margin table above) increased $48 million, or 8%, to $628 million in 2006. The increased expense reflects higher depreciation related to normal additions and replacements of property, higher amortization of the regulatory assets associated with securitization bonds (offset in revenues), higher expense associated with mining reclamation obligations and a $4 million adjustment related to capitalized software costs.

SG&A expenses increased $23 million, or 4%, to $582 million in 2006. The increase reflected:

• $22 million in costs associated with the new generation development programs, principally salaries and consulting expenses;

• $16 million in higher bad debt expense reflecting higher retail accounts receivable balances due to higher prices;

• $15 million in higher fees related to the sale of accounts receivable program due to higher interest rates; and

• $12 million in executive severance costs,

partially offset by:

• $19 million in lower stock-based incentive compensation expense due primarily to fewer share awards and lower expense related to a deferred compensation plan; and

• $9 million in lower consulting fees related to various strategic initiatives, including fees in 2005 relating to the TXU Operating System;

• $6 million benefit from cost reduction initiatives;

• the absence of $4 million in office equipment lease adjustments incurred in 2005; and

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

Franchise and revenue-based taxes increased $18 million, or 7%, to $276 million reflecting higher state gross receipts taxes due to higher revenues and higher city franchise assessments under the TXU Electric Delivery cities rate settlement. See Note 15 to Financial Statements.

Other income totaled $91 million in 2006 and $104 million in 2005. Other deductions totaled $244 million in 2006, which included a $198 million impairment charge related to natural gas-fired generation plants, and $49 million in 2005. See Note 14 to Financial Statements for detail of other income and deductions.

Interest expense and related charges increased $49 million, or 8%, to $640 million in 2006. The increase reflected $67 million from higher average interest rates (including the effect of interest rate swap transactions), partially offset by $14 million in increased capitalized interest and $2 million due to lower average borrowings.

43

Income tax expense from continuing operations totaled $1.0 billion in 2006 compared to $441 million in 2005. The effective tax rate was 34.2% in 2006 compared to 24.5% in 2005. The 2006 amount included a charge of $41 million (1.4 percentage point effective tax rate impact) representing an adjustment to net deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 5 to the Financial Statements. The 2005 amount included $138 million in additional tax benefit (7.6 percentage point effective tax rate impact) related to the TXU Europe write-off as described in Note 4 to the Financial Statements. The increase in 2006 also reflects the significant increase in pretax earnings combined with the effect of lignite depletion and production deduction tax benefits that did not increase in proportion to pretax earnings.

Income from continuing operations (an after-tax measure) increased $636 million, or 47%, to $2.0 billion in 2006.

• Earnings in the TXU Energy Holdings segment increased $872 million, or 87%, to $1.9 billion driven primarily by improved gross margin, partially offset by a charge for the write-down of the natural gas-fired generation plants.

• Earnings in the TXU Electric Delivery segment decreased $20 million, or 7%, to $282 million driven primarily by higher franchise taxes and other deductions, including $10 million related to the cities rate settlement and $3 million in transition costs related to the InfrastruX joint venture.

• Results from Corporate and Other activities totaled $165 million in net expense in 2006 and net income of $51 million in 2005. These results reflect:

• a $71 million after-tax increase in net interest expense related to advances from subsidiaries reflecting higher balances and interest rates;

• a $17 million after-tax gain in 2006 related to a settlement of a telecommunications contract dispute;

• a $10 million after-tax insurance recovery in 2006 related to the 2005 shareholders’ litigation settlement;

• a $138 million tax benefit in 2005 related to TXU Europe (see Note 4 to Financial Statements);

• $23 million after-tax insurance recovery in 2005 related to the shareholders’ litigation settlement;

• a $7 million after-tax litigation settlement charge in 2005; and

• $7 million in equity losses in the unconsolidated affiliate engaged in broadband-over-powerline activities.

Net pension and other postretirement employee benefit costs reduced income from continuing operations by $31 million in 2006 and $29 million in 2005. See Note 10 to Financial Statements.

Income from discontinued operations (an after-tax measure) totaled $81 million in 2006 and $6 million in 2005. See Note 3 to Financial Statements for details.

Diluted earnings per share of common stock totaled $4.43 in 2006 and $1.76 in 2005.

• Diluted earnings per share in 2005 reflect a $1.02 per share unfavorable impact associated with the November 2004 accelerated share repurchase program. See Note 1 to Financial Statements for further discussion.

• Diluted earnings per share in 2006 reflected a favorable $0.21 impact from the repurchase of approximately 31 million shares since September 30, 2005. Basic average common shares outstanding decreased 4% to 460 million shares reflecting these share repurchases. Diluted average common shares decreased 4% to 469 million shares. (See Note 1 to Financial Statements.)

44

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2006. The net changes in these assets and liabilities, excluding “other activity” as described below, represent the net effect of mark-to-market accounting for positions in the commodity contract portfolio, which excludes positions that are subject to cash flow hedge accounting. For the nine months ended September 30, 2006, this effect totaled $87 million in unrealized net losses, which represented $88 million in net losses on open (unsettled) positions less $1 million in reversals of net losses recognized in prior periods on positions settled in the current period. These positions represent both economic hedging and proprietary trading activities.

	Nine Months Ended September 30, 2006
Commodity contract net liability at beginning of period	$	(56	)
Settlements of positions included in the opening balance (1)		1
Unrealized mark-to-market valuations of positions held at end of period (2)		(88	)
Other activity (3)		(16	)
Commodity contract net liability at end of period	$	(159	)

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

(2) Includes gains and losses recorded at contract inception dates. In June 2006, a subsidiary of TXU Corp. entered into a related series of commodity hedge transactions at below-market prices resulting in a $109 million loss at inception date. See Note 11 to Financial Statements.

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

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006			2005
Unrealized gains (losses) related to contracts marked-to-market	$	28	$	(107	)	$	(87	)	$	(95	)
Ineffectiveness gains related to cash flow hedges (a)		157		2			301			8
Total unrealized gains (losses) related to commodity contracts	$	185	$	(105	)	$	214		$	(87	)

(a) See Note 12 to Financial Statements.

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

45

Maturity Table — Of the commodity contract net liability of $159 million at September 30, 2006, the amount representing cumulative unrealized mark-to-market net losses that have been recognized in current and prior years’ earnings totaled $50 million. The remaining net liability of $109 million is comprised principally of amounts representing current and prior years’ net receipts of cash or other consideration, including $102 million related to natural gas physical swap transactions, as well as option premiums net of amortization. The following table presents the unrealized net commodity contract liability arising from mark-to-market accounting as of September 30, 2006, scheduled by contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract net assets (liabilities) at September 30, 2006
	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Source of fair value
Prices actively quoted	$	13		$	18		$	7		$	(2	)	$	36
Prices provided by other external sources(a)		(65	)		7			(93	)		(7	)		(158	)
Prices based on models		43			29			—			—			72
Total	$	(9	)	$	54		$	(86	)	$	(9	)	$	(50	)
Percentage of total fair value		18	%		(108	)%		172	%		18	%		100	%

(a) Includes a “day one” loss of $109 million associated with a related series of commodity hedge transactions. See Note 11 to Financial Statements.

As the above table indicates, 82% of the net liability from unrealized mark-to-market valuations as of September 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 generally extend through 2010 and over-the-counter quotes for natural gas generally extend through 2015 depending upon delivery point. The “prices based on models” category contains the value of all nonexchange traded options, valued using industry accepted option pricing models. In addition, this category contains other contractual arrangements which may have both forward and option components. In many instances, these contracts can be broken down into their component parts and modeled as simple forwards and options based on prices actively quoted. As the modeled value is ultimately the result of a combination of prices from two or more different instruments, it has been included in this category.

46

TXU Energy Holdings

Financial Results

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating revenues	$	3,148		$	2,994		$	7,507		$	7,091
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,348			1,835			3,081			4,173
Operating costs		141			151			442			482
Depreciation and amortization		82			78			252			234
Selling, general and administrative expenses		153			139			403			367
Franchise and revenue-based taxes		31			27			84			77
Other income		2			(19	)		(3	)		(28	)
Other deductions		4			6			205			19
Interest income		(61	)		(21	)		(137	)		(42	)
Interest expense and related charges		109			102			316			287
Total costs and expenses		1,809			2,298			4,643			5,569
Income from continuing operations before income taxes		1,339			696			2,864			1,522
Income tax expense		439			237			985			515
Income from continuing operations	$	900		$	459		$	1,879		$	1,007

47

TXU Energy Holdings

Sales Volume Data

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

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

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

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

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

48

TXU Energy Holdings

Customer Count Data

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

(a) Based on number of meters.

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

49

TXU Energy Holdings

Revenue and Market Share Data

	Three Months Ended September 30,								Nine Months Ended September 30,
	2006			2005			Change %		2006			2005			Change %
Operating revenues:
Retail electricity revenues:
Historical service territory:
Residential	$	1,333		$	1,208		10.3		$	3,086		$	2,682		15.1
Small business (a)		357			333		7.2			923			831		11.1
Total historical service territory		1,690			1,541		9.7			4,009			3,513		14.1
Other territories:
Residential		194			153		26.8			442			309		43.0
Small business (a)		25			24		4.2			61	��		51		19.6
Total other territories		219			177		23.7			503			360		39.7
Large business and other customers		375			347		8.1			1,031			1,006		2.5
Total retail electricity revenues		2,284			2,065		10.6			5,543			4,879		13.6
Wholesale electricity revenues (b)		648			959		(32.4	)		1,629			2,091		(22.1	)
Net gains (losses) from risk management and trading activities		118			(116	)	—			61			(122	)	—
Other revenues		98			86		14.0			274			243		12.8
Total operating revenues	$	3,148		$	2,994		5.1		$	7,507		$	7,091		5.9
Risk management and trading activities:
Realized net gains (losses) on settled positions	$	(67	)	$	(11	)			$	(153	)	$	(35	)
Reversal of prior periods’ unrealized net (gains) losses on positions settled in current period		(21	)		3					1			(20	)
Other unrealized net gains (losses), including cash flow hedge ineffectiveness		206			(108	)				213			(67	)
Total net gains (losses)	$	118		$	(116	)			$	61		$	(122	)
Average revenues per MWh:
Residential	$	151.45		$	121.81		24.3		$	148.44		$	114.71		29.4
Small business	$	145.66		$	117.37		24.1		$	146.44		$	115.09		27.2
Large business and other customers	$	95.83		$	86.61		10.6		$	96.29		$	80.20		20.1
Estimated share of ERCOT retail markets (c)(d):
Historical service territory:
Residential										67	%		74	%
Small business										67	%		73	%
Total ERCOT:
Residential										37	%		40	%
Small business										27	%		30	%
Large business and other customers										16	%		19	%

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

(b) See Note 1 to Financial Statements for discussion of reporting of trading and ERCOT balancing activity in 2006. Includes net purchases related to ERCOT balancing of $32 million in the third quarter of 2006 and $123 million of net sales in the third quarter of 2005, and net purchases of $6 million and net sales of $189 million in the nine months ended September 30, 2006 and 2005, respectively.

(c) Based on number of meters.

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

50

TXU Energy Holdings

Production, Purchased Power and Delivery Cost Data

	Three Months Ended September 30,								Nine Months Ended September 30,
	2006			2005			Change %		2006			2005			Change %
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	22		$	21		4.8		$	65		$	60		8.3
Lignite/coal		124			121		2.5			353			354		(0.3	)
Total baseload fuel		146			142		2.8			418			414		1.0
Natural gas/oil fuel and purchased power		740			1,194		(38.0	)		1,429			2,446		(41.6	)
Other costs		47			64		(26.6	)		169			197		(14.2	)
Fuel and purchased power costs (a)		933			1,400		(33.4	)		2,016			3,057		(34.1	)
Delivery fees (b)		415			435		(4.6	)		1,065			1,116		(4.6	)
Total	$	1,348		$	1,835		(26.5	)	$	3,081		$	4,173		(26.2	)
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.29		$	4.22		1.7		$	4.25		$	4.20		1.2
Lignite/coal (c)	$	11.73		$	11.22		4.5		$	12.11		$	11.71		3.4
Natural gas fuel and purchased power	$	69.87		$	68.32		2.3		$	65.71		$	59.17		11.1
Delivery fee per MWh	$	24.75		$	23.60		4.9		$	25.60		$	23.81		7.5
Production and purchased power volumes (GWh):
Nuclear		5,115			5,099		0.3			15,292			14,146		8.1
Lignite/coal		11,886			11,597		2.5			32,804			32,722		0.3
Total baseload generation		17,001			16,696		1.8			48,096			46,868		2.6
Natural gas-fired generation		1,948			1,682		15.8			3,487			2,947		18.3
Purchased power (a)		8,641			15,798		(45.3	)		18,258			38,397		(52.4	)
Total energy supply		27,590			34,176		(19.3	)		69,841			88,212		(20.8	)
Less line loss and power imbalances		700			277		—			1,514			1,424		6.3
Net energy supply volumes		26,890			33,899		(20.7	)		68,327			86,788		(21.3	)
Baseload capacity factors (%):
Nuclear		101.2	%		100.8	%	0.4			102.0	%		94.2	%	8.3
Lignite/coal		95.8	%		93.2	%	2.8			89.5	%		89.3	%	0.2
Total baseload		97.3	%		95.3	%	2.1			93.1	%		90.7	%	2.6

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

(b) Includes delivery fee charges from TXU Electric Delivery that are eliminated in consolidation ($347 million and $902 million for the three and nine months ended September 30, 2006, respectively, and $386 million and $1.0 billion for the three and nine months ended September 30, 2005).

(c) 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.

51

TXU Energy Holdings

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

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

Operating revenues increased $154 million, or 5%, to $3.1 billion in 2006. Retail electricity revenues increased $219 million, or 11%, to $2.3 billion.

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

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

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

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

52

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 $118 million in 2006 and net losses of $116 million in 2005. Because hedging activities are intended to mitigate the risk of commodity price movements on revenues and fuel and purchased power costs, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on gross margin. Results in 2006 included:

Results associated with the long-term hedging program

These results totaled $185 million in unrealized net gains and $30 million in realized net losses and consisted of:

• $153 million in unrealized cash flow hedge ineffectiveness net gains, which includes $148 million in net gains on unsettled positions and $5 million in net gains that represent reversals of previously recorded unrealized net losses on positions settled in the current period;

• $32 million in unrealized mark-to-market net gains on unsettled positions that are not being accounted for as cash flow hedges; and

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

Results associated with other risk management and trading activities

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

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

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

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

53

Gross Margin

	Three Months Ended September 30,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	3,148	100	%	$	2,994	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,348	43			1,835	61
Generation plant operating costs		141	4			151	5
Depreciation and amortization		80	3			77	3
Gross margin	$	1,579	50	%	$	931	31	%

Gross margin increased $648 million, or 70%, to $1.6 billion in 2006. The gross margin increase reflected the regulatory-approved price-to-beat increase implemented in October 2005 and January 2006, $185 million in unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of positions in the long-term hedging program and improved productivity of the baseload generation plants. The gross margin performance was tempered by the effects of lower retail sales volumes and higher purchased power prices.

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

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

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

• the effect of unrealized cash flow hedge ineffectiveness and mark-to-market gains related to the long-term hedge program (3 percentage point margin increase); and

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

Fuel, purchased power costs and delivery fees declined $487 million, or 27%, to $1.3 billion reflecting the reporting of wholesale trading activity on a net basis as discussed in Note 1 to the Financial Statements, as well as the decline in retail sales volumes and improved baseload generation plant productivity.

Operating costs decreased $10 million, or 7%, to $141 million in 2006. The decrease reflected:

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

• $2 million in savings from staff reductions.

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

54

SG&A expenses increased $14 million, or 10%, to $153 million in 2006. The increase reflected:

• $15 million principally in salaries and consulting expenses related to the new generation development programs;

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

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

partially offset by:

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

• $3 million benefit from cost reduction initiatives;

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

• $2 million in lower consulting fees related to various strategic initiatives.

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

Other income in 2006 was a negative $2 million reflecting a classification correction in the quarter. The 2005 amount totaling $19 million included:

• a $7 million gain on the sale of an investment in a power transmission project;

• a $6 million insurance recovery related to costs incurred for replacement power in connection with a fire in 2002;

• $2 million in gains on the sale of mining lands; and

• a $2 million gain on the sale of surplus equipment.

Other deductions totaled $4 million in 2006 and $6 million in 2005. The 2006 amount included $3 million in equity losses (representing amortization expense) related to the ownership interest in the TXU Corp. subsidiary holding the capitalized software licensed to Capgemini. The 2005 amount included:

• $3 million in transition costs associated with the Capgemini outsourcing agreement; and

• $2 million in equity losses (representing amortization expense) in the TXU Corp. entity holding the capitalized software licensed to Capgemini.

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

Interest expense and related charges increased by $7 million, or 7%, to $109 million in 2006 reflecting $10 million in higher average rates, partially offset by $3 million of higher capitalized interest.

Income tax expense on income from continuing operations totaled $439 million in 2006 compared to $237 million in 2005. The effective tax rate was 32.8% in 2006 compared to 34.1% in 2005. The decrease in the effective tax rate reflects increased estimated tax benefits related to lignite depletion and the production deduction.

Income from continuing operations increased $441 million, or 96%, to $900 million in 2006 driven by improved gross margin.

55

TXU Energy Holdings

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

Operating revenues increased $416 million, or 6%, to $7.5 billion in 2006. Retail electricity revenues increased $664 million, or 14%, to $5.5 billion.

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

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

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

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

56

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 $61 million in 2006 and net losses of $122 million in 2005. Because hedging activities are intended to mitigate the risk of commodity price movements on revenues and fuel and purchased power costs, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on gross margin. Results in 2006 included:

Results associated with the long-term hedging program

These results totaled $191 million in unrealized net gains and consisted of:

• $109 million in an unrealized “day one” loss on a related series of commodity price hedges entered into in June 2006 at below-market prices;

• $272 million in unrealized cash flow hedge ineffectiveness net gains, which includes $277 million in net gains on unsettled positions and $5 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period; and

• $28 million in unrealized mark-to-market net gains on unsettled positions that are not being accounted for as cash flow hedges.

Results associated with other risk management and trading activities

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

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

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

• $37 million in unrealized net losses primarily relating to economic hedge positions that are marked-to-market;

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

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

57

Gross Margin

	Nine Months Ended September 30,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	7,507	100	%	$	7,091	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		3,081	41			4,173	59
Generation plant operating costs		442	6			482	7
Depreciation and amortization		247	3			231	3
Gross margin	$	3,737	50	%	$	2,205	31	%

Gross margin increased $1.5 billion, or 69%, to $3.7 billion in 2006. The gross margin increase reflected the regulatory-approved price-to-beat increases implemented in May 2005, October 2005 and January 2006, $191 million in unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of positions in the long-term hedging program and improved productivity of the baseload generation plants. The gross margin performance was tempered by the effects of lower retail sales volumes and higher purchased power prices.

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

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

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

• the effect of unrealized cash flow hedge ineffectiveness and mark-to-market gains related to the long-term hedge program (1 percentage point margin increase) and;

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

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

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

Operating costs decreased $40 million, or 8%, to $442 million in 2006. The decrease reflected:

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

• $6 million in lower incentive compensation expense; and

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

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) increased $18 million, or 8%, to $252 million reflecting higher expense associated with mining reclamation obligations and rail spur capital lease amortization, partially offset by $4 million in lower depreciation due to the impairment of natural gas-fired generation plants in the second quarter of 2006.

58

SG&A expenses increased by $36 million, or 10%, to $403 million in 2006. The increase reflected:

• $22 million in costs associated with the new generation development programs, principally salaries and consulting expenses;

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

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

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

partially offset by:

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

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

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

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

Other income totaled $3 million in 2006 and $28 million in 2005. The 2005 amount included:

• a $7 million gain on the sale of an investment in a power transmission project;

• a $6 million insurance recovery related to a generation plant fire in 2002;

• a $4 million gain on the sale of mining lands;

• a $4 million gain in connection with a customer’s termination of a power services contract; and

• a $2 million gain on the sale of surplus equipment.

Other deductions totaled $205 million in 2006 and $19 million in 2005. The 2006 amount includes:

• a $198 million charge related to the write-down of the natural gas-fired generation plants to fair value (see Note 2 to Financial Statements); and

• $8 million in equity losses (representing amortization expense) related to the ownership interest in the TXU Corp. subsidiary holding the capitalized software licensed to Capgemini,

partially offset by a $12 million credit related to the favorable settlement of a counterparty default under a coal contract (as noted below, the original charge related to the default was recorded in this line item).

The 2005 amount includes:

• a $12 million charge related to a counterparty default under a coal contract;

• $9 million in transition costs associated with the Capgemini outsourcing agreement;

• $5 million in equity losses (representing amortization expense) related to the ownership interest in the TXU Corp. subsidiary holding the capitalized software licensed to Capgemini;

• $4 million in accretion expense related to a lease liability for gas-fired combustion turbines no longer operated for TXU Energy Holdings’ benefit; and

• a $12 million net credit from a reduction in the combustion turbine lease liability due to a change in estimated sublease proceeds. As the original charge associated with this liability was reported in this line item, the related credit was similarly reported.

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

59

Interest expense and related charges increased by $29 million, or 10%, to $316 million in 2006. The increase reflects higher average interest rates of $27 million, partially offset by higher capitalized interest of $10 million and higher average borrowings of $12 million.

Income tax expense on income from continuing operations totaled $985 million in 2006 compared to $515 million in 2005. The effective tax rate was 34.4% in 2006 compared to 33.8% in 2005. The 2006 amount included a charge of $41 million (a 1.4 percentage point effective tax rate impact) representing an adjustment to deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 5 to the Financial Statements. The 2005 amount reflected a charge of $10 million (a 0.6 percentage point effective tax rate impact) related to the settlement of the IRS audit for the 1994 to 1996 years.

Income from continuing operations increased $872 million, or 87%, to $1.9 billion in 2006 driven by improved gross margin, partially offset by the charge for the write-down of the natural gas-fired generation plants.

60

TXU Electric Delivery

Financial Results

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating revenues	$	708		$	706		$	1,874		$	1,820
Costs and expenses:
Operating costs		194			193			579			556
Depreciation and amortization		128			122			359			334
Selling, general and administrative expenses		44			49			138			140
Franchise and revenue-based taxes		71			65			189			179
Other income		(2	)		(1	)		(2	)		(3	)
Other deductions		11			3			13			9
Interest income		(14	)		(15	)		(43	)		(44	)
Interest expense and related charges		74			67			213			203
Total costs and expenses		506			483			1,446			1,374
Income before income taxes		202			223			428			446
Income tax expense		71			78			146			144
Net income	$	131		$	145		$	282		$	302

61

TXU Electric Delivery

Operating Data

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006		2005		Change %		2006		2005		Change %
Operating statistics – volumes:
Electric energy delivered (GWh)		33,105		34,028	(2.7	)		83,480		82,935	0.7
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)								78.29		78.01	0.4
System Average Interruption Frequency Index (SAIFI) (nonstorm)								1.16		1.19	(2.5	)
Customer Average Interruption Duration Index (CAIDI) (nonstorm)								67.31		65.45	2.8
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters) (b)								3,051		3,009	1.4
Operating revenues:
Electricity distribution revenues (c):
Affiliated (TXU Energy Company)	$	344	$	384	(10.4	)	$	894	$	998	(10.4	)
Nonaffiliated		296		262	13.0			782		645	21.2
Total distribution revenues		640		646	(0.9	)		1,676		1,643	2.0
Third-party transmission revenues		60		54	11.1			176		158	11.4
Other miscellaneous revenues		8		6	33.3			22		19	15.8
Total operating revenues	$	708	$	706	0.3		$	1,874	$	1,820	3.0

(a) SAIDI is the average number of electric service outage minutes per customer in a year. SAIFI is the average number of electric service interruptions per customer in a year. CAIDI is the average duration in minutes of interruptions to electric service in a year. The statistics presented are based on the preceding twelve months’ data.

(b) Includes lighting sites, primarily guard lights, for which TXU Energy Company is the REP but are not included in TXU Energy Company’s customer count. Such sites totaled 83,068 and 87,326 at September 30, 2006 and 2005, respectively.

(c) Includes transition charges associated with the issuance of securitization bonds totaling $44 million and $48 million for the three months ended September 30, 2006 and 2005, respectively, and $117 million and $116 million for the nine months ended September 30, 2006 and 2005, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

62

TXU Electric Delivery

TXU Electric Delivery’s future results are expected to be impacted by the effects of the cities rate settlement described in Note 15 to the Financial Statements. Incremental expenses of approximately $70 million are being recognized almost entirely over the period from May 2006 through June 2008, of which $7 million and $10 million has been recognized in the three and nine month periods ended September 30, 2006, respectively.

TXU Electric Delivery’s future results are also expected to be impacted by additional transition costs associated with the InfrastruX Energy Services joint venture totaling an estimated $16 million, of which approximately $3 million is expected to be expensed in the fourth quarter of 2006 and the balance in the first half of 2007.

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

Operating revenues increased $2 million, or less than 1%, to $708 million in 2006. Delivered volumes decreased 3%. The revenue increase reflected:

• $6 million in higher transmission revenues primarily due to rate increases approved in 2005 and 2006 to recover ongoing investment in the transmission system;

• an estimated $5 million due to growth in points of delivery; and

• $2 million from increased distribution tariffs to recover higher transmission costs,

partially offset by:

• an estimated $10 million decline due to lower delivered volumes as the effect of warmer weather on energy consumption was more than offset by end-user efficiency measures in response to energy prices and warmer weather; and

• $3 million in lower securitization transition revenue (offset by lower amortization of the related regulatory asset). The decline was due to a true-up of tariffs reflected in 2005 revenues.

Gross Margin

	Three Months Ended September 30,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	708	100	%	$	706	100	%
Costs and expenses:
Transmission and distribution system operating costs		194	27			193	28
Depreciation and amortization		128	18			122	17
Gross margin	$	386	55	%	$	391	55	%

Operating costs rose $1 million, or less than 1%, to $194 million in 2006. The increase included $5 million in increased fees paid to third-party transmission entities, partially offset by $2 million in lower costs associated with meter installation activities.

Depreciation and amortization (essentially all of which related to the delivery system as shown in the gross margin table above) increased $6 million, or 5%, to $128 million in 2006. The increase reflected $6 million in higher depreciation due to normal additions and replacements of property, plant, and equipment and a $4 million adjustment related to capitalized software costs, partially offset by $3 million in lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues).

SG&A expenses decreased $5 million, or 10%, to $44 million in 2006. The decrease primarily reflected $2 million in lower civic-support costs and $1 million in lower incentive compensation expense.

63

Franchise and revenue-based taxes increased $6 million, or 9%, to $71 million in 2006. The increase was driven by higher sales volumes in the period to which the tax applies and also includes $1 million in higher franchise fees under the cities rate settlement. See Note 15 to Financial Statements.

Other deductions totaled $11 million in 2006 and $3 million in 2005. The 2006 amount includes:

• $6 million in costs under the cities rate settlement (See Note 15 to Financial Statements);

• $3 million in transition costs related to the previously disclosed InfrastruX Energy services joint venture; and

• $1 million in equity losses (representing amortization expense) related to the ownership interest in the TXU Corp. subsidiary holding the capitalized software licensed to Capgemini.

The 2005 amount included:

• $1 million in costs associated with transitioning the outsourced activities to Capgemini; and

• $1 million in equity losses (representing amortization expense) for TXU Electric Delivery’s ownership interest of the TXU Corp. subsidiary holding the capitalized software licensed to Capgemini.

Interest expense increased $7 million, or 10%, to $74 million in 2006 primarily due to higher average balances of commercial paper outstanding.

Income tax expense totaled $71 million in 2006 compared to $78 million in 2005. The effective tax rate was comparable at 35.1% for 2006 and 35% for 2005.

Net income decreased $14 million, or 10%, to $131 million driven by costs associated with the cities rate settlement, higher depreciation and amortization and the transition costs related to the InfrastruX Energy Services joint venture. Higher interest expense was largely offset by lower SG&A expenses.

64

TXU Electric Delivery

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

Operating revenues increased $54 million, or 3%, to $1.9 billion in 2006. Delivered volumes rose less than 1%. The revenue increase reflected:

• $18 million in higher transmission revenues primarily due to rate increases approved in 2005 and 2006 to recover ongoing investment in the transmission system;

• an estimated $13 million due to growth in points of delivery;

• an estimated $9 million in higher revenues as the effect of warmer weather on energy consumption was partially offset by end-user efficiency measures in response to energy prices and warmer weather;

• $6 million from increased distribution tariffs to recover higher transmission costs; and

• $2 million in higher securitization transition revenues related to tariff true-ups (offset by higher amortization of the related regulatory asset).

Gross Margin

	Nine Months Ended September 30,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	1,874	100	%	$	1,820	100	%
Costs and expenses:
Transmission and distribution system operating costs		579	31			556	31
Depreciation and amortization		358	19			334	18
Gross margin	$	937	50	%	$	930	51	%

Operating costs rose $23 million, or 4%, to $579 million in 2006. The increase reflected $14 million in increased fees paid to third party transmission entities and $9 million in increased spending for vegetation management.

Depreciation and amortization (essentially all of which related to the delivery system as shown in the gross margin table above) increased $25 million, or 7%, to $359 million in 2006. The increase reflected $17 million in higher depreciation due to normal additions and replacements of property, plant and equipment, a $4 million adjustment related to capitalized software costs and $3 million in higher amortization of the regulatory assets associated with the securitization bonds (offset in revenues and other income).

SG&A expenses decreased $2 million, or 1%, to $138 million in 2006. The decrease reflected the absence of $4 million in office equipment lease adjustments incurred in 2005 and $2 million in lower incentive compensation expense, offset by $2 million in executive severance expenses (allocated by TXU Corp.) and $2 million in higher sale of receivables program fees driven by higher interest rates.

Franchise and revenue-based taxes increased $10 million, or 6%, to $189 million in 2006. The increase was driven by higher sales volumes in the period to which the tax applies and also includes $4 million in higher franchise fees under the cities rate settlement. See Note 15 to Financial Statements.

65

Other deductions totaled $13 million in 2006 and $9 million in 2005. The 2006 amount includes:

• $6 million in costs under the cities rate settlement (See Note 15 to Financial Statements);

• $3 million in transition costs related to the previously disclosed InfrastruX Energy Services joint venture; and

• $3 million in equity losses (representing amortization expense) related to the ownership interest in the TXU Corp. subsidiary holding the capitalized software licensed to Capgemini.

The 2005 amount included:

• $3 million in costs associated with transitioning the outsourced activities to Capgemini;

• $2 million of severance-related charges related to the 2004 restructuring actions; and

• $2 million in equity losses (representing amortization expense) for TXU Electric Delivery’s ownership interest of the TXU Corp. subsidiary holding the capitalized software licensed to Capgemini.

Interest expense increased $10 million, or 5%, to $213 million in 2006 due to higher average balances of commercial paper outstanding.

Income tax expense totaled $146 million in 2006 compared to $144 million in 2005. The effective tax rate increased to 34.1% in 2006 from 32.3% in 2005. The 2005 amount reflected a credit of $4 million (a 0.9 percentage point effective tax rate impact) related to the settlement of an IRS audit for the 1994 to 1996 years. The higher effective tax rate also reflected adjustments in 2006 related to the filing of the 2005 federal income tax return.

Net income decreased $20 million, or 7%, to $282 million driven by a higher effective income tax rate and increased revenue-based taxes. Higher interest expense was largely offset by increased gross margin.

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COMPREHENSIVE INCOME – Continuing Operations

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
Net increase (decrease) in fair value of cash flow hedges (all commodity) held at end of period	$	401	$	(71	)	$	431	$	(58	)
Derivative value net losses reported in net income that relate to hedged transactions recognized in the period:
Commodities		9		14			16		47
Financing – interest rate swaps		2		4			6		12
		11		18			22		59
Total income (loss) effect of cash flow hedges reported in other comprehensive income from continuing operations	$	412	$	(53	)	$	453	$	1

TXU Corp. 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 recognized in net income.

See Note 12 to Financial Statements.

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FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash flows provided by operating activities for the nine months ended September 30, 2006 totaled $4.0 billion for an increase of $2.0 billion over the nine months ended September 30, 2005. The improvement reflected:

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

• utilization of net operating loss carryforwards, which are expected to total $1.2 billion for the 2006 year, that reduces the amount of income taxes that would otherwise be payable related to 2006 earnings;

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

• a favorable change of $102 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, partially offset by decreased proceeds from the accounts receivable sales program; and

• an $84 million payment in 2005, net of insurance recoveries, to settle the consolidated amended securities class action lawsuit.

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

	Nine Months Ended September 30,
	2006			2005
Net repayments, repurchases and issuances of borrowings	$	(992	)	$	159
Net repurchases and issuances of common stock		(832	)		(542	)
Net repurchases of preference and preferred stock		—			(338	)
Common stock dividends paid		(575	)		(408	)
Preference stock dividends paid		—			(11	)
Excess tax benefit on stock-based incentive compensation		47			28
Total	$	(2,352	)	$	(1,112	)

Cash flows used in investing activities increased $951 million as summarized below:

	Nine Months Ended September 30,
	2006			2005
Capital expenditures, including nuclear fuel	$	(1,486	)	$	(792	)
Purchase of lease trust		(69	)		—
Deposit of proceeds from pollution control revenue bonds with trustee		(99	)		—
Net investments in nuclear decommissioning trust fund securities		(12	)		(11	)
Proceeds from sale of assets		15			76
Investment in unconsolidated affiliate		(15	)		—
Costs to remove retired property		(33	)		(34	)
Other		(6	)		7
Total	$	(1,705	)	$	(754	)

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $48 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.

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Long-term Debt Activity—During the nine months ended September 30, 2006, TXU Corp. issued, reacquired, or made scheduled principal payments on long-term debt as follows (all amounts presented are principal):

	Issuances		Repayments and Repurchases
TXU Corp.:
Senior notes	$	—	$	683
Equity-linked senior notes		—		179
Other long-term debt		—		10
TXU Energy Company:
Pollution control revenue bonds		100		203
Senior notes		—		400
Other long-term debt		—		2
TXU Electric Delivery:
Transition bonds		—		62
US Holdings		—		8
Total	$	100	$	1,547

See Note 7 to Financial Statements for further detail of debt issuances and retirements and financing arrangements.

Credit Facilities— At October 23, 2006, subsidiaries of TXU Corp. had access to credit facilities totaling $6.5 billion of which $5.3 billion was unused. The facilities expire on various dates between May 2007 and June 2010. The maximum amount TXU Energy Company and TXU Electric Delivery can directly access under the facilities is $6.5 billion and $3.6 billion, respectively. These 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 7 to Financial Statements for details of the arrangements.

Capital Expenditures— Capital expenditures for 2006 are expected to total approximately $2.6 billion, including $840 million for investment in transmission and distribution infrastructure, $1.3 billion for new lignite/coal-fired generation facilities and $480 million for maintenance and upgrades of existing generation assets.

Financing for New Generation Development Program—As discussed above under “Significant Developments in 2006”, TXU DevCo has secured a financing commitment for $11 billion to fund its development and construction of up to 11 new generation units in Texas. The financing is expected to close in the first half of 2007. Borrowings by TXU DevCo under the agreement are expected to be nonrecourse to TXU Corp.

Pension Protection Act — In August 2006, the Pension Protection Act of 2006 (the Act) was signed into law. The Act is expected to increase plan funding and require additional plan disclosures in regulatory filings and to plan participants. The Act will be phased in over the next few years. Pension funding for TXU Corp. is expected to total approximately $135 million in 2007 and $90 million in 2008, including the effects of the Act. No funding is expected in 2006.

Income Tax Payments —Absent the effects of any potential transactions, federal income tax payments in 2006 are now estimated to total approximately $80 million. The remaining estimated 2006 income tax liability of $170 million to $220 million is expected to be paid in March 2007 upon the filing of a request for extension for the 2006 federal income tax return.

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Short-term Borrowings—At October 23, 2006, subsidiaries of TXU Corp. had $1.1 billion of commercial paper outstanding and $295 million of bank borrowings under credit facilities. The commercial paper funds short-term liquidity requirements.

Dividends–On November 3, 2006, the TXU Corp. board of directors declared a common stock dividend in the amount of $0.4325 per share, an increase of 5% over the previous quarter, payable on January 2, 2007 to shareholders of record as of December 1, 2006. The increase sets the common stock dividend at an annual rate of $1.73 per share. The dividend rate and annual dividend growth rate will be subject to regular review by TXU Corp.’s board of directors and may be changed at any time based upon a number of factors, particularly those factors discussed below under “Risk Factors”.

Common Stock Repurchase—In November 2005, the TXU Corp. board of directors authorized the repurchase of up to 34 million shares of common stock through the end of 2006. As of October 23, 2006, approximately 31 million of the 34 million shares authorized have been repurchased. In November 2006, the TXU Corp. board of directors extended to the end of 2007 the authority for the remaining 3 million shares to be repurchased. In addition, in November 2006, the TXU Corp. board of directors authorized the repurchase of up to an additional 20 million shares of common stock through the end of 2007. TXU Corp. plans to apply its capital allocation philosophy in determining the timing and amount of repurchases under these authorizations, and the ultimate timing and amount of shares repurchased, if any, will depend on a number of factors, particularly those factors discussed below under “Risk Factors”.

Sales of Accounts Receivable — Subsidiaries of TXU Corp. participate in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of TXU Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions. All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program at September 30, 2006 and December 31, 2005 totaled $700 million and $671 million, respectively. See Note 6 to Financial Statements for a more complete description of the program including the impact on the financial statements for the periods presented and the contingencies that could result upon the termination of the program.

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

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

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

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

• $449 million in letters of credit have been posted with counterparties as collateral.

With respect to collateral received, subsidiaries of TXU Corp. have 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 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 Corp.’s liquidity.

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With respect to positions under the long-term hedging program as of October 13, 2006, for each $1.00 per MMBtu increase in natural gas prices, TXU Corp. could be required to post up to approximately $1 billion in additional collateral and/or financial margining. Transactions requiring daily margining account for approximately 52% of the long-term hedge positions and are generally met by cash postings. For the remainder, collateral settlements are being met by a combination of the Big Brown Lien, letters of credit and cash postings as required periodically by counterparties.

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

Credit Ratings

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

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

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

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

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

Material Credit Rating Covenants

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

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

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

ERCOT also has rules in place to assure adequate credit worthiness for parties that schedule power on the ERCOT System. Under those rules, if TXU Energy Company’s credit rating were downgraded to below investment grade by any specified rating agency, TXU Energy Company could be required to post collateral of approximately $25 million as of September 30, 2006.

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

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

Other arrangements of TXU Corp. and its subsidiaries, 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.

Material Cross Default Provisions

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

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

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

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

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TXU Corp. 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 Corp. 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.

TXU DevCo’s commodity hedging agreement contains a cross default provision. In the event of a default by TXU DevCo under the agreement, including certain cross-acceleration events relating to the indebtedness of TXU DevCo or its subsidiaries in an amount equal to or greater than $50 million before initial funding under the credit facilities for its new generation development program and $100 million thereafter, the hedge counterparty may terminate the transactions, including any novated transactions, covered by the hedging agreement.

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

Long-term Contractual Obligations and Commitments — Significant changes to the contractual cash obligations of TXU Corp. and its subsidiaries since December 31, 2005 as disclosed in the 2005 Form 10-K are shown below.

Increases in Contractual Cash Obligations since December 31, 2005—

	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Contracts related to generation development programs (a)	$	797	$	3,117	$	85	$	—	$	3,999
Obligations under commodity purchase agreements	$	—	$	653	$	—	$	311	$	964

(a) Amounts represent scheduled payments under the contracts. Contingent cancellation costs are expected to increase to an estimated $1.3 billion by December 31, 2006 (See Note 9 to Financial Statements). Recovery values upon cancellation related to assets acquired and owned assets that are intended to be utilized in the program are estimated at 40% to 80% of the contingent cancellation costs.

OFF BALANCE SHEET ARRANGEMENTS, INCLUDING VARIABLE INTEREST ENTITIES

Subsidiaries of TXU Corp. participate in an accounts receivable securitization program. See discussion above under “Sales of Accounts Receivable” and in Note 6 to Financial Statements.

Also see Note 9 to Financial Statements regarding guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 9 to Financial Statements for discussion of commitments and contingencies.

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REGULATION AND RATES

Wholesale Market Activity Investigation— See Note 9 to Financial Statements for discussion.

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

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

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

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

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

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

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

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

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

The Texas franchise tax system is being replaced with a new tax system, referred to as the Texas margin tax. The Texas margin tax is a significant change in Texas tax law because it generally makes all legal entities subject to tax, including general and limited partnerships, while the current franchise tax system applies only to corporations and limited liability companies. TXU Corp.’s subsidiaries conduct significant operations through Texas limited partnerships that will become subject to the new Texas margin tax. The effective date of the Texas margin tax is January 1, 2008 for calendar year-end companies and the computation of tax liability is expected to be based on 2007 revenues as reduced by certain deductions. The new margin tax is expected to increase TXU Corp.’s annual state franchise tax expense by approximately $30 million beginning in 2007. Also see Note 5 to Financial Statements.

The property tax relief law is expected to reduce school taxes assessed to TXU Corp. and its subsidiaries by an estimated $12 million in 2006 and $40 million annually in 2007 and subsequent years (based on current property values and without regard to any property additions).

Transmission Rates— In order to recover increased affiliate and third-party transmission costs from REPs, TXU Electric Delivery is allowed to request an update twice a year to the TCRF component of its retail delivery rate. In July 2006, an application was filed to increase the TCRF, which became effective September 1, 2006. This increase is expected to result in an annual increase of $24 million in the TCRF component of TXU Electric Delivery’s retail delivery rates charged to REPs and includes $7 million of the wholesale transmission rate increase described below.

TXU Electric Delivery filed an application for an interim update of its wholesale transmission rate which was approved by the Commission in April 2006 and the new rate went into effect immediately. Annualized revenues are expected to increase by approximately $19 million. Approximately $12 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $7 million is recoverable from REPs through the retail transmission cost recovery factor (TCRF) component of TXU Electric Delivery’s delivery rates charged to REPs.

Automated Meter Reading— In 2005, the Texas legislature passed legislation that authorized utilities to impose a surcharge to recover costs incurred in deploying advanced metering and meter information networks. Benefits of the advanced metering installation include improved safety, on-demand meter reading, enhanced outage identification and restoration and system monitoring of voltages. At September 30, 2006, TXU Electric Delivery had installed approximately 214,000 advanced meters in its service territory and anticipates installation of approximately 370,000 automated meters by year-end 2006, which would represent approximately 12% of the meters on the distribution system. Commission staff have initiated rulemaking that may address various automated meter reading issues, including cost recovery. TXU Corp. cannot predict the outcome of this rulemaking. TXU Electric Delivery anticipates filing a surcharge request in the near future to seek recovery of investment costs incurred.

Cities Rate Settlement — As previously disclosed, in January 2006 TXU Electric Delivery agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the Commission to no later than June 30, 2008 (based on a test year ending December 31, 2007), unless the Cities and TXU Electric Delivery mutually agree that such a filing is unnecessary. TXU Electric Delivery has extended the benefits of the agreement to 292 nonlitigant cities. Based on the final agreements, including the participation of the nonlitigant cities, expected payments to the cities are estimated to total approximately $70 million, including incremental franchise taxes.

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This amount is being recognized in earnings over the period from May 2006 through June 2008. Payments under the agreement are expected to be made until new tariffs are effective, which based upon an assumed June 2008 rate case filing, is projected to be mid-2009. Payments under the agreement are expected to total approximately $17 million in 2006, of which $10 million has been expensed through the third quarter, $30 million in 2007, $16 million in 2008 and $7 million in 2009. See Note 15 to Financial Statements.

Wholesale Market Design— In August 2003, the Commission adopted a rule that, when implemented, will alter the wholesale market design in ERCOT. The rule requires ERCOT:

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

• to operate a voluntary day-ahead energy market;

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

• to use nodal energy prices for resources;

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

• to use zonal prices for loads; and

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

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

Commission Review of InfrastruX Joint Venture— As discussed above under “Significant Developments in 2006”, TXU Corp. and InfrastruX Group have announced the formation of a joint venture, InfrastruX Energy Services, that expects to provide utility construction, power restoration, maintenance and other services. TXU Corp. also announced an agreement between TXU Electric Delivery and InfrastruX Energy Services under which TXU Electric Delivery will receive services from the joint venture. The Commission recently announced its desire to gather further information regarding the joint venture. On November 6, 2006, the Commission filed a proposed procedural schedule outlining key events and dates related to the review. While the Commission does not believe an evidentiary hearing is needed, an intervening party may request that one be held. If no hearing is necessary, initial briefs are due January 24, 2007 and reply briefs are due February 7, 2007. TXU Electric Delivery cannot predict the ultimate outcome of this process, including its possible effect on the timing of the closure of the transaction.

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

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

CHANGES IN ACCOUNTING STANDARDS

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk that TXU Corp. may experience a loss in value as a result of changes in market conditions affecting commodity prices and interest rates, which TXU Corp. is exposed to in the ordinary course of business. TXU Corp.’s exposure to market risk is affected by a number of factors, including the size, duration and composition of its energy and financial portfolio, as well as the volatility and liquidity of markets. TXU Corp. 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 Corp.’s wholesale business manages the market, credit and operational risk related to commodity prices of the unregulated energy business within limitations established by senior management and in accordance with TXU Corp.’s overall risk management policies. Interest rate risks are managed centrally by the corporate treasury function. Market risks are monitored daily by risk management groups that operate and report independently of the wholesale commercial operations, utilizing industry accepted practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (VaR) methodologies.

TXU Corp. has a corporate risk management organization that is headed by a Chief Risk Officer. The Chief Risk Officer, through his designees, enforces all applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in the various businesses of TXU Corp. 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 Corp.’s businesses are subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products they market or purchase. TXU Corp.’s businesses actively manage their portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. These businesses, similar to other participants in the market, cannot fully manage the long-term value impact of structural declines or increases in natural gas, power and oil prices and spark spreads (differences between the market price of electricity and its cost of production).

In managing energy price risk, subsidiaries of TXU Corp. 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 Corp. strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

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

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

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

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

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

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

	September 30, 2006				December 31, 2005
	Five-day to 60 day holding period		Five-day holding period		Five-day holding period
Period-end MtM VaR:	$	391	$	117	$	19
Average Month-end MtM VaR:	$	100	$	34	$	20

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

	September 30, 2006				December 31, 2005
	Five to 60 day holding period		Five-day holding period		Five-day holding period
EaR	$	386	$	112	$	32

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

INTEREST RATE RISK

See Note 7 to Financial Statements for a discussion of debt-related activity since December 31, 2005.

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CREDIT RISK

Credit Risk— Credit risk relates to the risk of loss associated with nonperformance by counterparties. TXU Corp. and its subsidiaries maintain credit risk policies with regard to their counterparties to minimize overall credit risk. These policies require an evaluation of a potential counterparty’s financial condition, credit rating and other quantitative and qualitative credit criteria and specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. TXU Corp. 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 Corp. or its subsidiaries. Additionally, TXU Corp. 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 — Gross exposure of TXU Corp.’s businesses to credit risk, which totaled approximately $2.4 billion at September 30, 2006, represents trade accounts receivable, as well as net asset positions arising from hedging and trading activities.

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

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

Of this $1.3 billion exposure, 86% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and TXU Corp.’s internal credit evaluation process. Those customers and counterparties without an S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate an S&P equivalent rating. TXU Corp. routinely monitors and manages its credit exposure to these customers and counterparties on this basis.

In addition, TXU Electric Delivery has exposure to credit risk totaling $214 million at September 30, 2006 arising from potential nonperformance by nonaffiliated REPs. This exposure consists almost entirely of noninvestment grade trade accounts receivable.

TXU Corp. is also exposed to credit risk related to the Capgemini put option with a carrying value of $177 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 agreements with TXU Energy Company and TXU Electric Delivery, as well as the payment in connection with a put option. S&P currently maintains a BB+ rating with a positive outlook for Cap Gemini S.A.

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

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

Approximately 67% of the net $1.3 billion credit exposure has a maturity date of two years or less. TXU Corp. does not anticipate any material adverse effect on its financial position or results of operations due to nonperformance by any customer or counterparty.

TXU Corp.’s subsidiaries had credit exposure to two counterparties having an exposure greater than 10% of the net $1.3 billion credit exposure. These two counterparties represented 14% and 12%, respectively, of the net exposure. TXU Corp. views its subsidiaries’ exposure with these two counterparties to be within an acceptable level of risk tolerance.

TXU Corp.’s subsidiaries are exposed to credit risk related to its long-term hedging program. Of the transactions in the program, over 97% of the volumes are with counterparties with an A credit rating or better, and 100% are at least investment grade.

Additionally, under the long-term hedging program, TXU Corp. has potential credit risk exposure concentration related to a single counterparty. A related series of hedge transactions with this counterparty contain certain credit rating provisions that would require the counterparty to post collateral in the form of cash in the event of significant declines in natural gas prices and a material downgrade in the credit rating of the counterparty. TXU Corp. views the potential concentration of risk with this counterparty to be within acceptable risk tolerance due to the strong financial profile of the counterparty and it’s A or above rating.

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by TXU Corp. contain “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 Corp. 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 Corp.’s business and operations (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “projection,” “target,” “outlook”), are forward-looking statements. Although TXU Corp. 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 Corp. 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;

• allowed rates of return;

• 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 Corp.’s ability to attract and retain profitable customers;

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

• changes in wholesale electricity prices or energy commodity prices;

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

• TXU Corp.’s ability to effectively hedge against changes in commodity prices and market heat rates;

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

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

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

• access to adequate transmission facilities to meet changing demands;

• unanticipated changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;

• 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;

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• inability of various counterparties to meet their obligations with respect to TXU Corp.’s financial instruments;

• changes in technology used by and services offered by TXU Corp.;

• significant changes in TXU Corp.’s 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 Corp.;

• actions by credit rating agencies;

• the ability of TXU Corp. to implement cost reduction initiatives;

• with respect to TXU Corp.’s lignite/coal generation development program, more specifically, TXU Corp.’s ability to fund such investments, delays in the approval of, or failure to obtain, air and other environmental permits, and the ability to satisfactorily resolve issues relating to the Sandow consent decree, changes in competitive market rules, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity in Texas, the ability of TXU Corp. and its contractors to attract and retain, at projected rates, skilled labor for constructing the new generating units, the ability to negotiate and finalize engineering, procurement and construction contracts for the reference plants in a timely manner and with terms and costs that do not materially impact the value of the projects, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, changes in the cost and availability of materials necessary for the construction program and the ability of TXU Corp. to manage the significant construction program to a timely conclusion with limited cost overruns; and

• with respect to the InfrastruX Energy joint venture, the amount of time the Commission takes to review the transaction and the results of such review.

Any forward-looking statement speaks only as of the date on which it is made, and TXU Corp. 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 Corp. to predict all of them; nor can TXU Corp. assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Item 4. CONTROLS AND PROCEDURES.

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to the discussion in Note 9 regarding legal proceedings.

Item 1A. Risk Factors.

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

TXU Corp.’s growth strategy, including its investment in lignite/coal-fired generation facilities, may not be executed as planned which could adversely impact its financial condition and results of operations.

There can be no guarantee that the execution of TXU Corp.’s growth strategy will be successful. As discussed below, TXU Corp’s growth strategy is dependent upon many factors. Unanticipated changes in laws, regulations, markets, costs or other factors could negatively impact the execution of TXU Corp.’s growth strategy, including causing management to change the strategy. Even if TXU Corp. is able to execute its growth strategy, it may take longer than expected at costs higher than expected.

With respect to TXU Corp.’s lignite/coal-fired generation development program, there can be no guarantee that the execution of such program will be successful. While TXU Corp. has vast experience in operating lignite/coal-fired generation facilities, TXU Corp. has limited experience in developing such facilities. To the extent construction, including any related rail construction, is not managed efficiently and to a timely conclusion, cost overruns may occur resulting in the overall program costing significantly more than anticipated. This may also result in delays in the expected online dates for the facilities resulting in less overall income than projected. While TXU Corp. believes it can acquire the resources needed to effectively execute this program, TXU Corp. is exposed to the risk that it may not be able to attract and retain skilled labor, at projected rates, for developing and constructing these new facilities. TXU Corp. has not yet negotiated final engineering, procurement and construction (EPC) contracts for most of its planned generation facilities. Until these contracts are finalized, TXU Corp. will not be able to determine a definitive range of the costs for the facilities nor can it determine what related risks it may be required to bear.

TXU Corp.’s lignite/coal-fired generation development program is subject to permitting risks. TXU Corp. may not be able to obtain in a timely manner, if at all, all of the permits necessary to develop and operate these new facilities. Obtaining all permits necessary for the program, and the timely issuance of such permits, could be impeded by litigation against TXU Corp. and/or the applicable regulatory agencies. In addition, obtaining all permits necessary for the program, and the timely issuance of such permits, is subject to the regulatory approval process. Some, if not all, of the reference plant permits are expected to be opposed and the Oak Grove permit has been opposed and the subject of a contested case hearing that resulted in an unfavorable recommendation from the State Office of Administrative Hearings. In addition, while there is an existing air permit for the Sandow project under which the project is being constructed, it was issued pursuant to a consent decree issued by a federal court that contains certain provisions that create risks to the project including a provision that requires the project to be commercially operational by April 25, 2007, TXU Corp. is currently working with Alcoa, its counterparty on the project, to obtain resolution of the issues related to the consent decree; however, there can be no assurance that such issues will be resolved favorably. If the necessary environmental permits are not obtained and the consent decree is not adequately resolved and all 11 power generation plants are cancelled, given the strategy of conducting engineering and ordering of major equipment in parallel with the permitting process, TXU Corp. would have exposure to a number of different engineering and equipment cancellation costs. Such contingent cancellation costs totaled approximately $675 million at September 30, 2006 and are expected to increase to approximately $1.3 billion by December 31, 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 program.

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TXU Corp.’s lignite/coal-fired generation development program is subject to changes in laws, regulations and policies that are beyond TXU Corp.’s control. Any unanticipated change in law, regulation or policy regarding commodity prices, power prices, electric competition or solid-fuel generation facilities or other related matters could adversely impact this program. As a result of recent natural disasters, such as Hurricane Katrina, global warming has received significant media attention. Any unanticipated change in environmental law, regulation or policy, such as regulations of emissions of carbon dioxide, if not implemented in a manner that focuses on technology, incentives and a functioning wholesale market, could adversely impact this program.

TXU Corp.’s lignite/coal-fired generation development program is subject to changes in the electricity market, primarily ERCOT for its new build program in Texas, that are beyond TXU Corp.’s control. If demand growth is less than expected or if other generation companies build new generation assets in markets that TXU Corp. builds generation assets, TXU Corp.’s program could impact market prices of power such that the new generation capacity becomes uneconomic. In addition, any unanticipated reduction in wholesale electricity prices, market heat rates and natural gas prices, which could occur for a variety of reasons, could adversely impact this program. Even if TXU Corp. enters into hedges to reduce such exposures, TXU Corp. would still be subject to the credit risk of its counterparties. In addition, unanticipated increases in the price of fuel, particularly Powder River Basin coal, or rail transportation could result in unexpected costs to operate the new facilities.

TXU Corp.’s lignite/coal-fired generation development program is subject to other risks that are beyond TXU Corp.’s control. For example, TXU Corp. is exposed to the risk that a change in technology for electric generation facilities and/or emissions control technologies may make other generation facilities less costly and more attractive than TXU Corp.’s new lignite/coal-fired generation facilities. TXU Corp. is also subject to risks relating to transmission capabilities and constraints. TXU Corp. is also exposed to changes in the cost and availability of materials necessary for the development and construction of the new facilities. TXU Corp. is also exposed to the risk that its contractors may default on their obligations to TXU Corp. and damages received, if any, will not cover TXU Corp.’s losses.

TXU Corp.’s ability to finance the construction of the new generation facilities is subject to a variety of risks. The ability to finance the projects on a non-recourse basis is contingent on a number of factors, including the terms of the EPC contracts, construction costs, capital and bank market conditions as well as the project finance entity’s separateness from TXU Corp. and its other subsidiaries. To the extent TXU Corp. is not able to use non-recourse financing or if the rating agencies attribute a material amount of the project finance debt to TXU Corp.’s credit, the financing of the plants could have a negative impact on the credit ratings of TXU Corp. and its other subsidiaries.

With respect to TXU Corp.’s capital deployment program for its electric delivery facilities, there can be no guarantee that the execution of such program will be successful. There can be no assurance that the capital investments TXU Corp. intends to make in connection with its electric delivery business will produce the desired reductions in cost and improvements to service and reliability.

        InfrastruX Energy Services faces challenges to transition into a consolidated and independent business. It may not be able to provide TXU Electric Delivery sufficient services.

TXU Corp. has agreed to form a joint venture with InfrastruX Group. This joint venture, InfrastruX Energy Services, will have to undertake significant actions to integrate the legacy operations of InfrastruX Group, Inc. with the functions required under the services agreement with TXU Electric Delivery prior to the commencement of InfrastruX Energy Services’ operations. InfrastruX Energy Services may not have sufficient resources to adequately complete these actions on a timely basis. If these actions cannot be accomplished, the operational performance of InfrastruX Energy Services and its ability to provide services to TXU Electric Delivery could be affected.

The ownership structure of InfrastruX Energy Services and the services agreement between it and TXU Electric Delivery are designed to ensure that TXU Electric Delivery receives sufficient services to provide service to its customers, but may not operate as planned. In this case, TXU Electric Delivery will have to identify an alternative means to acquire sufficient asset services because it will no longer have an internal asset services function. TXU Electric Delivery may not be able to readily find replacement services and such services may be more costly than those provided by InfrastruX Energy Services. Should TXU Electric Delivery wish to terminate or materially modify the services agreement, InfrastruX Energy Services and TXU Electric Delivery would also incur transition costs. Failure to obtain sufficient services and costs to acquire replacement services (including transition costs) could adversely affect the financial condition and results of operations of TXU Electric Delivery.

The Commission has recently requested to review the proposed joint venture transaction. TXU Corp. cannot predict the timing and results of the Commission’s review. Such review has delayed the closing of the transaction.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares That May Yet be Purchased Under the Plans or Programs (a)
July 1, 2006 – July 31, 2006	240,796	$	59.93	240,796
August 1, 2006 – August 31, 2006	1,685,500		64.77	1,685,500
September 1, 2006 – September 30, 2006	314,500		66.32	314,500
Total as of September 30, 2006	2,240,796	$	64.47	2,240,796	3,448,989

(a) There have not been any additional share repurchases from October 1, 2006 to October 23, 2006. All of these share repurchases were under a November 2005 authorization by TXU Corp.’s board of directors for the repurchase of up to 34 million shares between November 2005 and year end 2006 (which has been extended to year end 2007). Additionally, in November 2006, the TXU Corp. board of directors authorized the repurchase of an additional 20 million shares of common stock through year end 2007. At November 9, 2006, the maximum number of shares that can yet be repurchased under the two Board authorizations is approximately 23 million shares.

Item 4. Submission of Matters to a Vote of Security Holders

None.

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Item 6. Exhibits

(a) Exhibits filed or furnished as part of Part II are:

Exhibits	Previously Filed With File Number*	As Exhibit
(10)	Material Contracts.
10(a)				Form of Purchase Order by and between TXU Generation Development Company LLC and The Babcox and Wilcox Company, effective as of June 5, 2006 (confidential treatment has been requested for portions of this exhibit).
10(b)				Form of Purchase Order by and between TXU Generation Development Company LLC and General Electric Company, effective as of June 21, 2006 (confidential treatment has been requested for portions of this exhibit).
10(c)				Form of Purchase Order by and between TXU Generation Development Company LLC and Alstom Power Inc., effective as of September 21, 2006 (confidential treatment has been requested for portions of this exhibit).
10(d)				Deed of Trust, Assignment of Rents, Security Agreement, Financing Statement and Fixture Filing, dated as of August 28, 2006, regarding the Big Brown Lien.
(15)	Letter re: Unaudited Interim Financial Information.
15			—	Letter from independent registered public accounting firm as to unaudited interim financial information.
31	Rule 13a – 14(a)/15d – 14 (a) Certifications.
31(a)			—	Certification of C. John Wilder, President and Chief Executive of TXU Corp., pursuant to Rule 13a-14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of David A. Campbell, Executive Vice President and Acting Chief Financial Officer of TXU Corp., pursuant to Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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Exhibits	Previously Filed With File Number*	As Exhibit
(32)	Section 1350 Certifications.
32(a)			—	Certification of C. John Wilder, President and Chief Executive of TXU Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)			—	Certification of David A. Campbell, Executive Vice President and Acting Chief Financial Officer of TXU Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99)	Additional Exhibits.
99			—	Condensed Statements of Consolidated Income – Twelve Months Ended September 30, 2006.

* Incorporated here by reference.

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SIGNATURE

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

TXU CORP.

By

/s/ Stan Szlauderbach

Stan Szlauderbach

Senior Vice President and Controller

Date: November 9, 2006

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