Energy Future 10Q 2007 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2007

— 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 ü 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 ü 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 ü

Common Stock outstanding at August 7, 2007: 461,152,009 shares, without par value.

TABLE OF CONTENTS
	Page
GLOSSARY	ii
Part I. Financial information
Item 1. Financial Statements Condensed Statements of Consolidated Income – Three and Six Months Ended June 30, 2007 and 2006	1

Condensed Statements of Consolidated Comprehensive Income – Three and Six Months Ended June 30, 2007 and 2006	2

Condensed Statements of Consolidated Cash Flows – Six Months Ended June 30, 2007 and 2006	3

Condensed Consolidated Balance Sheets – June 30, 2007 and December 31, 2006	5

Notes to Condensed Consolidated Financial Statements	6

Report of Independent Registered Public Accounting Firm	38
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3. Quantitative and Qualitative Disclosures About Market Risk	86
Item 4. Controls and Procedures	92
Part II. Other Information
Item 1. Legal Proceedings	93
Item 1A. Risk Factors	93
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	95
Item 4. Submission of Matters to a Vote of Security Holders	95
Item 6. Exhibits	96
SIGNATURE	98

TXU Corp.’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the TXU Corp. website at http://www.txucorp.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. TXU Corp. will provide copies of current reports not posted on the website upon request. The information on TXU Corp.’s website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-Q. In addition, in accordance with corporate governance rules of the New York Stock Exchange, TXU Corp. has provided, on the TXU Corp. website, (a) its corporate governance guidelines, (b) its code of conduct for employees, officers and directors, and (c) charters of the committees of the board of directors including the Audit, Nominating and Governance and Organization and Compensation Committees. Printed copies of corporate governance documents which are posted on the TXU Corp. website are also available to any shareholder upon request to the Secretary of TXU Corp., 1601 Bryan Street, Dallas, Texas 75201-3411.

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
2006 Form 10-K	TXU Corp.’s Annual Report on Form 10-K for the year ended December 31, 2006
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
Competitive Electric	Refers to the TXU Corp. business segment, formerly referred to as TXU Energy Holdings, which includes the activities of Texas Competitive Holdings, TXU DevCo and a lease trust holding certain combustion turbines.
EPA	US Environmental Protection Agency
EPC	engineering, procurement and construction
ERCOT	Electric Reliability Council of Texas, the Independent System Operator and the regional coordinator of 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 48	FIN No. 48, “Accounting for Uncertainty in Income Taxes”
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
FSP	FASB Staff Position
GAAP	generally accepted accounting principles
GWh	gigawatt-hours

historical service territory	the territory, largely in north Texas, being served by TXU Corp.’s regulated electric utility subsidiary at the time of entering retail competition on January 1, 2002
IRS	US Internal Revenue Service
kWh	kilowatt-hours
market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. The market heat rate is based on the price offer of the marginal supplier in Texas (generally natural gas plants) in generating electricity and is calculated by dividing the wholesale market price of electricity by the market price of natural gas.
Merger Agreement	Agreement and Plan of Merger, dated February 25, 2007, under which an investor group led by Kohlberg Kravis Roberts & Co. and Texas Pacific Group would acquire TXU Corp.
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
Oncor Electric Delivery	Refers to Oncor Electric Delivery Company, a subsidiary of TXU Corp., and/or its consolidated bankruptcy remote financing subsidiary, Oncor 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., Texas Competitive Holdings or Oncor 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 or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or of any other affiliate.
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 was supplied by competing REPs, adjusted periodically for changes in fuel costs, and (ii) were required to be made available to those customers until January 1, 2007
PURA	Texas Public Utility Regulatory Act
REP	retail electric provider

iii

RRC	Railroad Commission of Texas, which has oversight of lignite mining activity
S&P	Standard & Poor’s Ratings Services, a division of the McGraw Hill Companies Inc. (a credit rating agency)
SEC	US Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards issued by the FASB
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement 125”
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 146	SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities"
SFAS 158	SFAS No. 158, “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
Texas Competitive Holdings	Refers to Texas Competitive Electric Holdings Company LLC (formerly TXU Energy Company LLC), a subsidiary of TXU Corp., and/or its 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., Texas Competitive Holdings or Oncor 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 or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or of any other affiliate.

TXU Corp.	Refers to TXU Corp., a holding company, and/or its subsidiaries, depending on context. This Form 10-Q and other SEC filings of TXU Corp. and its subsidiaries occasionally make references to TXU Corp., Texas Competitive Holdings or Oncor 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 or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or of any other affiliate.
TXU DevCo	Refers to subsidiaries of TXU Corp. that have been established for the purpose of developing new generation facilities. The TXU DevCo subsidiaries are currently not subsidiaries of Texas Competitive Holdings
TXU Energy Retail	Refers to TXU Energy Retail Company LLC, a subsidiary of Texas Competitive Holdings engaged in the retail sale of power to residential and business customers
TXU Europe	TXU Europe Limited, a former subsidiary of TXU Corp.
TXU Fuel	TXU Fuel Company, a former subsidiary of Texas Competitive Holdings
TXU Gas	TXU Gas Company, a former subsidiary of TXU Corp.
TXU Portfolio Management	TXU Portfolio Management Company LP, a subsidiary of Texas Competitive Holdings, currently doing business as Luminant Energy
US	United States of America
US Holdings	TXU US Holdings Company, a subsidiary of TXU Corp.

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

TXU CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(millions of dollars, except per share amounts)

Operating revenues	$	2,022		$	2,667		$	3,691		$	4,971

Costs and expenses:
Fuel, purchased power costs and delivery fees		739			658			1,404			1,179
Operating costs		368			341			714			684
Depreciation and amortization		200			207			403			413
Selling, general and administrative expenses		227			181			447			370
Franchise and revenue-based taxes		89			87			176			174
Other income (Note 6)		(16	)		(42	)		(45	)		(55	)
Other deductions (Note 6)		122			221			891			221
Interest income		(17	)		(11	)		(35	)		(20	)
Interest expense and related charges (Note 15)		221			218			418			431
Total costs and expenses		1,933			1,860			4,373			3,397

Income (loss) from continuing operations before income taxes		89			807			(682	)		1,574

Income tax expense (benefit)		(21	)		310			(294	)		561

Income (loss) from continuing operations		110			497			(388	)		1,013

Income from discontinued operations, net of tax effect		11		─				11			60

Net income (loss)	$	121		$	497		$	(377	)	$	1,073

Average shares of common stock outstanding (millions):
Basic		459			458			458			461
Diluted		464			465			458			470

Per share of common stock - Basic:
Net income (loss) from continuing operations	$	0.24		$	1.08		$	(0.85	)	$	2.20
Income from discontinued operations, net of tax effect		0.02		─				0.03			0.13
Net income (loss)	$	0.26		$	1.08		$	(0.82	)	$	2.33

Per share of common stock – Diluted:
Net income (loss) from continuing operations	$	0.24		$	1.07		$	(0.85	)	$	2.16
Income from discontinued operations, net of tax effect		0.02		─				0.03			0.13
Net income (loss)	$	0.26		$	1.07		$	(0.82	)	$	2.29

Dividends declared	$	0.433		$	0.413		$	0.865		$	0.826

See Notes to Financial Statements.

TXU CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

		Three Months Ended June 30,						Six Months Ended June 30,
		2007			2006			2007			2006
		(millions of dollars)

Components related to continuing operations:

Income (loss) from continuing operations		$	110		$	497		$	(388	)	$	1,013

Other comprehensive income (loss):

Reclassification of pension and other retirement benefit costs
(net of tax expense of $─, ─, $3 and ─) (Note 13)			1		─				5		─

Cash flow hedges:
Net increase (decrease) in fair value of derivatives held at end
of period (net of tax (expense) benefit of $(19), $44, $151 and
	$(16))		35			(83	)		(281	)		30
Derivative value net (gains) losses related to hedged transactions
settled during the period and reported in net income (net of
tax (expense) benefit of $(9), $6, $(49) and $6)			(17	)		12			(91	)		11
Total effect of cash flow hedges			18			(71	)		(372	)		41

Total adjustments to net income (loss) from continuing operations			19			(71	)		(367	)		41

Comprehensive income (loss) from continuing operations			129			426			(755	)		1,054

Comprehensive income from discontinued operations			11		─				11			60

Comprehensive income (loss)		$	140		$	426		$	(744	)	$	1,114

See Notes to Financial Statements.

TXU CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2007			2006
	(millions of dollars)
Cash flows – operating activities:
Net income (loss)	$	(377	)	$	1,073
Income from discontinued operations, net of tax effect		(11	)		(60	)
Income (loss) from continuing operations		(388	)		1,013
Adjustments to reconcile income (loss) from continuing operations to cash provided by
(used in) operating activities:
Depreciation and amortization		433			444
Deferred income tax expense (benefit) – net		(613	)		319
Impairment of natural gas-fueled generation plants	─				198
Inventory write-off related to natural gas-fueled generation plants	─				3
Charges related to suspended development of generation facilities (Note 2)		716		─
Write-off of deferred transaction costs (Note 6)		38		─
Net gains on sale of assets		(27	)		(24	)
Net effect of unrealized mark-to-market valuations – losses (gains)		1,182			(29	)
Gain on contract settlement	─				(26	)
Bad debt expense		25			30
Stock-based incentive compensation expense		15			9
Other, net		19			16
Changes in operating assets and liabilities		(1,455	)		(49	)
Cash provided by (used in) operating activities from continuing operations		(55	)		1,904

Cash flows – financing activities:
Issuances of securities:
Long-term debt		1,800			100
Common stock		1			180
Retirements/repurchases of securities:
Equity-linked debt	─				(179	)
Pollution control revenue bonds		(143	)		(203	)
Other long-term debt		(68	)		(1,143	)
Common stock		(10	)		(809	)
Change in short-term borrowings:
Commercial paper		(1,296	)		905
Bank borrowings		2,155			800
Common stock dividends paid		(397	)		(384	)
Settlements of minimum withholding tax liabilities under stock-based compensation plans		(93	)		(56	)
Debt premium, discount, financing and reacquisition expenses – net		(15	)		(17	)
Cash provided by (used in) financing activities from continuing operations		1,934			(806	)

Cash flows – investing activities:
Capital expenditures		(1,611	)		(825	)
Nuclear fuel		(30	)		(30	)
Proceeds from sale of assets		4		─
Purchase of lease trust	─				(69	)
Reduction of restricted cash related to the redemption of pollution control revenue bonds		143		─
Proceeds from sales of nuclear decommissioning trust fund securities		104			144
Investments in nuclear decommissioning trust fund securities		(111	)		(151	)
Proceeds from pollution control revenue bonds deposited with trustee	─				(99	)
Cost to remove retired property		(16	)		(22	)
Investment in unconsolidated affiliate	─				(15	)
Other		11			5
Cash used in investing activities from continuing operations		(1,506	)		(1,062	)

TXU CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (cont.)

(Unaudited)

	Six Months Ended
	June 30,
	2007		2006
	(millions of dollars)
Discontinued operations:
Cash provided by (used in) operating activities		24		(1	)
Cash used in financing activities	─		─
Cash used in investing activities	─		─
Cash provided by (used in) discontinued operations		24		(1	)

Net change in cash and cash equivalents		397		35
Cash and cash equivalents – beginning balance		25		37
Cash and cash equivalents – ending balance	$	422	$	72

See Notes to Financial Statements.

TXU CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
	2007			2006
ASSETS	(millions of dollars)
Current assets:
Cash and cash equivalents	$	422		$	25
Restricted cash		54			58
Trade accounts receivable – net (Note 7)		1,016			959
Inventories		428			383
Commodity and other derivative contractual assets (Note 12)		299			950
Accumulated deferred income taxes (Note 3)		829			253
Margin deposits related to commodity positions		448			7
Other current assets		189			177
Total current assets		3,685			2,812

Restricted cash		119			258
Investments		742			712
Property, plant and equipment — net		19,387			18,756
Goodwill		542			542
Regulatory assets — net		1,935			2,028
Commodity and other derivative contractual assets (Note 12)		216			345
Other noncurrent assets		362			380

Total assets	$	26,988		$	25,833

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings (Note 8)	$	2,350		$	1,491
Long-term debt due currently (Note 9)		792			485
Trade accounts payable		1,014			1,093
Commodity and other derivative contractual liabilities (Note 12)		429			293
Margin deposits related to commodity positions		35			681
Other current liabilities		993			1,040
Total current liabilities		5,613			5,083

Accumulated deferred income taxes (Note 3)		3,121			4,238
Investment tax credits		353			363
Commodity and other derivative contractual liabilities (Note 12)		876			191
Long-term debt, less amounts due currently (Note 9)		11,917			10,631
Other noncurrent liabilities and deferred credits		4,063			3,187
Total liabilities		25,943			23,693

Commitments and Contingencies (Note 10)

Shareholders’ equity (Note 11):
Common stock without par value: Authorized shares: 1,000,000,000
Outstanding shares: 461,196,630 and 459,244,523		5			5
Additional paid-in capital		1,115			1,104
Retained earnings (deficit)		(117	)		622
Accumulated other comprehensive income		42			409
Total shareholders’ equity		1,045			2,140
Total liabilities and shareholders’ equity	$	26,988		$	25,833

See Notes to Financial Statements.

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 conducting its operations principally through its Texas Competitive Holdings, Oncor Electric Delivery and TXU DevCo subsidiaries and their subsidiaries. Each of these subsidiaries is a separate legal entity with its own assets and liabilities. Texas Competitive Holdings is a holding company whose subsidiaries are engaged in competitive market activities consisting of electricity generation, retail electricity sales to residential and business customers, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. Oncor 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 generation facilities in Texas.

On February 25, 2007, TXU Corp. entered into a Merger Agreement under which an investor group led by Kohlberg Kravis Roberts & Co. and Texas Pacific Group (Sponsors) is expected to acquire TXU Corp. if the relevant conditions to closing are satisfied (Proposed Merger).

TXU Corp. has two reportable segments: the Competitive Electric segment (formerly the TXU Energy Holdings segment), which includes the activities of Texas Competitive Holdings, TXU DevCo and a lease trust holding certain combustion turbines, and the Regulated Delivery segment (formerly the Oncor Electric Delivery segment), which includes the activities of Oncor Electric Delivery, its wholly owned bankruptcy-remote financing subsidiary and certain revenues and costs associated with broadband-over-powerlines equipment installation. (See Note 14 for further information concerning reportable business segments.)

Basis of Presentation— The condensed consolidated financial statements of TXU Corp. have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in its 2006 Form 10-K with the exception of the adoption of FIN 48. All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in the 2006 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.

Prior period commodity contract assets and liabilities and cash flow hedge and other derivative assets and liabilities have been combined to conform with the current period presentation (see Note 12).

Discontinued Businesses─ Income from discontinued operations in the six months ended June 30, 2007 consisted primarily of insurance settlements related to TXU Europe litigation. Income from discontinued operations in the six months ended June 30, 2006 consisted primarily of a reversal of a TXU Gas income tax reserve due to a favorable resolution of an IRS audit matter. The TXU Gas business was disposed of in October 2004.

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 valuations. 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 year.

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 employee compensation and certain debt arrangements. See Note 5 for a reconciliation of basic earnings per share to diluted earnings per share.

Changes in Accounting Standards — Effective January 1, 2007, TXU Corp. adopted FIN 48 as required. FIN 48 provides clarification of SFAS 109 with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. See Note 3 for the impacts of adopting FIN 48 and required disclosures.

In April 2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39”. This FSP provides additional guidance regarding the offsetting in the balance sheet of cash collateral and contractual fair value amounts and related disclosures. This FSP is effective for fiscal years beginning after November 15, 2007. TXU Corp. is evaluating the impact of this standard on its balance sheet.

2. CHARGES RELATED TO SUSPENDED DEVELOPMENT OF COAL-FUELEDGENERATION FACILITIES

In the first quarter of 2007, TXU Corp. recorded a charge totaling $713 million ($463 million after-tax) in connection with the February 2007 suspension by TXU DevCo of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation of the recoverability of recorded assets associated with the development program. The charge included $673 million for the impairment of construction work-in-process asset balances (primarily pre-construction development costs), $11 million for costs arising from terminations of equipment orders and $29 million for the write-off of deferred financing costs. In determining the charge to be recorded, TXU Corp. applied accounting rules for impairment of long-lived assets under SFAS 144 and for exit activities under SFAS 146.

The construction work-in-process asset balances totaled $871 million at March 31, 2007 prior to the writedown and included progress payments made and accruals for amounts due to equipment suppliers, based on percentage of completion estimates, engineering and design services costs, site preparation expenditures, internal salary and related overhead costs for personnel engaged directly in construction management activities and capitalized interest. The construction work-in-process balance subsequent to the writedown totaled $198 million at March 31, 2007 and consisted of $159 million in estimated recovery amounts, using a probability-weighted methodology, from equipment salvage and potential resale activities, and $39 million in equipment projects at existing generation plant sites related to the development program that are expected to have future value. The charge recorded was based on management's judgments and estimates. The ultimate loss to be realized related to the construction work-in-process assets may differ materially from the estimate recorded in the first quarter of 2007 as amounts due to suppliers for actual work completed are resolved and salvage and resale actions are finalized.

In the second quarter of 2007, TXU Corp. recorded an additional charge totaling $82 million ($54 million after-tax), which consisted almost entirely of the previously disclosed $79 million pretax charge arising from the negotiated termination of certain equipment orders in April 2007. With this agreement, TXU DevCo has now terminated essentially all of the equipment orders, with the exception of certain in-process boilers that may be resold, but remains subject to potential additional termination liabilities as discussed below.

These charges have been classified in other deductions and are reported in the results of the Competitive Electric segment.

In addition to the termination costs recognized to date, TXU DevCo is exposed to potential liabilities of up to approximately $150 million for termination and suspension costs under the equipment order and construction agreements. Because the amounts ultimately payable to suppliers cannot be reasonably estimated at this time (and may be subject to dispute), no accruals have been established for these contingent liabilities. Additional charges for termination liabilities are expected to be recorded as uncertainties regarding suppliers’ costs incurred as a result of the terminations are resolved.

The construction work-in-process balances increased $46 million in the second quarter of 2007 to $244 million. The increase primarily represents additional previously anticipated fabrication costs for the boilers referred to above, the incurrence of which does not result in an increase in estimated impairment.

3. ADOPTION OF NEW INCOME TAX ACCOUNTING RULES (FIN 48)

FIN 48 requires that each tax position be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable. TXU Corp. has completed its review and assessment of uncertain tax positions and in the quarter ended March 31, 2007 recorded a net benefit to retained earnings and a decrease to noncurrent liabilities of $33 million in accordance with the new accounting rule.

TXU Corp. and its subsidiaries file income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of income tax returns filed by TXU Corp. and any of its subsidiaries for the years ending prior to January 1, 1997, with few exceptions, are complete. Texas franchise tax returns for the years 2002 to 2006 have not been examined.

As expected, the IRS has completed examining TXU Corp.’s US income tax returns for the years 1997 through 2002, and proposed adjustments were received in July 2007. TXU Corp. plans to appeal the proposed adjustments in the third quarter of 2007. The proposed adjustments received from the IRS with respect to the 1997-2002 income tax returns do not materially affect TXU Corp.’s assessment of uncertain tax positions as reflected in the amounts recorded upon adoption of FIN 48.

The total amount of benefits taken on income tax returns that do not qualify for financial statement recognition under FIN 48 total $1.7 billion as of June 30, 2007, the substantial majority of which represents amounts that have been accounted for as noncurrent liabilities instead of deferred income tax liabilities; of this amount, $28 million would increase earnings if recognized (net of an estimated $12 million decrease related to discontinued operations), and $54 million would be recorded as an adjustment to additional paid-in capital if recognized. The balance sheet at June 30, 2007 reflects a reclassification of $893 million from accumulated deferred income tax liabilities to other noncurrent liabilities recorded in the first quarter of 2007.

TXU Corp. classifies interest and penalties related to unrecognized tax benefits as income tax expense. As of June 30, 2007, noncurrent liabilities included a total of $79 million in accrued interest. The amount of interest included in income tax expense for the three and six months ended June 30, 2007 totaled $15 million and $29 million after-tax, respectively.

TXU Corp. does not expect that the total amount of unrecognized tax benefits for the positions assessed as of the date of the adoption will significantly increase or decrease within the next 12 months.

4. TEXAS MARGIN TAX

In May 2006, the Texas legislature enacted a new law that reformed the Texas franchise tax system and replaced it with a new tax system, referred to as the Texas margin tax. The Texas margin tax has been determined to be an income tax for accounting purposes. 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 deferred tax expense of $41 million in the second quarter of 2006.

In June 2007, an amendment to this law was enacted that included clarifications and technical changes to the provisions of the tax calculation. In the second quarter of 2007, TXU Corp. recorded a deferred tax benefit of $51 million, essentially all of which related to changes in the rate at which a tax credit is calculated as specified in the new law. This estimated benefit is based on the Texas margin tax law in its current form and the current guidance issued by the Texas Comptroller of Public Accounts.

The effective date of the Texas margin tax for TXU Corp. is January 1, 2008. The computation of tax liability will be based on 2007 revenues as reduced by certain deductions and is being accrued in the current year.

Of the total 2007 deferred tax benefit, $30 million was recognized in the Competitive Electric segment results and $21 million was recognized in the Corporate and Other nonsegment results. Of the total 2006 deferred tax charge, $42 million was recognized as a deferred tax charge in the Competitive Electric segment results and $1 million was recognized as a deferred tax benefit in the Corporate and Other nonsegment results.

5. 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 and certain debt arrangements.

	For the Three Months Ended June 30, 2007						For the Three Months Ended June 30, 2006
					Per						Per
	Income				Share						Share
	(Loss)		Shares		Amount		Income		Shares		Amount


Income (loss) from continuing operations
-Basic	$	110		458.8	$	.24	$	497		458.0	$	1.08

Dilutive securities/other adjustments:

Convertible senior notes		―		1.5				―		1.5

Equity-linked debt securities		―		―				―		1.0

Stock-based incentive compensation plan		―		3.4				―		5.0

Income (loss) from continuing operations
-Diluted	$	110		463.7	$	.24	$	497		465.5	$	1.07

	For the Six Months Ended June 30, 2007									For the Six Months Ended June 30, 2006
							Per							Per
	Income						Share							Share
	(Loss)			Shares			Amount			Income		Shares		Amount

Income (loss) from continuing operations
-Basic	$	(388	)		458.2		$	(.85	)	$	1,013		461.0	$	2.20

Dilutive securities/other adjustments:

Convertible senior notes		―			1.5						1		1.5

Equity-linked debt securities		―			―						―		1.6

Stock-based incentive compensation plan		―			4.4						―		5.6

Income (loss) from continuing operations
-Diluted	$	(388	)		458.2	(a)	$ (.85) (a)			$	1,014		469.7	$	2.16
_________________

(a) Diluted results per share equal basic results per share because of the loss position and antidilution accounting rules.

6. OTHER INCOME AND DEDUCTIONS

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Other income:
Gain on contract settlement (a)	$ ─		$	26	$ ─		$	26
Amortization of gain on sale of TXU Fuel		11		11		23		23
Net gain on sale of other properties	─			1		4		1
Reduction of insurance reserves unrelated to ongoing operations		2	─			7	─
Settlement penalty for coal tonnage delivery deficiency	─		─			3	─
Royalty income from lignite and natural gas leases		2	─			5	─
Other		1		4		3		5
Total other income	$	16	$	42	$	45	$	55
Other deductions:
Charges related to suspended development of generation facilities (Note 2)	$	82	$ ─		$	795	$ ─
Writeoff of deferred transaction costs (b)	─		─			30	─
Transaction costs related to Proposed Merger		6	─			20	─
Expenses related to InfrastruX Energy Services joint venture (c)		11	─			12	─
Charge for impairment of natural gas-fueled generation plants	─			198	─			198
Inventory write-off related to natural gas-fueled generation plants	─			3	─			3
Credit related to coal contract counterparty claim (d)	─		─		─			(12	)
Costs related to 2006 cities rate settlement		7	─			13	─
Charge for settlement of retail matter with the Commission		5	─			5	─
Pension and other postretirement benefit costs related to discontinued
businesses		6		5		9		10
Equity losses ─ unconsolidated affiliates	─			7		1		7
Other		5		8		6		15
Total other deductions	$	122	$	221	$	891	$	221

______________________

	(a)	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 results.)
	(b)	Represents previously deferred costs, consisting primarily of professional fees for tax, legal and other advisory services, in connection with certain previously anticipated strategic transactions (including expected financings) that are no longer expected to be consummated as a result of the Merger Agreement. (Reported in Corporate and Other nonsegment results.)
	(c)	Consists of previously deferred costs, consisting primarily of professional fees that were written-off due to suspension of the agreement. Of these amounts, $8 million was reported in the Corporate and Other nonsegment results and the balance was reported in the Regulated Delivery segment results.
	(d)	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 Competitive Electric segment results.)

7. 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.

The maximum amount currently available under the program is $700 million, and the program funding was $527 million as of June 30, 2007. 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 Texas Competitive Holdings’ fixed charge coverage ratio is less than 2.5 times; 50% if Texas Competitive Holdings’ coverage ratio is less than 3.25 times, but at least 2.5 times; and zero % if Texas Competitive Holdings’ coverage ratio is 3.25 times or more. The originators’ customer deposits, which totaled $119 million, did not affect funding availability at that date as Texas Competitive Holdings’ 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, totaled $350 million and $211 million at June 30, 2007 and December 31, 2006, 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 $20 million and $18 million for the six month periods ending June 30, 2007 and 2006, respectively, and averaged 6.4% and 5.4% (on an annualized basis) of the funding under the program for the first six months of 2007 and 2006, respectively. The servicing fee, which totaled approximately $2 million for the first six months of both 2007 and 2006, 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 June 30, 2007 consolidated balance sheet includes $877 million face amount of trade accounts receivable of Texas Competitive Holdings and Oncor Electric Delivery sold to TXU Receivables Company, such amount having been reduced by $527 million of undivided interests sold by TXU Receivables Company. Funding under the program decreased $100 million for the six month period ending June 30, 2007 and increased $29 million for the six month period ending June 30, 2006. 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.

Activities of TXU Receivables Company were as follows:

	Six Months Ended June 30,
	2007			2006

Cash collections on accounts receivable	$	3,964		$	3,705
Face amount of new receivables purchased		(4,003	)		(3,763	)
Discount from face amount of purchased receivables		22			20
Program fees paid		(20	)		(18	)
Servicing fees paid		(2	)		(2	)
Increase in subordinated notes payable		139			29
Operating cash flows used by (provided to) TXU Corp. under the program	$	100		$	(29	)

Upon termination of the program, cash flows would be delayed as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities 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:

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

the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds and the financial institutions do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables, not separately to the receivables of each originator.

Trade Accounts Receivable -

	June 30,			December 31,
	2007			2006
Gross trade accounts receivable	$	1,557		$	1,599
Undivided interests in accounts receivable sold by TXU Receivables Company		(527	)		(627	)
Allowance for uncollectible accounts related to undivided interests in receivables retained		(14	)		(13	)
Trade accounts receivable ― reported in balance sheet	$	1,016		$	959

Gross trade accounts receivable at June 30, 2007 and December 31, 2006 included unbilled revenues of $528 million and $466 million, respectively.

Allowance for Uncollectible Accounts Receivable -

	2007			2006

Allowance for uncollectible accounts receivable as of January 1	$	13		$	36
Increase for bad debt expense		25			30
Decrease for account write-offs		(33	)		(41	)
Changes related to receivables sold		9			13
Other (a)	─				(15	)
Allowance for uncollectible accounts receivable as of June 30	$	14		$	23

(a)

Represents an allowance established in 2005 for a coal contract dispute that was reversed upon settlement in 2006. See Note 6.

Allowances related to undivided interests in receivables sold are reported in current liabilities and totaled $17 million and $26 million at June 30, 2007 and December 31, 2006, respectively.

8. SHORT-TERM FINANCING

Short-term Borrowings - At June 30, 2007 and December 31, 2006, the outstanding short-term borrowings of TXU Corp. and its subsidiaries consisted of the following:

	At June 30, 2007					At December 31, 2006
	Outstanding Amount		Interest Rate (a)			Outstanding Amount		Interest Rate (a)
Bank borrowings	$	2,350		6.19	%	$	195		5.97	%
Commercial paper		―		―			1,296		5.53	%
Total	$	2,350				$	1,491

(a)

Weighted average interest rate at the end of the period.

Under the commercial paper programs, Texas Competitive Holdings and Oncor Electric Delivery may issue up to $2.4 billion and $1.0 billion of commercial paper, respectively. At June 30, 2007, Texas Competitive Holdings and Oncor Electric Delivery had no commercial paper outstanding. These programs are effectively supported by existing credit facilities although there is no contractual obligation under the programs to maintain equivalent availability under existing credit facilities. During 2007, the commercial paper borrowings have been largely refinanced through borrowings against existing credit facilities.

Credit Facilities— At June 30, 2007, subsidiaries of TXU Corp. had access to credit facilities with the following terms:

		At June 30, 2007
Authorized	Maturity	Facility		Letters of		Cash
Borrowers	Date	Limit		Credit		Borrowings		Availability
Texas Competitive Holdings	February 2008	$	1,500	$	―	$	―	$	1,500
Texas Competitive Holdings, Oncor Electric Delivery	June 2008		1,400		512		765		123
Texas Competitive Holdings, Oncor Electric Delivery	August 2008		1,000		―		495		505
Texas Competitive Holdings, Oncor Electric Delivery	March 2010		1,600		248		815		537
Texas Competitive Holdings, Oncor Electric Delivery	June 2010		500		5		230		265
Texas Competitive Holdings	December 2009		500		455		45		―
Total		$	6,500	$	1,220	$	2,350	$	2,930

The maximum amount Texas Competitive Holdings and Oncor 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. Availability under these facilities as of June 30, 2007 declined $2.4 billion from December 31, 2006.

On March 1, 2007, a $1.5 billion Texas Competitive Holdings facility maturing in May 2007 was terminated and replaced with a new 364-day facility with terms comparable to the existing facilities. The new credit facility may only be drawn upon if the $1.0 billion credit facility maturing in August 2008 is fully drawn. The facility matures in February 2008 but will terminate earlier on any date Texas Competitive Holdings issues any debt (excluding pollution control revenue bonds and commercial paper) or preferred equity securities or enters into any credit facilities.

All letters of credit under the credit facilities as of June 30, 2007 are the obligations of Texas Competitive Holdings. At June 30, 2007, Texas Competitive Holdings and Oncor Electric Delivery had $2.195 billion and $155 million in outstanding cash borrowings, respectively.

Pursuant to Commission rules, availability under the credit facilities is further reduced by $125 million to provide liquidity to permit TXU Energy Retail to return retail customer deposits, if necessary.

9. LONG-TERM DEBT

Long-term debt - At June 30, 2007 and December 31, 2006, the long-term debt of TXU Corp. consisted of the following:

	June 30,		December 31,
	2007		2006
Texas Competitive Holdings
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39	$	39
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
3.830% Floating Series 2001A due October 1, 2030 (b)		71		71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)		217		217
3.780% Floating Series 2001D due May 1, 2033 (b)		268		268
5.380% Floating Taxable Series 2001I due December 1, 2036 (b)		62		62
3.830% Floating Series 2002A due May 1, 2037 (b)		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		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
3.850% Floating Series 2006A due November 1, 2041 (interest rate in effect at March 31, 2007) (c)		―		47
3.850% Floating Series 2006B due November 1, 2041, (interest rate in effect at March 31, 2007) (c)		―		46

Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028		14		14
3.850% Floating Series 2006 due November 1, 2041, (interest rate in effect at March 31, 2007) (c)		―		50

Other:
6.125% Fixed Senior Notes due March 15, 2008 (d)		250		250
7.000% Fixed Senior Notes due March 15, 2013		1,000		1,000
5.860% Floating Senior Notes due September 16, 2008 (e)		1,000		―
Capital lease obligations		92		98
Fair value adjustments related to interest rate swaps		11		10
Total Texas Competitive Holdings	$	3,888	$	3,036

	June 30,			December 31,
	2007			2006
Oncor 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		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
5.000% Fixed Debentures due September 1, 2007 (d)		200			200
7.000% Fixed Debentures due September 1, 2022		800			800
5.735% Floating Senior Notes due September 16, 2008 (e)		800			―
Unamortized discount		(16	)		(16	)
Total Oncor Electric Delivery		3,834			3,034

Oncor Electric Delivery Transition Bond Company LLC (f)
2.260% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2007		―			8
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		109			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		131			158
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 Oncor Electric Delivery Transition Bond Company LLC		1,026			1,074
Total Oncor Electric Delivery Consolidated		4,860			4,108

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		78			85
9.580% Fixed Notes due in semiannual installments through December 4, 2019		62			62
8.254% Fixed Notes due in quarterly installments through December 31, 2021		58			59
6.156% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (g)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized premium		4			5
Total US Holdings		221			230

TXU Corp.
6.375% Fixed Senior Notes Series C due January 1, 2008 (d)		200			200
4.800% Fixed Senior Notes Series O due November 15, 2009		1,000			1,000
5.550% Fixed Senior Notes Series P due November 15, 2014		1,000			1,000
6.500% Fixed Senior Notes Series Q due November 15, 2024		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 (h)		93			99
6.856% Floating Convertible Senior Notes due July 15, 2033 (g)		25			25
Fair value adjustments related to interest rate swaps		(70	)		(73	)
Unamortized discount		(8	)		(9	)
Total TXU Corp.		3,740			3,742

Total TXU Corp. consolidated		12,709			11,116
Less amount due currently		(792	)		(485	)
Total long-term debt	$	11,917		$	10,631

____________________

(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)	Interest rates in effect at June 30, 2007. 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.
(c)	These series were redeemed on May 8, 2007 as a result of the suspension of development of eight coal-fueled generation facilities.
(d)	Interest rates swapped to variable on entire principal amount at June 30, 2007.
(e)	Interest rates in effect at June 30, 2007. These series are subject to mandatory redemption upon a change in control of TXU Corp., including the Proposed Merger and are subject to optional redemption on or after September 16, 2007.
(f)	These bonds are nonrecourse to Oncor Electric Delivery and were issued to securitize a regulatory asset.
(g)	Interest rates in effect at June 30, 2007.
(h)	TXU Corp. and Texas Competitive Holdings replaced their guarantees of this financing with a $144 million letter of credit in June 2007.

Debt-related Activity in 2007 — In May 2007, Texas Competitive Holdings redeemed at par the Sabine River Authority of Texas Series 2006A and 2006B pollution control revenue bonds with aggregate principal amounts of $47 million and $46 million, respectively, and the Trinity River Authority of Texas Series 2006 pollution control revenue bonds with an aggregate principal amount of $50 million. All three bond series were issued in conjunction with the development of eight coal-fueled generation plants, which has been suspended. Restricted cash retained upon issuance of the bonds was used to fund substantially all of the redemption amount.

In March 2007, Texas Competitive Holdings and Oncor Electric Delivery issued floating rate senior notes with an aggregate principal amount of $1.0 billion and $800 million, respectively. The floating rate is based on LIBOR plus 50 basis points for Texas Competitive Holdings (subject to an increase of 25 basis points in the event of a downgrade in Texas Competitive Holdings’ credit rating) and 37.5 basis points for Oncor Electric Delivery (subject to an increase of up to 50 basis points in the event of a downgrade in Oncor Electric Delivery's credit rating). The notes mature in September 2008, but are subject to mandatory redemption upon a change in control of TXU Corp., including consummation of the Proposed Merger.

Fair Value Hedges — TXU Corp. uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At June 30, 2007, $650 million of fixed rate debt had been effectively converted to variable rates through interest rate swap transactions, expiring through 2008. These swaps qualified for and were designated as fair value hedges in accordance with SFAS 133 (under the short-cut method as the conditions for assuming no ineffectiveness are met). Interest rate swaps related to $1.85 billion principal amount of debt were dedesignated as fair value hedges in January 2007. Offsetting swap positions were entered into and both the original swaps and offsetting positions are subsequently being marked-to-market in net income.

Long-term debt fair value adjustments —

	Six Months Ended June 30, 2007
Long-term debt fair value adjustments related to interest rate swaps at beginning of period ― net reduction in debt carrying value	$	(63	)
Fair value adjustments during the period		1
Recognition of net gains on settled fair value hedges (a)		(1	)
Recognition of net losses on dedesignated fair value hedges (b)		4
Long-term debt fair value adjustments at end of period ― net reduction in debt carrying value (net out-of-the-money value of swaps)	$	(59	)

______________

(a)	Net value of settled in-the-money fixed-to-variable swaps recognized in net income when the hedged transactions are recognized. Amount is pretax.
(b)	Net value of dedesignated out-of-the money fixed-to-variable swaps recognized in net income when the hedged transactions are recognized. Amount is pretax.

Any changes in unsettled swap fair values of active positions reported as fair value adjustments to debt amounts are offset by changes in derivative assets and liabilities.

10. COMMITMENTS AND CONTINGENCIES

Generation Development

Subsidiaries of TXU Corp. have executed EPC agreements for the development of three lignite/coal-fueled generation units in Texas. Such subsidiaries or the EPC contractors have placed orders for critical long lead-time equipment, including boilers, turbine generators and air quality control systems for the two units at Oak Grove and one unit at Sandow, and construction of the three units has commenced.

The existing air permit for the Sandow facility was issued to Alcoa Inc. pursuant to a consent decree issued by a federal court and is expected to be transferred to a TXU Corp. subsidiary pursuant to a development agreement that includes a long-term power supply arrangement with Alcoa Inc. The consent decree contains certain provisions that create risk to the project; however, TXU Corp. has reached a negotiated settlement with the US Department of Justice and the EPA that would resolve the consent decree issues, including one related to the deadline for commercial operation of the facility. In February 2007, the federal court approved this settlement, but it is subject to pending appeal. There can be no assurance that the appeals court would not overturn the ruling, which would result in an adverse impact on the project.

A TXU Corp. subsidiary has received the air permit for the Oak Grove units, which was approved by the TCEQ in June 2007. The Oak Grove air permit is the subject of motions for rehearing at the TCEQ and collateral litigation in state and federal court and is expected to be appealed. While TXU Corp. does not expect the appeal to be successful, and it believes the collateral litigation is without merit and intends to vigorously defend such litigation and appeals, there can be no assurance that the appeal or collateral litigation will not have an adverse impact on the project.

Capital expenditures under the construction-related agreements for the three generation units totaled approximately $1.0 billion as of June 30, 2007. If the agreements had been canceled as of that date, subsidiaries of TXU Corp. would have incurred an estimated termination obligation of up to approximately $340 million. This estimated gross cancellation exposure of approximately $1.4 billion at June 30, 2007 excludes any potential recovery values for assets acquired to date and for assets already owned prior to executing such agreements that are intended to be utilized for these projects.

Litigation

Two putative class and derivative lawsuits and one derivative lawsuit were filed in the United States District Court, Northern District of Texas, Dallas Division in March 2007 against the directors of TXU Corp., TXU Corp., as a nominal defendant, and the Sponsors. On April 27, 2007, the Plaintiffs filed Amended Complaints asserting only derivative claims against the same defendants. The lawsuits seek to challenge and enjoin the Merger Agreement. The cases allege that the directors abused their ability to control and influence TXU Corp., committed gross mismanagement and violated various fiduciary duties by approving the Merger Agreement and the Sponsors aided and abetted that alleged conduct. The Plaintiffs contend that the directors violated fiduciary duties owed to shareholders by failing to maximize the value of TXU Corp. and by breaching duties of loyalty and due care by not taking adequate measures to ensure that the interests of shareholders were properly protected. The Merger Agreement allowed TXU Corp. to solicit other proposals from third parties until April 16, 2007 and the transaction is subject to the approval of TXU Corp.’s shareholders. Accordingly, TXU Corp. and its directors filed Motions to Dismiss based on the Plaintiffs failure to comply with the provisions of the Texas Business Organizations Code applicable to filing and pursuing derivative proceedings. The Motions are pending before the Court.

In February and March 2007, three derivative lawsuits were filed in Dallas County state district courts arising out of the Merger Agreement. The suits, filed by putative shareholders, allege that TXU Corp.'s directors, named as defendants, breached fiduciary duties owed TXU Corp. by approving the Merger Agreement. The petitions, now consolidated into one action in the 44^th District Court, Dallas County, Texas, include claims that the defendants failed to ensure that the transaction was in the best interest of TXU Corp.; that the directors participated in a transaction where their loyalties were divided and where they were to receive a personal financial benefit; that such alleged conduct constituted a breach of their duties of care, loyalty, good faith, candor and independence owed to TXU Corp.; and that the Sponsors aided and abetted the alleged breaches of fiduciary duties by the directors. TXU Corp. believes that the Plaintiffs failed to comply with provisions of the Texas Business Organizations Code applicable to filing and pursuing derivative proceedings and thus have filed a Motion to Dismiss that is pending before the Court. Additionally, TXU Corp. has filed a Written Statement with the Court advising that, pursuant to the Texas Business Organizations Code, a Derivative Demand Committee of independent and disinterested members of TXU Corp.'s board of directors has been formed and is engaged in the active review, in good faith, of the allegations in the consolidated derivative lawsuits. Consequently, TXU Corp. has requested that the Court enforce the automatic and mandatory stay of the proceedings as provided in the Texas Business Organizations Code (TBOC) until the Derivative Demand Committee has completed its review. On May 16, 2007, the parties agreed to stay the consolidated derivative proceeding pending the Derivative Demand Committee’s review of Plaintiffs’ claims in that proceeding. On May 18, 2007, the Court entered an order staying the action in accordance with Section 21.555 of the TBOC. On July 18, 2007, TXU Corp. filed a Written Statement pursuant to TBOC Section 21.555(c) and an Application for Additional Stay informing the District Court that the Derivative Demand Committee was continuing its active review, in good faith, of the allegations set forth in the derivative lawsuits and accordingly requested an extension of the order staying the action through August 31, 2007. The Court has not yet ruled upon the Written Statement and Application.

In February and March 2007 eight lawsuits were filed in state district court in Dallas County, Texas by putative shareholders against the directors of TXU Corp., TXU Corp., the Sponsors, and certain financial entities, asserting claims on behalf of owners of shares of TXU common stock as well as seeking to certify a class action on behalf of allegedly similarly situated shareholders. The lawsuits, which have been consolidated into one action in the 44^th District Court, Dallas County, Texas, contend that the directors of TXU Corp. violated various fiduciary duties owed plaintiffs and other shareholders in connection with the execution of the Merger Agreement and that the Sponsors and certain financial entities aided and abetted the alleged breaches of fiduciary duties by the directors. Plaintiffs seek to enjoin defendants from consummating the Merger Agreement until such time as a procedure or process is adopted to obtain the highest possible price for shareholders, as well as a request that the Court direct the officers and directors of TXU Corp. to exercise their fiduciary duties in order to obtain a transaction in the best interest of TXU Corp. shareholders. The consolidated suit includes claims that the directors failed to take steps to properly value or maximize the value of TXU Corp. and breached their duties of loyalty, good faith, candor and independence owed to TXU Corp. shareholders. The Merger Agreement allowed TXU Corp. to solicit other proposals from third parties until April 16, 2007 and is subject to the approval of TXU Corp.’s shareholders. The consolidated suit purports to assert claims by shareholders directly against the directors. TXU Corp. believes that Texas law does not recognize such a cause of action. Consequently, TXU Corp. and its directors have filed a Motion to Dismiss. On May 25, 2007, the Court granted the Motion and dismissed the consolidated putative class action suit with prejudice. On May 31, 2007, Plaintiffs moved for reconsideration of the May 25 Order dismissing the action. The motion is pending before the Court. TXU Corp. believes the claims made in this litigation are without merit and, therefore, intends to vigorously defend this litigation.

On July 19, 2007, a putative class action lawsuit was filed in the United States District Court, Northern District of Texas, Dallas Division by a putative shareholder against TXU Corp. and its directors asserting a claim under Section 14(a) of the Securities Exchange Act of 1934 and the rules and regulations thereunder, asserting that the preliminary proxy statement of TXU Corp. filed June 14, 2007 fails to adequately describe the relevant facts and circumstances regarding the Proposed Merger as well as seeking to certify the litigation as a class action on behalf of allegedly similarly situated shareholders. TXU Corp. has not yet responded to this litigation and, as described below, on July 23, 2007, the Sponsors, joined by TXU Corp. for the limited purpose described below, have entered into a memorandum of understanding with plaintiffs that would result in the dismissal of this litigation if the settlement is approved by the courts. In the event that TXU Corp. is required to respond to this litigation, TXU Corp. will file a Motion to Dismiss based on the fact that this proxy statement clearly and accurately describes the information regarding the Proposed Merger and the information necessary for a shareholder to evaluate the proposal to approve the Merger Agreement. TXU Corp. believes the claims made in this litigation are without merit and, therefore, if necessary, TXU Corp. intends to vigorously defend this litigation.

On July 23, 2007, the Sponsors, joined by TXU Corp. for the limited purpose described below, executed a memorandum of understanding with the plaintiffs in certain of the lawsuits described above pursuant to which, if approved by the court in which the litigation is pending, to the extent required, all of the litigation related to the Proposed Merger will be dismissed with prejudice. Neither TXU Corp. nor any of its directors agreed to fund any payment or pay any other consideration under the settlement. TXU Corp. did agree to make certain revisions to the final proxy statement as part of the agreement between the Sponsors and the plaintiffs to settle the litigation and agreed that under certain circumstances the termination fee payable by TXU Corp. under the Merger Agreement would be $925 million rather than $1 billion. The settlement of the litigation, subject to court approval, will result in a dismissal of all claims against TXU Corp. and its officers and directors related to the Proposed Merger.

On December 1, 2006, a lawsuit was filed in the United States District Court for the Western District of Texas against TXU Generation Company LP, Oak Grove Management Company, LLC and TXU Corp. The complaint sought declaratory and injunctive relief, as well as the assessment of civil penalties, with respect to the permit application for the construction and operation of the Oak Grove Steam Electric Station in Robertson County, Texas. The plaintiffs allege violations of the Federal Clean Air Act, Texas Health and Safety Code and Texas Administrative Code and sought to temporarily and permanently enjoin the construction and operation of the Oak Grove generation plant. The complaint also asserted that the permit application was deficient in failing to comply with various modeling and analyses requirements relative to the impact of emissions from the Oak Grove plant. Plaintiffs further requested that the District Court enter an order requiring the defendants to take other appropriate actions to remedy, mitigate and offset alleged harm to the public health and environment. TXU Corp. believes the Oak Grove air permit granted by the TCEQ on June 13, 2007 is protective of the environment and that the application for and the processing of the air permit by Oak Grove Management Company LLC with the TCEQ has been in accordance with applicable law. TXU Corp. and the other defendants filed a Motion to Dismiss the litigation, which was granted by the District Court on May 21, 2007. The Plaintiffs have appealed the District Court’s dismissal of the case to the Fifth Circuit Court of Appeals. TXU Corp. believes the District Court properly granted the Motion to Dismiss and 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. maintains that the claims made in the complaint are without merit. Accordingly, TXU Corp. intends to vigorously defend the appeal and this litigation in the event the Fifth Circuit reverses the District Court.

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 plaintiffs’ 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 plaintiffs filed a timely notice of appeal, and the matter is now before the Fifth Circuit Court of Appeals with briefing of the appeal completed. 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.

In November 2002, February 2003 and March 2003, three lawsuits were filed in the US District Court for the Northern District of Texas, Dallas Division, asserting claims under Employee Retirement Income Security Act (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 TXU Corp. 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. While on appeal, the matter was referred to the Fifth Circuit’s alternative dispute resolution program and subsequently to mediation. While mediation was unsuccessful, further discussions led to an agreement in principle to settle this litigation on December 24, 2006 for $7.25 million, before attorneys' fees, to be paid by TXU Corp. to the Thrift Plan pursuant to a Court approved allocation. A Memorandum of Understanding confirming the agreement in principle was signed on January 24, 2007, and the settlement is in the process of being confirmed with final settlement documents after which the settlement will be submitted to the District Court for approval. TXU Corp. believes the claims are without merit and, in the event the settlement is not approved, 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 District Court rejects the settlement, 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.

In October, November and December 2002 and January 2003, a number of lawsuits were filed against TXU Corp. and certain of its officers and directors. These lawsuits were consolidated and lead plaintiffs were appointed by the District 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 settlement appealed the orders approving the settlement to the Fifth Circuit Court of Appeals. The appeal was dismissed on June 11, 2007 and as a result, the District Court’s Judgment is final and not subject to further appeal.

Regulatory Investigations

In March 2007, the Commission issued a Notice of Violation (NOV) stating that the Commission Staff is recommending an enforcement action, including the assessment of administrative penalties, against TXU Corp. and certain affiliates for alleged market power abuse by its power generation affiliates and TXU Portfolio Management in ERCOT-administered balancing energy auctions during certain periods of the summer of 2005. The NOV is premised upon the Commission Staff's allegation that TXU Portfolio Management's bidding behavior was not competitive and increased market participants' costs of balancing energy by approximately $70 million, including approximately $20 million in incremental revenues to TXU Corp. The Commission Staff has recommended that TXU Portfolio Management and its affiliates be required to pay administrative penalties in the amount of $140 million and pay the $70 million in incremental costs purportedly incurred by market participants. A hearing requested by TXU Portfolio Management to contest the alleged occurrence of a violation and the amount of the penalty in the NOV has been scheduled to start in April 2008. TXU Corp. believes TXU Portfolio Management's conduct during the period in question was consistent with the Commission's rules and policies, and no market power abuse was committed. TXU Corp. is vigorously contesting the NOV. TXU Corp. is unable to predict the outcome of this matter.

TXU Corp. and TXU Portfolio Management have taken actions to reduce the risk of future similar allegations related to the balancing energy segment of the ERCOT wholesale market, including working with the Commission Staff and the Commission's independent market monitor to develop a voluntary mitigation plan for approval by the Commission. TXU Portfolio Management has submitted a voluntary mitigation plan that was approved by the Commission in July 2007.

As previously disclosed, the Commission Staff had been investigating TXU Energy Retail with respect to the renewal process for certain small and medium business customers on term service plans. The investigation did not involve residential customers. In June 2007, TXU Energy Retail reached a settlement agreement with the Staff of the Commission that was approved by the Commission in July 2007. While TXU Energy Retail expressly denies any violations of rules, it has agreed to pay the Commission a $5 million settlement as a compromise in this dispute.

Other Proceedings

In addition to the above, TXU Corp. and its subsidiaries are 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.

Guarantees

Overview — 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 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, which expires on October 1, 2007, is $192.5 million. In addition, until October 1, 2014, 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 $1.9 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 any of these indemnity obligations, 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 $108 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 June 30, 2007, the aggregate maximum amount of residual values guaranteed was approximately $205 million with an estimated residual recovery of approximately $202 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the lease portfolio is approximately four 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 June 30, 2007, the balance of the indebtedness was $120 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities.

Letters of Credit

At June 30, 2007, Texas Competitive Holdings had outstanding letters of credit under its revolving credit facilities in the amount of $499 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions, and $46 million for miscellaneous credit support requirements.

Texas Competitive Holdings has outstanding letters of credit under its revolving credit facilities totaling $455 million at June 30, 2007 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.

As of June 30, 2007, Texas Competitive Holdings had outstanding letters of credit under its revolving credit facilities totaling $77 million to support mining reclamation activities and certain collection agent activities performed for REPs in TXU Corp.'s historical service territory.

TXU Corp. and Texas Competitive Holdings have previously guaranteed the obligations under the lease agreement for TXU Corp.’s current headquarters building. These obligations include future undiscounted base rent payments. As a result of the March 2007 downgrade by S&P of Texas Competitive Holdings’ credit rating to below investment grade, Texas Competitive Holdings has provided a $144 million letter of credit to replace TXU Corp.’s and its guarantees of these obligations.

Security Interest

A first-lien security interest has been placed on the two lignite/coal-fueled generation units at Texas Competitive Holdings’ Big Brown plant to support commodity hedging transactions entered into by TXU DevCo. The lien can be used to secure obligations related to current and future hedging transactions of TXU DevCo or its affiliates for up to an aggregate of 1.2 billion MMBtu of natural gas.

11. SHAREHOLDERS’ EQUITY

Declaration of Dividend — At its May 2007 meeting, the Board of Directors of TXU Corp. declared a quarterly dividend of $0.4325 per share, which was paid on July 2, 2007 to shareholders of record on June 1, 2007. At its February 2007 meeting, the Board of Directors of TXU Corp. declared a quarterly dividend of $0.4325 per share, which was paid on April 2, 2007 to shareholders of record on March 2, 2007.

Dividend Restrictions — At June 30, 2007, there were no significant restrictions on the payment of regular quarterly common stock dividends; except that, the Merger Agreement prohibits TXU Corp. from increasing the regular quarterly common stock dividend to an amount greater than $0.4325 without the prior approval of the Sponsors.

Common Stock Repurchase— TXU Corp. has board of directors' authority to repurchase up to 23 million shares of TXU Corp. common stock through the end of 2007. Under this authority, TXU Corp. repurchased 153 thousand shares in the second quarter of 2007. The Merger Agreement generally prohibits TXU Corp. from making common stock repurchases without the prior approval of the Sponsors.

Shareholders’ Equity — The following table presents the changes to shareholders’ equity during the six months ended June 30, 2007:

	Common Stock		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity

Balance at December 31, 2006	$	5	$	1,104		$	622		$	409		$	2,140
Common stock issuances	─			1		─			─				1
Common stock repurchases	─			(10	)	─			─				(10	)
Net effects of cash flow hedges	─		─			─				(372	)		(372	)
Reclassification of pension and other retirement benefit costs	─		─			─				5			5
Dividends	─		─				(397	)	─				(397	)
Net loss	─		─				(377	)	─				(377	)
Effect of adoption of FIN 48	─		─				33		─				33
Effects of stock-based incentive compensation plans (a)	─			(77	)	─			─				(77	)
Excess tax benefit on stock-based compensation	─			82		─			─				82
Cost of Thrift Plan shares issued by LESOP trustee	─			6		─			─				6
Effects of executive deferred compensation plan	─			10		─			─				10
Other	─			(1	)		2		─				1
Balance at June 30, 2007	$	5	$	1,115		$	(117	)	$	42		$	1,045
_______________

(a)	Includes $93 million in settlements of minimum withholding tax liabilities.

12. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

The following table breaks down commodity and other derivative contractual assets and liabilities as presented in the balance sheet into the two major components:

	June 30, 2007
	Commodity contracts			Cash flow hedges and other derivatives		Netting adjustments (a)			Total

Assets:
Current assets	$	243		$	359	$	(303	)	$	299
Noncurrent assets		112			172		(68	)		216
Total	$	355		$	531	$	(371	)	$	515

Liabilities:
Current liabilities	$	701		$	31	$	(303	)	$	429
Noncurrent liabilities		810			134		(68	)		876
Total	$	1,511		$	165	$	(371	)	$	1,305

Net assets (liabilities)	$	(1,156	)	$	366	$ ─			$	(790	)


	December 31, 2006
	Commodity contracts			Cash flow hedges and other derivatives		Netting adjustments (a)			Total

Assets:
Current assets	$	276		$	698	$	(24	)	$	950
Noncurrent assets		162			248		(65	)		345
Total	$	438		$	946	$	(89	)	$	1,295

Liabilities:
Current liabilities	$	278		$	39	$	(24	)	$	293
Noncurrent liabilities		183			73		(65	)		191
Total	$	461		$	112	$	(89	)	$	484

Net assets (liabilities)	$	(23	)	$	834	$ ─			$	811

______________

(a)

Represents the effects of netting assets and liabilities at the counterparty agreement level.

Commodity Contract Assets and Liabilities — Commodity contract assets and liabilities primarily represent mark-to-market values of natural gas and electricity derivative instruments that have not been designated as cash flow hedges or “normal” purchases or sales under SFAS 133.

Current and noncurrent commodity contract assets are stated net of applicable credit (collection) and performance reserves totaling $10 million and $9 million at June 30, 2007 and December 31, 2006, respectively. Performance reserves are provided for direct, incremental costs to settle the contracts.

Commodity contract assets/liabilities at June 30, 2007 include "day one" losses of $164 million associated with contracts entered into in the first six months of 2007 at below market prices. Essentially all of this amount represents losses associated with transactions using natural gas financial instruments intended to economically hedge exposure to future changes in electricity prices. The losses were recorded as a reduction of revenues, consistent with other mark-to-market gains and losses, and were included in the results of the Competitive Electric segment.

Commodity contract assets/liabilities at June 30, 2007 includes a "day one" gain of $30 million associated with a long-term power purchase agreement entered into in the second quarter of 2007. The gain was recorded as an increase to revenues, consistent with other mark-to-market gains and losses, and was included in the results of the Competitive Electric segment.

Cash Flow Hedge and Other Derivative Assets and Liabilities — Cash flow hedge and other derivative assets and liabilities primarily represent mark-to-market values of commodity contracts that have been designated as cash flow hedges as well as interest rate swap agreements. The change in fair value of derivative assets and liabilities related to cash flow hedges are recorded as other comprehensive income or loss to the extent the hedges are effective; the ineffective portion of the change in fair value is included in net income. A portion of the interest rate swaps have been designated as fair value hedges and the change in fair value of such hedges are recorded as an increase or decrease in the carrying value of the debt (see Note 9); changes in fair value of other interest rate swaps are included in net income.

As previously disclosed, a significant portion of natural gas financial instruments entered into to hedge future changes in electricity prices had been designated and accounted for as cash flow hedges. In March 2007, these instruments were dedesignated as cash flow hedges as allowed under SFAS 133. Subsequent changes in the fair value of these instruments are being marked-to-market in net income.

A summary of cash flow hedge and other derivative assets and liabilities follows:

	June 30,		December 31,
	2007		2006

Current and noncurrent assets:
Commodity-related cash flow hedges	$	445	$	933
Debt-related interest rate swaps		71		4
Other		15		9
Total	$	531	$	946

Current and noncurrent liabilities:
Commodity-related cash flow hedges	$	20	$	23
Debt-related interest rate swaps		145		89
Total	$	165	$	112

Other Cash Flow Hedge Information — TXU Corp. experienced cash flow hedge ineffectiveness of $1 million in net losses and $114 million in net gains for the three and six month periods ended June 30, 2007, respectively. For the corresponding periods of 2006, the amounts were $141 million and $128 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 unrealized effect totaled $5 million in net losses and $94 million in net gains for the three and six month periods ended June 30, 2007, respectively, and $145 million and $144 million in net gains for the three and six month periods ended June 30, 2006, respectively.

As of June 30, 2007, commodity positions accounted for as cash flow hedges, which represent a small portion of economic hedge positions, reduce exposure to variability of future cash flows from future revenues or purchases through 2010.

Cash flow hedge amounts reported in the Statements of Condensed Consolidated Comprehensive Income exclude period net gains and losses associated with cash flow hedges settled within the periods presented. These amounts totaled $5 million and $16 million in after-tax net losses for the three and six month periods ended June 30, 2007, respectively, and $14 million and $18 million in after-tax net gains for the three and six month periods ended June 30, 2006, respectively.

TXU Corp. expects that $44 million of after-tax net gains related to cash flow hedges included in accumulated other comprehensive income will be reclassified into net income during the next twelve months as the related hedged transactions affect net income. Of this amount, $50 million in gains relate to commodity hedges and $6 million in losses relate to debt-related hedges.

13. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) COSTS

Net pension and OPEB costs for the three and six months ended June 30, 2007 and 2006 are comprised of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Components of net pension costs:
Service cost	$	9		$	11		$	20		$	21
Interest cost		36			34			71			68
Expected return on assets		(38	)		(37	)		(79	)		(73	)
Prior service cost		—			1			1			1
Net loss		6			8			10			16
Net pension cost		13			17			23			33
Components of net OPEB costs:
Service cost		4			3			6			6
Interest cost		14			15			27			30
Expected return on assets ��		(5	)		(5	)		(10	)		(10	)
Net transition obligation		1			1			1			1
Prior service cost		(1	)		(1	)		(2	)		(2	)
Net loss		3			7			13			15
Net OPEB costs		16			20			35			40

Net pension and OPEB costs		29			37			58			73
Less amounts deferred principally as a regulatory asset or property		(17	)		(21	)		(29	)		(41	)
Net amounts recognized as expense	$	12		$	16		$	29		$	32

The discount rate reflected in net pension and OPEB costs in 2007 is 5.90%. The expected rate of return on plan assets reflected in the 2007 cost amounts is 8.75% for the pension plan and 8.67% for the OPEB plan.

In accordance with accounting rules under SFAS 158, following is the detail of amounts reclassified from accumulated other comprehensive income (AOCI) to net pension and OPEB costs for the three months and six months ended June 30, 2007, respectively:

	Three Months Ended June 30, 2007									Six Months Ended June 30, 2007
	Pension Plan			OPEB Plan			Total			Pension Plan			OPEB Plan			Total
Net transition obligation	$	—		$	1		$	1		$	—		$	1		$	1
Prior service cost		—			(1	)		(1	)		1			(2	)		(1	)
Net loss		6			3			9			10			13			23
Total		6			3			9			11			12			23
Less amounts related to a regulatory asset		(4	)		(4	)		(8	)		(8	)		(7	)		(15	)
Net pretax amounts reclassified from AOCI	$	2		$	(1	)	$	1		$	3		$	5		$	8

TXU Corp. expects to make a $1 million required contribution to its pension plan in 2007.

14. SEGMENT INFORMATION

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

Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, retail electricity sales to residential and business customers, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. These activities are conducted principally by subsidiaries of Texas Competitive Holdings. The results of this segment also include the activities of TXU DevCo and its subsidiaries, which are engaged in the development of new generation facilities, and the activities of a lease trust holding certain combustion turbines.

Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor Electric Delivery, including its wholly owned bankruptcy-remote financing subsidiary, and also include certain revenues and costs associated with broadband-over-powerlines equipment installation.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses, interest on TXU Corp. and US Holdings debt and activities involving mineral interest holdings.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies. TXU Corp. evaluates 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						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Operating revenues:
Competitive Electric	$	1,666		$	2,349		$	2,983		$	4,359
Regulated Delivery		589			604			1,207			1,166
Corporate and Other		12			14			23			27
Eliminations		(245	)		(300	)		(522	)		(581	)
Consolidated	$	2,022		$	2,667		$	3,691		$	4,971

Regulated revenues included in operating revenues:
Competitive Electric	$ ─			$ ─			$ ─			$ ─
Regulated Delivery		589			604			1,207			1,166
Corporate and Other	─			─			─			─
Eliminations		(232	)		(284	)		(497	)		(551	)
Consolidated	$	357		$	320		$	710		$	615

Affiliated revenues included in operating revenues:
Competitive Electric	$	2		$	3		$	3		$	4
Regulated Delivery		232			284			497			551
Corporate and Other		11			13			22			26
Eliminations		(245	)		(300	)		(522	)		(581	)
Consolidated	$ ─			$ ─			$ ─			$ ─

Income (loss) from continuing operations:
Competitive Electric	$	129		$	461		$	(342	)	$	981
Regulated Delivery		54			86			140			151
Corporate and Other		(73	)		(50	)		(186	)		(119	)
Consolidated	$	110		$	497		$	(388	)	$	1,013

15. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations—

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Operating revenues:
Regulated	$	589		$	604		$	1,207		$	1,166
Unregulated		1,678			2,363			3,006			4,386
Intercompany sales eliminations – regulated		(232	)		(284	)		(497	)		(551	)
Intercompany sales eliminations – unregulated		(13	)		(16	)		(25	)		(30	)
Total operating revenues		2,022			2,667			3,691			4,971
Costs and operating expenses:
Fuel, purchased power costs and delivery fees – unregulated (a)		739			658			1,404			1,179
Operating costs – regulated		207			194			402			385
Operating costs – unregulated		161			147			312			299
Depreciation and amortization – regulated		114			117			234			231
Depreciation and amortization – unregulated		86			90			169			182
Selling, general and administrative expenses – regulated		49			43			90			90
Selling, general and administrative expenses – unregulated		178			138			357			280
Franchise and revenue-based taxes – regulated		60			59			121			119
Franchise and revenue-based taxes – unregulated		29			28			55			55
Other income		(16	)		(42	)		(45	)		(55	)
Other deductions		122			221			891			221
Interest income		(17	)		(11	)		(35	)		(20	)
Interest expense and related charges		221			218			418			431
Total costs and operating expenses		1,933			1,860			4,373			3,397
Income (loss) from continuing operations before income taxes	$	89		$	807		$	(682	)	$	1,574

_______________

(a)

Includes unregulated cost of fuel consumed of $245 million and $250 million for the three months ended June 30, 2007 and 2006, respectively, and $477 million and $415 million for the six months ended June 30, 2007 and 2006, respectively. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

The operations of the Competitive Electric segment are included above as unregulated as the Texas wholesale and retail electricity markets are open to competition. However, retail pricing to residential customers in the historical service territory was subject to certain price controls until December 31, 2006.

Interest Expense and Related Charges ─

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Interest	$	237		$	224		$	452		$	438
Amortization of debt discounts, premiums and issuance costs		8			4			12			8
Capitalized interest, including debt portion of allowance for borrowed funds
used during construction		(24	)		(10	)		(46	)		(15	)
Total interest expense and related charges	$	221		$	218		$	418		$	431

Restricted Cash—

	Balance Sheet Classification
	At June 30, 2007				At December 31, 2006
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets

Pollution control revenue bond funds held by trustee (See Note 9)	$	1	$	102	$ ─		$	241
Amounts related to securitization (transition) bonds		52		17		55		17
All other		1	─			3	─
Total restricted cash	$	54	$	119	$	58	$	258

Inventories by Major Category—

	June 30,		December 31,
	2007		2006
Materials and supplies	$	186	$	189
Fuel stock		97		94
Natural gas in storage		110		75
Environmental energy credits and emission allowances		35		25
Total inventories	$	428	$	383

Investments ─

	June 30,		December 31,
	2007		2006

Nuclear decommissioning trust	$	474	$	447
Assets related to employee benefit plans, principally employee savings programs		200		197
Land		36		36
Note receivable from Capgemini		25		25
Investment in unconsolidated affiliates		2		3
Miscellaneous other		5		4
Total investments	$	742	$	712

Property, Plant and Equipment ─ As of June 30, 2007 and December 31, 2006, property, plant and equipment of $19.4 billion and $18.8 billion, respectively, is stated net of accumulated depreciation and amortization of $12.7 billion and $12.4 billion, respectively.

Asset Retirement Obligations —These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant 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 Oncor 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 consolidated balance sheet, during the six months ended June 30, 2007:

Asset retirement liability at December 31, 2006	$	585
Additions:
Accretion		19
Reductions:
Mining reclamation cost adjustments		(2	)
Mining reclamation payments		(13	)
Asset retirement liability at June 30, 2007	$	589

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

	As of June 30, 2007						As of December 31, 2006
	Gross						Gross
	Carrying		Accumulated				Carrying		Accumulated
	Amount		Amortization		Net		Amount		Amortization		Net
Intangible assets subject to amortization included in property, plant and equipment
Capitalized software placed in service	$	435	$	352	$	83	$	423	$	339	$	84
Land easements		180		67		113		180		65		115
Total	$	615	$	419	$	196	$	603	$	404	$	199

Aggregate TXU Corp. amortization expense for intangible assets for the three months ended June 30, 2007 and 2006 totaled $8 million and $6 million, respectively. Aggregate TXU Corp. amortization expense for intangible assets for the six months ended June 30, 2007 and 2006 totaled $15 million and $14 million, respectively. At June 30, 2007, the weighted average remaining useful lives of capitalized software and land easements were six years and 69 years, respectively. The estimated aggregate amortization expense for each of the five succeeding fiscal years from December 31, 2006 is as follows:

Year	Amortization Expense

2007	$	33
2008		28
2009		18
2010		9
2011		6

Goodwill (net of accumulated amortization) as of June 30, 2007 and December 31, 2006 totaled $542 million with $517 million at Texas Competitive Holdings and $25 million at Oncor Electric Delivery.

Regulatory Assets and Liabilities —

	June 30, 2007		December 31, 2006
Regulatory assets
Generation-related regulatory assets securitized by transition bonds	$	1,246	$	1,316
Employee retirement costs		451		461
Storm-related service recovery costs		142		138
Securities reacquisition costs		108		112
Recoverable deferred income taxes — net		90		90
Employee severance costs		42		44
Total regulatory assets		2,079		2,161

Regulatory liabilities
Investment tax credit and protected excess deferred taxes		61		63
Over-collection of securitization (transition) bond revenues		34		34
Nuclear decommissioning cost over-recovery		26		17
Other regulatory liabilities		23		19
Total regulatory liabilities		144		133

Net regulatory assets	$	1,935	$	2,028

Regulatory assets totaling $121 million have been reviewed and approved by the Commission and are earning a return. The unamortized amounts of these regulatory assets reflected in the above table totaled $97 million at June 30, 2007 and $100 million at December 31, 2006. The assets that have been approved by the Commission and are not earning a return totaled $1.275 billion at June 30, 2007 and $1.343 billion at December 31, 2006, and have a remaining recovery period of nine to 44 years, including the regulatory assets securitized by transition bonds that have a remaining recovery period of nine years.

Supplemental Cash Flow Information —

	Six Months Ended
	June 30,
	2007		2006
Cash payments related to continuing operations:
Interest (net of amounts capitalized)	$	386	$	434
Income taxes	$	214	$	18
Noncash investing and financing activities:
Noncash construction expenditures	$	213	$	63

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 June 30, 2007, and the related condensed statements of consolidated income and comprehensive income for the three-month and six-month periods ended June 30, 2007 and 2006, and of cash flows for the six-month periods ended June 30, 2007 and 2006. 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. and subsidiaries as of December 31, 2006, and the related statements of consolidated income, comprehensive income, cash flows, and shareholders’ equity for the year then ended (not presented herein); and in our report dated March 1, 2007, 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, 2006 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Dallas, Texas

August 9, 2007

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Business

TXU Corp. is a holding company conducting its operations principally through its Texas Competitive Holdings, Oncor Electric Delivery and TXU DevCo subsidiaries and their subsidiaries. Each of these subsidiaries is a separate legal entity with its own assets and liabilities. Texas Competitive Holdings is a holding company whose subsidiaries are engaged in competitive market activities consisting of electricity generation, retail electricity sales to residential and business customers, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. Oncor 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 generation facilities in Texas; these development activities are expected to be continued by subsidiaries of Texas Competitive Holdings.

Operating Segments

TXU Corp. has aligned and reports its business activities as two operating segments: Competitive Electric (formerly TXU Energy Holdings) and Regulated Delivery (formerly Oncor Electric Delivery).

Competitive Electric segment includes the activities of Texas Competitive Holdings and TXU DevCo, as described above. This segment also includes the activities of a lease trust holding certain natural gas-fueled combustion turbines.

Regulated Delivery segment includes the activities of Oncor Electric Delivery, as described above, its wholly owned bankruptcy-remote financing subsidiary and certain revenues and costs associated with broadband-over-powerlines equipment installation.

See Note 14 to Financial Statements for further information concerning reportable business segments.

Recent Developments

Proposed Merger ─ In connection with the Proposed Merger, Mr. Wilder, TXU Corp.'s Chairman and Chief Executive Officer, has advised the Board of Directors that he will not be remaining with TXU Corp. following the Proposed Merger. However, in the event the Proposed Merger does not close, he will remain as Chairman and Chief Executive Officer of TXU Corp. to ensure the continuity of the corporate management team and to oversee TXU Corp.'s business and the implementation of an alternative strategy to the Proposed Merger.

The Merger Agreement contains a "go-shop" provision that gave TXU Corp. the right to solicit competing proposals until April 16, 2007. The "go-shop" process conducted on behalf of TXU Corp. by an independent financial advisor to the TXU Corp. Board of Directors has ended, and TXU Corp.'s Board of Directors determined that no proposal was received that could reasonably be expected to result in a proposal superior to the Proposed Merger.

TXU Corp. and the Sponsors are continuing their efforts to complete the Proposed Merger. In April 2007, TXU Generation Company LP filed an application with the NRC for the indirect transfer of control of the operating licenses relating to its Comanche Peak nuclear generation units. The receipt of the required NRC approval is a condition to the parties’ respective obligations to complete the Proposed Merger. The time period for third party intervention in respect of the NRC application expired in July 2007 without notice of any intervention in opposition to the transaction.

In May 2007, Oncor Electric Delivery, TXU Portfolio Management and Texas Energy Future Holdings Limited Partnership (TEF), the holding company formed by the Sponsors to acquire TXU Corp., filed with the FERC an application for the indirect transfer of control of certain FERC jurisdictional assets (principally the direct current interconnection between ERCOT and the Southwest Power Pool and TXU Portfolio Management's power marketer license). The receipt of FERC approval under Section 203 of the Federal Power Act is a condition to the parties’ respective obligations to complete the Proposed Merger. The time period for third party intervention in respect of the FERC application expired in June 2007 without notice of any intervention in opposition to the transaction.

In June 2007, TXU Corp. and the Sponsors filed required documents pursuant to the Hart-Scott-Rodino Act with the U.S. Department of Justice and the Federal Trade Commission. TXU Corp. received notification on July 16, 2007 that the required waiting period under the Hart-Scott-Rodino Act had ended. No further action is required by TXU Corp. and the Sponsors. The requirements of the Hart-Scott-Rodino Act will be satisfied if the Proposed Merger is completed within one year from the end of the waiting period. Although the waiting period has ended, the US Department of Justice, the Federal Trade Commission or others could take action under the antitrust laws with respect to the Proposed Merger, including seeking to enjoin the completion of, rescind or conditionally approve the Proposed Merger.

TXU Corp. has received approvals from the Federal Communication Commission for the transfer of radio and point-to-point private microwave licenses.

TXU Corp. has scheduled its annual shareholders' meeting and shareholder vote on the Proposed Merger for September 7, 2007. Assuming shareholder approval and required regulatory approvals are obtained, the Proposed Merger is expected to close in the fourth quarter of 2007.

In April 2007, Oncor Electric Delivery and TEF filed an application with the Commission under Section 14.101 of PURA requesting that the Commission make a determination that the transaction as it relates to Oncor Electric Delivery is in the public interest. While the filing of this application is not a condition to closing of the Proposed Merger, Oncor Electric Delivery and TEF are cooperating with the Commission in its review of the Proposed Merger as it relates to Oncor Electric Delivery.

As part of TXU Corp.'s plan to further differentiate its businesses (which is expected even if the Proposed Merger does not close), TXU Electric Delivery Company has been renamed Oncor Electric Delivery Company. In addition, in July 2007, TXU Corp.’s generation, wholesale and generation facility development operations began doing business under the "Luminant" brand name. No organizational or other operational changes were announced or implemented as part of the brand name change. The retail electricity operations retain the "TXU Energy" brand name.

Texas Generation Facilities Development Program ─ See discussion in Note 2 to the Financial Statements related to the charge resulting from the suspension of development of eight coal-fueled generation facilities.

Development of three lignite/coal-fueled generation facilities continues (two units at the Oak Grove site and one unit at the Sandow site). On June 13, 2007, the TCEQ voted to approve the air permit for the two units at Oak Grove. The transfer of the Sandow air permit from Alcoa, Inc. is expected to occur during the summer of 2007 (see Note 10 to Financial Statements). At June 30, 2007, construction work-in-process balances for these three units totaled approximately $1.0 billion.

Nuclear Generation Development ─ As previously disclosed, TXU Corp. planned to file applications for combined construction and operating licenses for 2,000 to 6,000 MW of new nuclear generation capacity at one to three sites in Texas. In order to focus effort and investment on the site that TXU Corp. believes has the highest potential, TXU Corp. is proceeding with the preparation of a combined license application for two new nuclear generation facilities, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site and is not actively pursuing development of additional sites. Although TXU Corp. may select and develop additional sites at a later date subsequent to closing of the Proposed Merger, no work is being done on the development of nuclear generation facilities at additional sites at this time and there is no schedule for the submittal of additional combined license applications.

Integrated Gasification Combined Cycle (IGCC) Demonstration Plants ─ In March 2007, TXU Corp. and the Sponsors announced their intention to explore the development of two IGCC commercial demonstration plants to be located in Texas and expects to issue a request for proposal from companies offering coal gasification technologies with carbon dioxide capture.

Utility Services Joint Venture ─ As previously disclosed, TXU Corp. and InfrastruX Group announced the formation of a joint venture, InfrastruX Energy Services (IES). TXU Corp. also announced an agreement between Oncor Electric Delivery and IES under which Oncor Electric Delivery would receive utility services from the joint venture. In April 2007, TXU Corp., Oncor Electric Delivery and InfrastruX Group amended their agreements to remove the March 31, 2007 end date and to permit either party to terminate the agreements at any time. TXU Corp. and InfrastruX Group have suspended activities related to the joint venture and Oncor Electric Delivery and IES have suspended activities related to the utility services agreement. The parties expect to terminate these agreements upon closing of the Proposed Merger.

In the second quarter of 2007, TXU Corp. wrote-off approximately $11 million ($7 million after-tax) in previously deferred costs primarily representing professional fees incurred in the development of the joint venture agreements.

Long-term Hedging Program ─ In October 2005, TXU Corp. initiated a long-term hedging program designed to reduce exposure to changes in future electricity 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. As of July 31, 2007, subsidiaries of TXU Corp. have effectively sold forward 2.2 billion MMBtu of natural gas (an equivalent of approximately 260,000 GWh at an assumed 8.5 market heat rate) over the period 2007 to 2013 at average annual prices ranging from $7 per MMBtu to $9 per MMBtu.

As previously disclosed, a significant portion of the instruments under the long-term hedging program had been designated and accounted for as cash flow hedges. In March 2007, these instruments were dedesignated as cash flow hedges as allowed under SFAS 133. Changes in fair value of these hedges that were deferred in accumulated other comprehensive income totaled $117 million in pretax gains at the time of the dedesignation, and this amount is expected to be reclassified to net income as the related forecasted transactions settle. Subsequent changes in the fair value of these instruments are being marked-to-market in net income, which has and could continue to result in significantly increased volatility in reported earnings. Based on the size of the long-term hedging program as of July 31, 2007, a $1.00/MMBtu change in natural gas prices would result in the recognition of approximately $2.2 billion in pretax unrealized mark-to-market gains or losses.

During 2007, subsidiaries of TXU Corp. entered into several large hedging transactions involving natural gas-related financial instruments that resulted in “day one” losses totaling $63 million in the second quarter of 2007 and $160 million year-to-date. The "day one" losses essentially represent the discount to transact these positions given their size and long dating.

The hedging transactions executed by TXU DevCo are secured by a first-lien security interest in the two lignite/coal-fueled generation units at Texas Competitive Holdings' Big Brown plant and are also guaranteed by Texas Competitive Holdings. Upon certain events, including the closing of the Proposed Merger, these hedging transactions will be transferred to Texas Competitive Holdings (or one of its subsidiaries) and will be supported by a first-lien security interest in Texas Competitive Holdings' assets.

Retail Pricing ─ In May 2007, TXU Corp. and the Sponsors announced that residential price cuts provided by TXU Energy Retail subsequent to the announcement of the Proposed Merger would total 15% (5% of which would only be implemented upon consummation of the Proposed Merger), which represents a five percentage point increase over the previously announced price discount program. The specifics of this price discount program and other pricing activities are as follows:

a six percent price discount effective with March 27, 2007 meter reads to those existing residential customers in the historical service territory with month-to-month service plans and a rate equivalent to the former price-to-beat rate;

an additional four percent price discount to the same class of customers as above effective with June 8, 2007 meter reads;

an additional five percent price discount to such customers upon closing of the Proposed Merger;

protection against price increases above the rates in effect prior to the four percent discount described above for bills based on meter readings through September 30, 2008 (excluding increases in response to a change in law or regulatory charges);

protection against price increases above the rates prior to the six percent discount described above for bills based on meter readings ending between October 1, 2008 and December 31, 2009 (excluding increases in response to a change in law or regulatory charges);

upon closing of the Proposed Merger, protection against price increases at the full fifteen percent discounted level through December 2008 (excluding increases in response to a change in law or regulatory charges); and

the remaining customer appreciation bonus of $25 to be applied to residential customers' bills in August 2007 under the previously announced customer appreciation bonus program, in addition to the $25 bonuses provided in each of the November 2006, February 2007 and May 2007 bill cycles (for residential customers who were receiving service as of October 29, 2006 and living in areas where TXU Energy Retail offered its price-to-beat rate).

RESULTS OF OPERATIONS

TXU Corp. Consolidated

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

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 decreased $645 million, or 24%, to $2.0 billion in 2007. The net decrease reflected the following:

Operating revenues in the Competitive Electric segment decreased $683 million, or 29%, to $1.7 billion. The decrease was driven by a $396 million decrease in retail electricity revenues and $370 million in increased losses from risk management and trading activities. The decrease in retail electricity revenues reflected lower volumes driven by cooler, below normal weather and a net loss of customers due to competitive activity. The retail revenue decrease also reflected residential price discount actions. The losses from risk management and trading activities reflected unrealized mark-to-market losses on positions in the long-term hedging program due to higher forward market prices of natural gas, with higher prices for all hedged future periods beyond 2008. Also, see discussion above under “Long-term Hedging Program”.

Operating revenues in the Regulated Delivery segment decreased $15 million, or 2%, to $589 million. The revenue decrease reflected lower delivered volumes primarily reflecting the effects of cooler, below normal weather, partially offset by higher transmission and delivery tariffs and installation revenues in 2007 for equipment installation services to support the broadband-over-powerlines initiative.

A decline in the net intercompany sales elimination of $53 million primarily reflected lower sales by Oncor Electric Delivery to REP subsidiaries of Texas Competitive Holdings, while its sales to nonaffiliated REPs increased.

Gross Margin


	Three Months Ended June 30,
	2007		% of Revenue			2006		% of Revenue

Operating revenues	$	2,022		100	%	$	2,667		100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		739		36			658		25
Operating costs		368		18			341		13
Depreciation and amortization		196		10			202		7
Gross margin	$	719		36	%	$	1,466		55	%

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 electricity.

Gross margin decreased $747 million, or 51%, to $719 million in 2007.

The Competitive Electric segment’s gross margin decreased $719 million, or 61%, to $452 million. The gross margin decrease reflected the declines in revenues and the combined effect of lower nuclear generation volumes (due to a planned outage) and increased higher-cost purchased power volumes.

The Regulated Delivery segment’s gross margin decreased $26 million, or 9%, to $268 million driven by the decline in revenues and higher third-party transmission fees.

Operating costs increased $27 million, or 8%, to $368 million in 2007.

The Competitive Electric segment’s operating costs increased $11 million, or 7%, reflecting higher generation maintenance costs, insurance costs and property taxes, partially offset by lower costs resulting from the outsourcing of certain generation technical support services.

The Regulated Delivery segment’s operating costs increased $13 million, or 7%, reflecting equipment installation costs to support the broadband-over-powerlines initiative and higher third-party transmission fees.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the gross margin table above) decreased $7 million, or 3%, to $200 million in 2007. The decreased expense reflects lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues) and lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006.

SG&A expenses increased $46 million, or 25%, to $227 million in 2007. The increase reflected:

$12 million in increased retail marketing expenses;

$11 million in higher professional services costs, due primarily to consulting fees for marketing/strategic projects and retail billing and customer care systems enhancements;

$8 million increase in salary and benefit costs driven largely by an increase in staffing in retail operations;

$5 million in higher incentive compensation;

$3 million in higher outsourced service provider costs due to contract adjustments;

$3 million for expenses related to rebranding of the Oncor Electric Delivery Company name; and

$2 million in increased contributions primarily for the Energy Aid (low-income customer assistance) program,

partially offset by $3 million in lower bad debt expense reflecting a decrease in delinquencies and lower accounts receivable balances.

Other income totaled $16 million in 2007 and $42 million in 2006. Other deductions totaled $122 million in 2007 and a $221 million in 2006. See Note 6 to Financial Statements for detail of other income and deductions. The 2007 other deductions amount includes an additional charge of $82 million related to the suspension of the development of eight coal-fueled generation units. (See Note 2 to Financial Statements.) The 2006 other deductions amount includes a $198 million impairment charge related to the natural gas-fueled generation plants.

Interest expense and related charges increased $3 million, or 1%, to $221 million in 2007 reflecting $21 million due to higher average borrowings, partially offset by $14 million in increased capitalized interest and $4 million from lower average interest rates.

Income tax benefit on income from continuing operations totaled $21 million in 2007 compared to income tax expense of $310 million on income from continuing operations in 2006. Excluding the $51 million deferred tax benefit in 2007 and the $41 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 4 to the Financial Statements, the effective income tax rate was 33.7% in 2007 (on a small income base) compared to 33.3% in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.) The increased effective rate reflects higher interest accrued related to uncertain tax positions partially offset by the effects on the rate of the significant unrealized mark-to-market net losses associated with the long-term hedging program.

Income from continuing operations (an after-tax measure) decreased $387 million to $110 million in 2007.

Earnings in the Competitive Electric segment decreased $332 million to $129 million driven by the decline in gross margin and higher SG&A expenses, partially offset by lower other deductions and the Texas margin tax benefit.

Earnings in the Regulated Delivery segment decreased $32 million, or 37%, to $54 million primarily driven by lower operating revenue, higher SG&A expenses and third-party transmission fees and costs associated with the cities rate settlement.

Corporate and Other net expenses totaled $73 million in 2007 and $50 million in 2006. The amounts in 2007 and 2006 consist principally of recurring interest expense on outstanding debt and affiliate borrowings at the TXU Corp. parent, as well as corporate general and administrative expenses. The increase of $23 million primarily reflects:

a $17 million after-tax favorable settlement in 2006 of a telecommunications contract dispute;

$8 million after-tax in higher accrued interest related to uncertain tax positions;

$7 million after-tax in increased SG&A expenses driven by higher compensation and consulting expenses;

a $5 million after-tax write-off in 2007 of deferred costs associated with the suspended Infrastrux joint venture; and

$4 million after-tax in financial advisory, legal and other professional fees in 2007 directly related to the Proposed Merger,

partially offset by the $21 million deferred tax benefit in 2007 related to the Texas Margin tax as described in Note 4 to the Financial Statements.

Net pension and postretirement benefit costs reduced income from continuing operations by $8 million in 2007 and $10 million in 2006.

TXU Corp. Consolidated

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

TXU Corp.’s operating revenues decreased $1.3 billion, or 26%, to $3.7 billion in 2007. The net decrease reflected the following:

Operating revenues in the Competitive Electric segment decreased $1.4 billion, or 32%, to $3.0 billion. The decrease was driven by $1.0 billion in increased losses from risk management and trading activities and a $354 million decrease in retail electricity revenues. The losses from risk management and trading activities reflected unrealized mark-to-market losses on positions in the long-term hedging program due to higher forward market prices of natural gas, with higher prices for all hedged future periods beyond 2008. Also, see discussion above under "Long-term Hedging Program". The decrease in retail electricity revenues reflected lower volumes driven by the effects of a net loss of customers due to competitive activity and cooler, below normal weather. The retail revenue decrease also reflected residential price discount actions.

Operating revenues in the Regulated Delivery segment increased $41 million, or 4%, to $1.2 billion. The revenue increase reflected higher distribution and transmission tariffs, revenues in 2007 for equipment installation services to support the broadband-over-powerlines initiative and growth in points of delivery.

A decline in the net intercompany sales elimination of $55 million reflected lower sales by Oncor Electric Delivery to REP subsidiaries of Texas Competitive Holdings, while its sales to nonaffiliated REPs increased.

Gross Margin


	Six Months Ended June 30,
	2007		% of Revenue			2006		% of Revenue

Operating revenues	$	3,691		100	%	$	4,971		100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,404		38			1,179		24
Operating costs		714		19			684		14
Depreciation and amortization		395		11			404		8
Gross margin	$	1,178		32	%	$	2,704		54	%

Gross margin decreased $1.5 billion, or 56%, to $1.2 billion in 2007.

The Competitive Electric segment’s gross margin decreased $1.5 billion, or 72%, to $609 million. The gross margin decrease reflected the declines in revenues and higher average cost of electricity sold due primarily to a decrease in baseload generation volumes (largely reflecting planned outages) and increased purchased power volumes.

The Regulated Delivery segment’s gross margin increased $21 million, or 4%, to $572 million driven by higher revenues, partially offset by higher third-party transmission fees.

Operating costs increased $30 million, or 4%, to $714 million in 2007.

The Competitive Electric segment’s operating costs increased $8 million, or 3%, reflecting $20 million in higher generation maintenance costs largely due to the scheduled outage of one of the nuclear generation units, partially offset by $11 million in lower costs associated with generation technical support outsourcing service agreements.

The Regulated Delivery segment’s operating costs increased $17 million, or 4%, reflecting equipment installation costs in 2007 to support the broadband-over-powerlines initiative and higher third-party transmission fees.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the gross margin table above) decreased $10 million, or 2%, to $403 million in 2007. The decreased expense reflects lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006, lower expense associated with mining reclamation obligations and lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues), partially offset by normal additions of property, plant and equipment and additional mining development amortization.

SG&A expenses increased $77 million, or 21%, to $447 million in 2007. The increase reflected:

$20 million in costs associated with the generation development program that was initiated in the second quarter of 2006, principally salaries and consulting expenses;

$18 million in increased retail marketing expenses;

$15 million in higher professional services costs, due primarily to consulting fees for retail billing and customer care systems enhancements and marketing/strategic projects;

$10 million in higher outsourced service provider costs due to contract adjustments;

$7 million increase in salary and benefit costs driven largely by an increase in staffing in retail operations;

$4 million in higher incentive compensation;

$3 million for expenses related to rebranding of the Oncor Electric Delivery Company name; and

$3 million in increased contributions primarily for the Energy Aid (low-income customer assistance) program,

partially offset by the effect of $12 million in executive severance expense in 2006.

Other income totaled $45 million in 2007 and $55 million in 2006. Other deductions totaled $891 million in 2007 and $221 million in 2006. The 2007 other deductions amount includes charges of $795 million related to the suspension of the development of eight coal-fueled generation units (see Note 2 to Financial Statements). The 2006 other deductions amount includes a $198 million impairment charge related to natural gas-fired generation plants. See Note 6 to Financial Statements for detail of other income and deductions.

Interest expense and related charges decreased $13 million, or 3%, to $418 million in 2007 reflecting $31 million in increased capitalized interest and $8 million from lower average interest rates, partially offset by $26 million due to higher average borrowings.

Income tax benefit on loss from continuing operations totaled $294 million in 2007 compared to income tax expense on income from continuing operations of $561 million in 2006. Excluding the $51 million deferred tax benefit in 2007 and the $41 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 4 to the Financial Statements, the effective income tax rate was 35.6% on a loss in 2007 compared to 33.0% on income in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.) The increased effective rate reflects the impact of the significant unrealized mark-to-market net losses associated with the long-term hedging program as well as the charge related to the suspended generation development activities. These effects were partially offset by higher interest accrued related to uncertain tax positions and higher income-based taxes arising from enactment of the Texas margin tax.

Results from continuing operations (an after-tax measure) decreased $1.4 billion to a loss of $388 million in 2007.

Results in the Competitive Electric segment decreased $1.3 billion to a loss of $342 million driven by the decline in gross margin and the charges related to the suspension of the development of eight coal-fueled generation units.

Earnings in the Regulated Delivery segment decreased $11 million, or 7%, to $140 million primarily driven by costs associated with the cities rate settlement, higher interest expense and higher third-party transmission fees, partially offset by higher operating revenues.

Corporate and Other net expenses totaled $186 million in 2007 and $119 million in 2006. The amounts in 2007 and 2006 consist principally of recurring interest expense on outstanding debt and affiliate borrowings at the TXU Corp. parent, as well as corporate general and administrative expenses. The increase of $67 million primarily reflects:

$20 million after-tax in financial advisory, legal and other professional fees in 2007 directly related to the Proposed Merger;

a 2007 write-off of $19 million after-tax in previously deferred costs related to anticipated strategic transactions (including expected financings) that are no longer expected to be completed as a result of the Proposed Merger;

a $17 million after-tax favorable settlement in 2006 of a telecommunications contract dispute;

$16 million after-tax in higher accrued interest related to uncertain tax positions; and

$9 million after-tax in higher SG&A expenses driven by higher compensation and consulting expenses,

partially offset by the $21 million deferred tax benefit in 2007 related to the Texas Margin tax as described in Note 4 to the Financial Statements.

Net pension and postretirement benefit costs reduced results from continuing operations by $19 million in 2007 and $21 million in 2006.

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

The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2007. The net changes in these assets and liabilities, excluding "other activity" as described below, represent the net effect of mark-to-market accounting for positions in the commodity contract portfolio, which excludes positions that are subject to cash flow hedge accounting. For the six months ended June 30, 2007, this effect totaled $1.3 billion in unrealized net losses, which represented $1.3 billion in net losses on unsettled positions, principally those positions entered into as part of the long-term hedging positions that were dedesignated as cash flow hedges for accounting purposes, and $7 million in reversals of net losses recognized in prior periods on positions settled in the current period. These positions represent both economic hedging and trading activities.

	Six Months
	Ended
	June 30, 2007

Net commodity contract liability at beginning of period	$	(23	)

Settlements of positions included in the opening balance (1)		7

Unrealized mark-to-market valuations of positions held at end of period (2)		(1,283	)

Other activity (3)		143

Net commodity contract liability at end of period	$	(1,156	)

_________________________

(1)

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

(2)

Includes mark-to-market effects of positions dedesignated as cash flow hedges (see discussion above under "Long-term Hedging Program"). Also includes $164 million in losses and a $30 million gain recorded at contract inception dates (see Note 12 to Financial Statements).

(3)

These amounts have not been recognized in prior and current year mark-to-market earnings. Includes initial values of positions involving the receipt or payment of cash or other consideration such as option premiums paid and received. Activity in 2007 included payments of $39 million related to natural gas physical swap transactions and a $102 million premium paid in 2007 related to a structured economic hedge transaction in the long-term hedging program.

In addition to the net effect of recording unrealized mark-to-market gains and losses that are reflected in the table above, 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 as changes in cash flow hedge and other derivative assets and liabilities (see Note 12 to Financial Statements). The total net effect of recording unrealized gains and losses related to commodity contracts under SFAS 133 is summarized as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Unrealized gains (losses) related to contracts marked-to-market	$	(413	)	$	(121	)	$	(1,276	)	$	(115	)

Ineffectiveness gains related to cash flow hedges (a)		(5	)		145			94			144

Total unrealized gains (losses) related to commodity contracts	$	(418	)	$	24		$	(1,182	)	$	29

_________________________

(a)	See Note 12 to Financial Statements.

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

Maturity Table — Of the net commodity contract liability balance above at June 30, 2007, the amount representing unrealized mark-to-market net losses that have been recognized in current and prior years' earnings totals $1.2 billion. Partially offsetting this net liability is a net asset of $51 million included in the June 30, 2007 balance sheet that is comprised principally of amounts representing current and prior years’ net payments of cash or other consideration, including $101 million of net option payments and $47 million in net receipts of natural gas related to physical swap transactions. The following table presents the unrealized net commodity contract liability arising from mark-to-market accounting as of June 30, 2007, scheduled by contractual settlement dates of the underlying positions.

	Maturity dates of unrealized net commodity contract liabilities at June 30, 2007
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	16		$	(200	)	$	(248	)	$	(23	)	$	(455	)
Prices provided by other
external sources (a)		6			(253	)		(353	)		(89	)		(689	)
Prices based on models (b)		(45	)		(18	)	─			─				(63	)
Total	$	(23	)	$	(471	)	$	(601	)	$	(112	)	$	(1,207	)
Percentage of total fair value		2	%		39	%		50	%		9	%		100	%

(a)

Includes “day one” losses of $138 million associated with hedge transactions and a "day one" gain of $30 million associated with a long-term power purchase agreement.

(b)

Includes "day one" loss of $26 million associated with a hedge transaction.

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 2011 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 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 each component valued separately. Components valued as forward commodity positions are included in the “prices provided by other external sources” category. Components valued as options are included in the “prices based on models” category.

Competitive Electric Segment

Financial Results

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Operating revenues	$	1,666		$	2,349		$	2,983		$	4,359

Costs and expenses:

Fuel, purchased power costs and delivery fees		971			943			1,902			1,733

Operating costs		163			152			314			306

Depreciation and amortization		82			84			161			169

Selling, general and administrative expenses		155			128			312			249

Franchise and revenue-based taxes		27			27			53			54

Other income	─				(1	)		(9	)		(1	)

Other deductions		93			205			808			195

Interest income		(85	)		(45	)		(162	)		(76	)

Interest expense and related charges		123			102			212			203

Total costs and expenses		1,529			1,595			3,591			2,832

Income (loss) before income taxes		137			754			(608	)		1,527

Income tax expense (benefit)		8			293			(266	)		546

Net income (loss)	$	129		$	461		$	(342	)	$	981

Competitive Electric Segment

Sales Volume Data

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2007			2006			Change %			2007			2006			Change %

Sales volumes:

Retail electricity sales volumes (GWh):
Historical service territory:
Residential		5,072			6,825			(25.7	)		10,719			12,057			(11.1	)
Small business (a)		1,537			2,068			(25.7	)		3,180			3,795			(16.2	)
Total historical service territory		6,609			8,893			(25.7	)		13,899			15,852			(12.3	)
Other territories:
Residential		1,010			1,018			(0.8	)		1,748			1,629			7.3
Small business (a)		204			169			20.7			368			301			22.3
Total other territories		1,214			1,187			2.3			2,116			1,930			9.6
Large business and other customers		3,653			3,552			2.8			7,043			6,785			3.8
Total retail electricity		11,476			13,632			(15.8	)		23,058			24,567			(6.1	)
Wholesale electricity sales volumes		9,290			7,852			18.3			17,977			15,705			14.5
Net sales (purchases) of balancing electricity
to/from ERCOT		302			(267	)	─				626			1,165			(46.3	)
Total sales volumes		21,068			21,217			(0.7	)		41,661			41,437			0.5

Average volume (kWh) per retail customer (b):

Residential		3,299			4,012			(17.8	)		6,731			6,975			(3.5	)
Small business		6,676			7,990			(16.4	)		13,476			14,460			(6.8	)
Large business and other customers		100,336			70,256			42.8			175,727			130,966			34.2

Weather (service territory average) – percent of normal (c):

Percent of normal:
Cooling degree days		85.3	%		131.0	%					88.8	%		135.9	%

________________

(a)

Customers with demand of less than 1 MW.

(b)

Calculated using average number of customers for period.

(c)

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

Competitive Electric Segment

Customer Count Data

	June 30,
	2007		2006		Change %
Customer counts:

Retail electricity customers (end of period and in thousands) (a):
Historical service territory:
Residential		1,560		1,716		(9.1	)
Small business (b)		248		271		(8.5	)
Total historical service territory		1,808		1,987		(9.0	)

Other territories:
Residential		273		227		20.3
Small business (b)		11		7		57.1
Total other territories		284		234		21.4

All territories:
Residential		1,833		1,943		(5.7	)
Small business (b)		259		278		(6.8	)
Total all territories ��		2,092		2,221		(5.8	)

Large business and other customers		36		49		(26.5	)
Total retail electricity customers		2,128		2,270		(6.3	)

________________

(a)

Based on number of meters.

(b)

Customers with demand of less than 1MW.

Competitive Electric Segment

Revenue and Market Share Data

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2007			2006			Change %			2007			2006			Change %
Operating revenues:
Retail electricity revenues:
Historical service territory:
Residential	$	700		$	1,008			(30.6	)	$	1,484		$	1,753			(15.3	)
Small business (a)		230			309			(25.6	)		468			566			(17.3	)
Total historical service territory		930			1,317			(29.4	)		1,952			2,319			(15.8	)

Other territories:
Residential		141			160			(11.9	)		249			248			0.4
Small business (a)		26			20			30.0			46			36			27.8
Total other territories		167			180			(7.2	)		295			284			3.9

Large business and other customers		343			339			1.2			657			655			0.3
Total retail electricity revenues		1,440			1,836			(21.6	)		2,904			3,258			(10.9	)
Wholesale electricity revenues		535			479			11.7			982			956			2.7
Net sales (purchases) of balancing electricity
to/from ERCOT	─				(32	)	─				9			26			(65.4	)
Net losses from risk management and trading activities		(383	)		(13	)	─				(1,069	)		(57	)	─
Other operating revenues		74			79			(6.3	)		157			176			(10.8	)
Total operating revenues	$	1,666		$	2,349			(29.1	)	$	2,983		$	4,359			(31.6	)

Risk management and trading activities:
Realized net gains (losses) on settled positions (b)	$	35		$	(38	)				$	113		$	(86	)
Reversal of prior periods’ unrealized net
(gains) losses on positions settled in current period		(21	)		2						(13	)		38
Other unrealized net gains (losses), including cash flow
hedge ineffectiveness		(397	)		23						(1,169	)		(9	)
Total net losses	$	(383	)	$	(13	)				$	(1,069	)	$	(57	)

Average revenues per MWh:
Residential	$	138.36		$	148.85			(7.0	)	$	139.01		$	146.23			(4.9	)

Estimated share of ERCOT retail markets (c):
Historical service territory:
Residential											62	%		69	%
Small business											61	%		68	%
Total ERCOT:
Residential											35	%		38	%
Small business											25	%		28	%
Large business and other customers											11	%		17	%

__________________________

(a)

Customers with demand of less than 1 MW.

(b)

Includes physical commodity trading activity not subject to mark-to-market accounting of $5 million in net losses in the second quarter of both 2007 and 2006, and $6 million and $15 million in net losses in the six months ended June 30, 2007 and 2006, respectively.

(c)

Based on number of meters. Estimated market share is based on the number of customers that have choice.

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2007			2006			Change %			2007			2006			Change %

Fuel, purchased power costs and delivery fees
($ millions):

Nuclear fuel	$	21		$	22			(4.5	)	$	39		$	43			(9.3	)
Lignite/coal		152			113			34.5			290			229			26.6
Total baseload fuel		173			135			28.1			329			272			21.0
Natural gas fuel and purchased power		435			421			3.3			818			689			18.7
Other costs		72			50			44.0			146			122			19.7
Fuel and purchased power costs		680			606			12.2			1,293			1,083			19.4
Delivery fees (a)		291			337			(13.6	)		609			650			(6.3	)
Total	$	971		$	943			3.0		$	1,902		$	1,733			9.8

Fuel and purchased power costs (which excludes
generation plant operating costs) per MWh:
Nuclear fuel	$	4.64		$	4.25			9.2		$	4.55		$	4.24			7.3
Lignite/coal (b)	$	16.14		$	12.67			27.4		$	15.62		$	12.33			26.7
Natural gas fuel and purchased power	$	62.86		$	63.40			(0.9	)	$	61.37		$	61.76			(0.6	)

Delivery fees per MWh	$	24.90		$	24.51			1.6		$	25.94		$	26.18			(0.9	)

Production and purchased power volumes (GWh):

Nuclear		4,492			5,098			(11.9	)		8,555			10,178			(15.9	)
Lignite/coal		10,211			10,044			1.7			20,197			20,918			(3.4	)
Total baseload generation		14,703			15,142			(2.9	)		28,752			31,096			(7.5	)
Natural gas-fueled generation		633			1,350			(53.1	)		1,382			1,539			(10.2	)
Purchased power		6,287			5,291			18.8			11,957			9,616			24.3
Total energy supply		21,623			21,783			(0.7	)		42,091			42,251			(0.4	)
Less line loss and power imbalances		555			566			(1.9	)		430			814			(47.2	)
Net energy supply volumes		21,068			21,217			(0.7	)		41,661			41,437			0.5

Baseload capacity factors (%):

Nuclear		89.6	%		102.0	%		(12.2	)		85.8	%		102.3	%		(16.1	)
Lignite/coal		85.9	%		82.4	%		4.2			86.6	%		86.4	%		0.2
Total baseload		87.0	%		88.0	%		(1.1	)		86.3	%		90.9	%		(5.1	)

________________

(a)

Includes delivery fee charges from Oncor Electric Delivery that are eliminated in consolidation.

(b)

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

Competitive Electric Segment

See Note 2 to Financial Statements for discussion of potential charges in future periods in connection with the suspended development of eight coal-fueled generation facilities.

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

Operating revenues decreased $683 million, or 29%, as follows:

	Three Months Ended June 30,
	2007			2006			Increase (Decrease)
Retail electricity revenues	$	1,440		$	1,836		$	(396	)
Wholesale electricity revenues		535			479			56
Wholesale balancing activities	─				(32	)		32
Net losses from risk management and trading activities		(383	)		(13	)		(370	)
Other operating revenues		74			79			(5	)
Total operating revenues	$	1,666		$	2,349		$	(683	)

The $396 million, or 22%, decrease in retail electricity revenues reflected the following:

Lower retail volumes contributed $290 million to the revenue decrease. Residential and small business volumes in the historical service territory decreased 26% reflecting cooler, below normal weather that drove an 18% decrease in average consumption per customer and the effects of a net loss of customers due to competitive activity.

Lower average pricing (including customer mix effects) contributed $106 million to the revenue decrease. Lower average retail pricing reflected new competitive product offerings, the effect of a six percent price discount, effective with meter reads on March 27, 2007, and an additional four percent price discount, effective with meter reads on June 8, 2007, to those residential customers in the historical service territory with month-to-month service plans and a rate equivalent to the former price-to-beat rate. Average prices in the large business market decreased 2% primarily reflecting a change in customer mix.

Total retail electricity customer counts at June 30, 2007 declined 6% from June 30, 2006. Total residential and small business customer counts in the historical service territory declined 9% and in all combined territories declined 6%.

Wholesale electricity revenues increased $56 million, or 12%. Volume growth of 18% contributed $88 million to the increase, which was partially offset by a $32 million pricing impact as average wholesale prices declined 6% reflecting lower natural gas prices. The volume growth was due in part to the decline in retail volumes associated with competitive activity.

Wholesale balancing activity comparisons are not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, that are highly variable.

Results from risk management and trading activities include realized and unrealized gains and losses associated with financial instruments used for economic hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading purposes. Because most of the hedging and risk management activities are intended to mitigate the risk of future 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. Following is an analysis of activities in the second quarter of 2007:

Results associated with the long-term hedging program

$400 million in unrealized mark-to-market net losses, which includes $386 million in net losses on unsettled positions and $14 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

$63 million in unrealized "day one" losses on a related series of commodity price hedges entered into at below-market prices;

$3 million in unrealized cash flow hedge ineffectiveness net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period; and

$34 million in realized net gains that offset hedged electricity revenues recognized in the current period.

Results associated with other risk management and trading activities

$33 million in unrealized net gains on economic hedge positions, which includes $40 million in net gains on unsettled positions and $7 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

$30 million "day one" gain on a long-term power purchase agreement; and

$14 million in other net losses, including unrealized losses on commodity trading positions.

Gross Margin


	Three Months Ended June 30,
	2007		% of Revenue			2006		% of Revenue

Operating revenues	$	1,666		100	%	$	2,349		100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		971		58			943		40
Generation plant operating costs		163		10			152		6
Depreciation and amortization		80		5			83		4
Gross margin	$	452		27	%	$	1,171		50	%

Gross margin decreased $719 million, or 61%, to $452 million in 2007. The decrease reflected $370 million unfavorable change in results from risk management and trading activities, a 26% decrease in residential and small business volumes in the historical service territory and lower retail electricity average pricing driven by residential price discounts. Lower gross margin also reflected higher average cost of electricity sold due to a 12% decrease in nuclear generation volumes and increased purchased power volumes. In addition, average fuel cost per MWh generated increased 5% as the impact of inefficiencies in lignite mining operations due to significantly above normal rainfall was partially offset by the favorable effect of lower utilization of natural gas-fueled plants.

The decline in nuclear generation volumes was due to a planned refueling and major maintenance outage for one of the two Comanche Peak units. Maintenance work during the 55-day outage, which ended in late April 2007, included the replacement of the unit's steam generators and reactor vessel head.

Gross margin as a percent of revenues decreased 23 percentage points to 27%. The decline reflected:

the effect of results from risk management and trading activities, including unrealized mark-to-market losses on positions in the long-term hedging program (12 percentage point margin decrease);

the effect of a decrease in residential and small business sales volumes and an increase in wholesale sales volumes (six percentage point margin decrease);

the effect of lower average retail electricity pricing (two percentage point margin decrease); and

the effect of lower generation volumes and higher purchased power volumes (one percentage point margin decrease).

Operating costs increased $11 million, or 7%, to $163 million in 2007. The increase reflected:

$6 million in higher generation maintenance costs largely due to the scheduled outage of one of the nuclear generation units;

$6 million in higher insurance costs, principally property-related; and

$5 million in higher property taxes reflecting higher valuations for 2007,

partially offset by $7 million in lower costs associated with the outsourcing of certain generation technical support services.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) decreased $2 million, or 2%, to $82 million primarily reflecting lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006.

SG&A expenses increased $27 million, or 21%, to $155 million in 2007. The increase reflected:

$12 million in increased retail marketing expenses;

$8 million in higher salary and benefit costs primarily driven by an increase in staffing in retail operations;

$6 million in higher professional fees primarily for marketing/strategic projects and retail billing and customer care systems enhancements;

$2 million in higher incentive compensation expense; and

$2 million in increased contributions primarily for the Energy Aid (low-income customer assistance) program,

partially offset by $3 million in lower bad debt expense driven by a decrease in delinquencies and lower accounts receivable balances due to the milder winter weather.

Other deductions totaled $93 million in 2007 and $205 million in 2006. The 2007 amount includes a charge of $82 million in connection with the suspension of the development of eight coal-fueled generation units (see Note 2 to Financial Statements) and $5 million in connection with the settlement of the Commission’s investigation regarding TXU Energy Retail’s renewal process for certain small and medium business customers on term service plans. The 2006 amount includes a charge of $198 million to write down the natural gas-fueled generation plants to fair value.

Interest income increased $40 million to $85 million in 2007 reflecting $21 million due to higher average advances to affiliates and $19 million due to higher average rates on the advances.

Interest expense and related charges increased by $21 million, or 21%, to $123 million in 2007. The increase reflected $18 million due to higher average borrowings and $16 million due to higher average interest rates, partially offset by $13 million in increased capitalized interest.

Income tax expense totaled $8 million in 2007 compared to $293 million in 2006. Excluding the $30 million deferred tax benefit in 2007 and the $42 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 4 to the Financial Statements, the effective income tax rate was 27.7% in 2007 on a small income base compared to 33.2% in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.) The lower effective rate reflected the impact of the significant unrealized mark-to-market net losses associated with the long-term hedging program, partially offset by higher interest accrued related to uncertain tax positions.

Net income decreased $332 million to $129 million in 2007 driven by the decline in gross margin and higher SG&A expenses, partially offset by lower other deductions and the Texas margin tax benefit.

Competitive Electric Segment

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Operating revenues decreased $1.4 billion, or 32%, as follows:

	Six Months Ended June 30,
	2007			2006			Increase (Decrease)
Retail electricity revenues	$	2,904		$	3,258		$	(354	)
Wholesale electricity revenues		982			956			26
Wholesale balancing activities		9			26			(17	)
Net losses from risk management and trading activities		(1,069	)		(57	)		(1,012	)
Other operating revenues		157			176			(19	)
Total operating revenues	$	2,983		$	4,359		$	(1,376	)

The $354 million, or 11%, decrease in retail electricity revenues reflected the following:

Lower retail volumes contributed $200 million to the revenue decrease. Residential and small business volumes in the historical service territory decreased 12% reflecting the effects of a net loss of customers due to competitive activity and lower average consumption per customer of 4% reflecting the cooler, below normal weather in the second quarter of 2007. Large business market volumes increased 4% reflecting a change in customer mix.

Lower average pricing (including customer mix effects) contributed $154 million to the revenue decrease. Lower average retail pricing reflected new competitive product offerings, the effect of a six percent price discount, effective with meter reads on March 27, 2007, and an additional four percent price discount, effective with meter reads on June 8, 2007, to those residential customers in the historical service territory with month-to-month service plans and a rate equivalent to the former price-to-beat rate. Average prices in the large business market decreased 3% primarily reflecting a change in customer mix.

Wholesale electricity revenues increased $26 million, or 3%. Volume growth of 14% contributed $138 million to the increase, which was partially offset by a $112 million pricing impact as average wholesale prices declined 10% reflecting lower natural gas prices. The volume growth was due in part to the decline in retail volumes associated with competitive activity.

Results associated with the long-term hedging program

$1.099 billion in unrealized mark-to-market net losses, which includes $1.130 billion in net losses on unsettled positions and $31 million in net gains that represent reversals of previously recorded unrealized net losses on positions settled in the current period;

$96 million in unrealized cash flow hedge ineffectiveness net gains, which includes $114 million in net gains on unsettled positions and $18 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

$160 million in unrealized "day one" losses on large positions entered into at below-market prices; and

$93 million in realized net gains that offset hedged electricity revenues recognized in the current period.

Results associated with other risk management and trading activities

$50 million in unrealized net losses on commodity trading positions, which includes $22 million in net losses on unsettled positions and $28 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the current period;

$30 million "day one" gain on a long-term power purchase agreement; and

$18 million in other gains, driven by realized net gains on settlement of trading positions.

Gross Margin


	Six Months Ended June 30,
	2007		% of Revenue			2006		% of Revenue

Operating revenues	$	2,983		100	%	$	4,359		100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		1,902		64			1,733		40
Generation plant operating costs		314		11			306		7
Depreciation and amortization		158		5			166		4
Gross margin	$	609		20	%	$	2,154		49	%

Gross margin decreased $1.5 billion, or 72%, to $609 million in 2007. The decrease reflected $1.0 billion unfavorable change in results from risk management and trading activities, a 12% decrease in residential and small business volumes in the historical service territory and lower average retail electricity pricing driven by residential price discounts. Lower gross margin also reflected higher average cost of electricity sold due to an 8% decrease in baseload generation volumes and increased purchased power volumes. In addition, average fuel cost per MWh generated increased 23% due primarily to inefficiencies in lignite mining operations caused by significantly above normal rainfall.

The decline in baseload generation volumes was primarily due to a planned refueling and major maintenance outage for one of the two Comanche Peak nuclear units, which resulted in a 16% decline in nuclear generation volumes. Maintenance work during the 55-day outage, which ended in late April 2007, included the replacement of the unit's steam generators and reactor vessel head.

Gross margin as a percent of revenues decreased 29 percentage points to 20%. The decline reflected:

the effect of results from risk management and trading activities, including net unrealized mark-to-market losses on positions in the long-term hedging program (19 percentage point margin decrease);

the effect of a decrease in residential and small business sales volumes and an increase in wholesale sales volumes (three percentage point margin decrease);

the effect of lower average retail electricity pricing (two percentage point margin decrease);

the effect of lower generation volumes and higher purchased power volumes (two percentage point margin decrease); and

the effect of higher average fuel costs (one percentage point margin decrease).

Operating costs increased $8 million, or 3%, to $314 million in 2007. The increase reflected $20 million in higher generation maintenance costs largely due to the scheduled outage of one of the nuclear generation units, partially offset by $11 million in lower costs in 2007 associated with generation technical support outsourcing service agreements.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) decreased $8 million, or 5%, to $161 million driven by lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006 and lower expense associated with mining reclamation obligations.

SG&A expenses increased $63 million, or 25%, to $312 million in 2007. The increase reflected:

$20 million in costs associated with the generation development program, principally salaries and consulting expenses;

$18 million in increased retail marketing expenses;

$12 million in higher professional fees primarily for retail billing and customer care systems enhancements and marketing/strategic projects;

$10 million in higher salary and benefit costs primarily driven by an increase in staffing in retail operations;

$7 million in higher costs due to reallocation of Capgemini outsourcing fees; and

$3 million in increased contributions primarily for the Energy Aid (low-income customer assistance) program,

partially offset by $6 million in executive severance expense in 2006 (including amounts allocated from parent).

Other income totaled $9 million in 2007 and $1 million in 2006. Other income in 2007 includes $5 million of royalty income and $3 million in penalties received due to nonperformance under a coal transportation agreement.

Other deductions totaled $808 million in 2007 and $195 million in 2006. The 2007 amount includes charges of $795 million in connection with the suspension of the development of eight coal-fueled generation units (see Note 2 to Financial Statements).

The 2006 amount includes:

a $198 million charge related to the write-down of the natural gas-fueled generation plants to fair value;

$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; and

$2 million in accretion expense related to the combustion turbine lease liability,

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).

Interest income increased $86 million to $162 million in 2007 reflecting $49 million due to higher average advances to affiliates and $37 million due to higher average rates on the advances.

Interest expense and related charges increased by $9 million, or 4%, to $212 million in 2007. The increase reflected $24 million due to higher average borrowings and $15 million due to higher average interest rates, partially offset by $30 million in increased capitalized interest.

Income tax benefit totaled $266 million in 2007 compared to income tax expense of $546 million in 2006. Excluding the $30 million deferred tax benefit in 2007 and the $42 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 4 to the Financial Statements, the effective income tax rate was a 38.8% on a loss in 2007 compared to 33.0% on income in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.) The increased effective rate reflects the impact of the significant unrealized mark-to-market net losses associated with the long-term hedging program as well as the charge related to the suspended generation development activities. These effects were partially offset by higher interest accrued related to uncertain tax positions and the higher income-based taxes arising from enactment of the Texas margin tax.

Results decreased $1.3 billion to a loss of $342 million in 2007 driven by the decline in gross margin and the charges related to the suspension of the development of eight lignite/coal-fueled generation units.

Regulated Delivery Segment

Financial Results

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Operating revenues	$	589		$	604		$	1,207		$	1,166

Costs and expenses:

Operating costs		207			194			402			385

Depreciation and amortization		114	��		117			234			231

Selling, general and administrative expenses		51			43			93			93

Franchise and revenue-based taxes		60			59			121			119

Other income		(1	)		―			(3	)		(1	)

Other deductions		10			1			19			2

Interest income		(14	)		(14	)		(29	)		(29	)

Interest expense and related charges		78			72			154			140

Total costs and expenses		505			472			991			940

Income before income taxes		84			132			216			226

Income tax expense		30			46			76			75

Net income	$	54		$	86		$	140		$	151

Regulated Delivery Segment

Operating Data

	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2007		2006		Change %			2007		2006		Change %
Operating statistics – volumes:
Electric energy delivered (GWh)		24,972		27,244		(8.3	)		49,966		50,376		(0.8	)

Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)									77.92		73.54		6.0
System Average Interruption Frequency Index (SAIFI) (nonstorm)									1.15		1.11		3.6
Customer Average Interruption Duration Index (CAIDI) (nonstorm)									67.78		66.11		2.5

Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters) (b)									3,077		3,038		1.3

Operating revenues:
Electricity distribution revenues (c):
Affiliated (Texas Competitive Holdings)	$	230	$	283		(18.7	)	$	494	$	550		(10.2	)
Nonaffiliated		278		254		9.4			558		485		15.1
Total distribution revenues		508		537		(5.4	)		1,052		1,035		1.6
Third-party transmission revenues		65		59		10.2			126		116		8.6
Other miscellaneous revenues		16		8		100.0			29		15		93.3
Total operating revenues	$	589	$	604		(2.5	)	$	1,207	$	1,166		3.5

__________________________

	(a)	SAIDI is the average number of electric service interruption minutes per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption 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 Retail is the REP but are not included in TXU Energy Retail’s customer count. Such sites totaled 79,856 and 84,362 at June 30, 2007 and 2006, respectively.
	(c)	Includes transition charge revenue associated with the issuance of securitization bonds totaling $33 million and $37 million for the three months ended June 30, 2007 and 2006, respectively, and $70 million and $73 million for the six months ended June 30, 2007 and 2006, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

Regulated Delivery Segment

Regulated Delivery’s future results are expected to be impacted by the effects of the 2006 cities rate settlement. Incremental expenses of approximately $70 million are being recognized almost entirely over the period from May 2006 through June 2008, of which $8 million and $16 million has been recognized in the three and six month periods ended June 30, 2007, respectively.

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

Operating revenues decreased $15 million, or 2%, to $589 million in 2007. The revenue decrease reflected:

an estimated $33 million in lower revenues due to decreased delivered volumes primarily reflecting the effects of cooler, below normal weather; and

$4 million in lower charges to REPs related to securitization bonds (offset by lower amortization of the related regulatory asset),

partially offset by,

$7 million for installation services related to equipment to support the broadband-over-powerlines initiative;

$6 million in higher transmission revenues primarily due to rate increases approved in 2006 and 2007 to recover ongoing investment in the transmission system;

$4 million from increased distribution tariffs to recover higher transmission costs; and

$3 million due to increased growth in points of delivery.

Gross Margin


	Three Months Ended
	June 30,
	2007		% of Revenue			2006		% of Revenue

Operating revenues	$	589		100	%	$	604		100	%
Costs and expenses:
Operating costs		207		35			194		32
Depreciation and amortization		114		19			116		19
Gross margin	$	268		46	%	$	294		49	%

Operating costs increased $13 million, or 7%, to $207 million in 2007. The increase reflected $7 million in equipment installation costs related to the broadband-over-powerlines initiative, $6 million in higher fees to other transmission entities, $5 million in increased labor costs primarily for restoration of service as a result of weather events and individually insignificant cost increases in several categories, partially offset by lower vegetation management expenses of $11 million due primarily to timing of these activities.

Depreciation and amortization decreased $3 million, or 3%, to $114 million in 2007. The decrease reflected $4 million in lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues), partially offset by $1 million in higher depreciation due to normal additions and replacements of property, plant and equipment.

SG&A expenses increased $8 million, or 19%, to $51 million in 2007. The increase reflected $3 million for expenses related to the rebranding of the Oncor Electric Delivery Company name, $2 million in higher legal and consulting fees, $2 million in higher outsourced service provider costs and $1 million in higher sale of receivables program fees driven by higher interest rates.

Franchise and revenue-based taxes increased $1 million, or 2%, to $60 million in 2007. The increase was driven primarily by higher franchise fees under the cities rate settlement.

Other deductions totaled $10 million in 2007 and $1 million in 2006. The 2007 amount includes $7 million in costs as a result of the 2006 cities rate settlement and $3 million in costs related to the InfrastruX Energy Services joint venture.

Interest expense increased $6 million, or 8%, to $78 million in 2007. The increase reflects $4 million due to higher average borrowings and $2 million due to higher average interest rates.

Income tax expense totaled $30 million in 2007 compared to $46 million in 2006. The effective income tax rate increased to 35.7% in 2007 from 34.8% in 2006. The increase reflects higher interest accrued related to uncertain tax positions and the effect of full amortization prior to 2007 of a regulatory liability associated with statutory tax rate changes.

Net income decreased $32 million, or 37%, to $54 million. This decrease was primarily driven by lower operating revenue, higher SG&A expenses and fees to other transmission entities and costs associated with the cities rate settlement.

Regulated Delivery Segment

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Operating revenues increased $41 million, or 4%, to $1.2 billion in 2007. The revenue increase reflected:

$13 million for installation services related to equipment to support the broadband-over-powerlines initiative;

$10 million from increased distribution tariffs to recover higher transmission costs;

$9 million in higher transmission revenues primarily due to rate increases approved in 2006 and 2007 to recover ongoing investment in the transmission system; and

$8 million due to growth in points of delivery,

partially offset by,

$3 million in lower charges to REPs related to securitization bonds (offset by lower amortization of the related regulatory asset).

Gross Margin


	Six Months Ended
	June 30,
	2007		% of Revenue			2006		% of Revenue

Operating revenues	$	1,207		100	%	$	1,166		100	%
Costs and expenses:
Operating costs		402		33			385		33
Depreciation and amortization		233		20			230		20
Gross margin	$	572		47	%	$	551		47	%

Operating costs increased $17 million, or 4%, to $402 million in 2007. The increase reflected $12 million in higher fees to other transmission entities, $12 million in equipment installation costs related to the broadband-over-powerlines initiative and $5 million in increased labor costs primarily due to restore service as a result of weather events, partially offset by lower vegetation management expenses of $14 million, due primarily to timing of these activities.

Depreciation and amortization increased $3 million, or 1%, to $234 million in 2007. The increase reflected $5 million in higher depreciation due to normal additions and replacements of property, plant and equipment, partially offset by $2 million in lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues).

Franchise and revenue-based taxes increased $2 million, or 2%, to $121 million in 2007. The increase was driven primarily by higher franchise fees under the cities rate settlement.

Other deductions totaled $19 million in 2007 and $2 million in 2006. The 2007 amount includes $13 million in costs as a result of the 2006 cities rate settlement and $4 million in costs related to the InfrastruX Energy Services joint venture.

Interest expense increased $14 million, or 10%, to $154 million in 2007. The increase reflects $11 million due to higher average borrowings and $3 million due to higher average interest rates.

Income tax expense totaled $76 million in 2007 compared to $75 million in 2006. The effective income tax rate increased to 35.2% in 2007 from 33.2% in 2006. The increase reflects higher taxes as a result of the enactment of the Texas margin tax, higher interest accrued related to uncertain tax positions and the effect of full amortization prior to 2007 of a regulatory liability associated with statutory tax rate changes.

Net income decreased $11 million, or 7%, to $140 million. This decrease was driven by costs associated with the cities rate settlement, higher interest expense due primarily to higher average borrowings and higher fees to other transmission entities, partially offset by higher operating revenue.

COMPREHENSIVE INCOME – Continuing Operations

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Net increase (decrease) in fair value of cash flow hedges (all commodity-related) held at end of period	$	35		$	(83	)	$	(281	)	$	30
Derivative value net losses (gains) reported in net income that relate to hedged
transactions recognized in the period:
Commodities		(19	)		10			(95	)		7
Financing – interest rate swaps (a)		2			2			4			4
		(17	)		12			(91	)		11
Total income (loss) effect of cash flow hedges reported in other comprehensive
income from continuing operations	$	18		$	(71	)	$	(372	)	$	41

______________

(a)	Represents recognition of net losses on settled swaps.

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 amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 12 to Financial Statements.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows — Cash flows used in operating activities for the six months ended June 30, 2007 totaled $55 million compared to cash flows provided by operating activities of $1.9 billion in 2006. The decrease of $2.0 billion reflected:

lower operating earnings after taking into account noncash items such as deferred federal income taxes, unrealized mark-to-market valuations and charges related to suspended development of generation facilities;

an unfavorable change of $959 million in net margin deposits due to the effect of higher forward natural gas prices on hedge positions;

an unfavorable change in working capital (accounts receivable, accounts payable and inventories) balances of $252 million primarily due to the effects of lower natural gas prices, as cash flows in 2006 included the collection of higher wholesale natural gas and electricity receivables that resulted from higher prices in late 2005; and

a $102 million premium paid in 2007 related to a structured natural gas-related option transaction entered into as part of the long-term hedging program.

Cash flows provided by financing activities totaled $1.9 billion in 2007 compared to cash flows used by financing activities of $806 million in 2006 as summarized below:

	Six Months Ended June 30,
	2007			2006
Net issuances, repayments and repurchases of borrowings	$	2,433		$	263
Net issuances and repurchases of common stock ��		(9	)		(629	)
Common stock dividends paid		(397	)		(384	)
Settlements of minimum withholding tax liabilities under stock-based incentive compensation plans		(93	)		(56	)
Total	$	1,934		$	(806	)

Cash flows used in investing activities increased $444 million as summarized below:

	Six Months Ended June 30,
	2007			2006

Capital expenditures, including nuclear fuel	$	(1,641	)	$	(855	)
Reduction of restricted cash related to the redemption of pollution control revenue bonds		143			―
Purchase of lease trust		―			(69	)
Proceeds from pollution control revenue bonds deposited with trustee		―			(99	)
Net investments in nuclear decommissioning trust fund securities		(7	)		(7	)
Investment in unconsolidated affiliate		―			(15	)
Costs to remove retired property		(16	)		(22	)
Other		15			5
Total	$	(1,506	)	$	(1,062	)

The $786 million, or 91.9%, increase in capital expenditures was driven by new generation facility development spending.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $30 million for the six months ended June 30, 2007. This difference represents amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice.

TXU Corp. may be restricted in applying its current capital allocation model under the terms of the Merger Agreement. In particular, TXU Corp. may be required to obtain consent of the Sponsors to make certain capital expenditures or to pay quarterly dividends in excess of 43.25 cents per share.

Certain financing arrangements of TXU Corp. and its subsidiaries are expected to be amended, replaced or discontinued as a result of the Proposed Merger. For example, as described in the 2006 Form 10-K, the credit facilities currently in place are expected to be replaced with new liquidity facilities upon consummation of the Proposed Merger. In addition, upon consummation of the Proposed Merger, Texas Competitive Holdings and Oncor Electric Delivery are required to redeem an aggregate of $1.8 billion floating rate senior notes issued in March 2007 and TXU Corp. and its subsidiaries may repurchase certain of their other outstanding debt securities.

Long-term Debt Activity — During the six months ended June 30, 2007, 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.:
Other long-term debt	$	―	$	(6	)

Texas Competitive Holdings:
Floating rate senior notes		1,000		―
Pollution control revenue bonds		―		(143	)
Other long-term debt		―		(6	)

Oncor Electric Delivery:
Floating rate senior notes		800		―
Transition bonds		―		(48	)

US Holdings		―		(8	)

Total	$	1,800	$	(211	)

See Note 9 to Financial Statements for further detail of long-term debt and other financing arrangements.

Interest rate swaps related to $1.85 billion principal amount of debt were dedesignated as fair value hedges in January 2007. Offsetting swap positions were entered into, and both the original swaps and offsetting positions are subsequently being marked-to-market in net income.

Credit Facilities/Commercial Paper— At July 31, 2007, subsidiaries of TXU Corp. had access to credit facilities totaling $6.5 billion of which $2.7 billion was unused. See Note 8 to Financial Statements for details of the arrangements. Availability under these facilities at June 30, 2007 declined $2.4 billion from year-end 2006 primarily due to incremental credit support requirements related largely to the long-term hedging program, capital expenditures and borrowings to repay all outstanding commercial paper as it matured due to the effects of rating agency actions on the commercial paper program (see discussion below under "Credit Ratings"). Commercial paper maturities totaled $1.3 billion in the first six months of 2007.

Short-term Borrowings — At July 31, 2007, subsidiaries of TXU Corp. had $2.6 billion of outstanding bank borrowings under credit facilities and no outstanding commercial paper. The bank borrowings fund short-term liquidity requirements.

Pension Plan Funding — TXU Corp. expects to make required contributions to its pension plan of $1 million in 2007 and $161 million in 2008.

Income Tax Payments — Such payments totaled $214 million and $18 million in the first six months of 2007 and 2006, respectively. TXU Corp. cannot reasonably estimate the ultimate timing of tax payments associated with uncertain tax positions, but none are expected in the next 12 months.

Common Stock Repurchases— TXU Corp. has board of directors’ authority to repurchase up to 23 million shares of TXU Corp. common stock through the end of 2007. 198 thousand shares have been repurchased under this authority in 2007. The Merger Agreement prohibits TXU Corp. from repurchasing shares of its common stock without the prior written consent of the Sponsors, and TXU Corp. has no intent to repurchase a significant number of shares prior to closing of the Proposed Merger.

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 totaled $527 million and $627 million at June 30, 2007 and December 31, 2006, respectively. See Note 7 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— Risk management and trading transactions typically require collateral to support potential future payment obligations. In particular, commodity transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument is out-of-the-money to such counterparty. TXU Corp. and its subsidiaries typically use cash and letters of credit to satisfy such collateral obligations. In addition, TXU Corp. and its subsidiaries continuously explore the use of other forms of collateral to maximize liquidity. For example, given the scale of TXU Corp.’s long-term hedging program, certain hedging transactions are supported with a first-lien security interest in the assets of TXU Big Brown Company LP consisting of two existing lignite/coal-fueled generation units (Big Brown Lien) as well as a guarantee from Texas Competitive Holdings. The Big Brown Lien can support hedging transactions for up to an aggregate of 1.2 billion MMBtu of natural gas. As of July 31, 2007, approximately half of the long-term hedging program position was supported with cash and letter of credit collateral while the other half was supported by the Big Brown Lien.

As of July 31, 2007, subsidiaries of TXU Corp. have received or posted cash and letters of credit for risk management and trading activities as follows:

$459 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $672 million received as of December 31, 2006;

$102 million in cash has been posted with counterparties for over-the-counter and other non-exchanged cleared transactions, as compared to $2 million received as of December 31, 2006; and

$499 million in letters of credit have been posted with counterparties, as compared to $455 million posted as of December 31, 2006.

With respect to exchange cleared transactions, these transactions typically require initial margin (i.e. the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e. the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is used by TXU Corp. and its subsidiaries for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities. Such counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing TXU Corp.’s liquidity.

As a result of the long-term hedging program, any increase in natural gas prices results in increased cash and letter of credit margin requirements for TXU Corp. and its subsidiaries. Significant increases in cash and letter of credit margin requirements, whether resulting from initial margin or variation margin requirements or otherwise, could have a material adverse impact on TXU Corp.’s liquidity. As representative example, as of July 31, 2007, for each $1.00 per MMBtu increase in natural gas prices, TXU Corp.’s liquidity could have been reduced by approximately $1.2 billion as a result of cash and letter of credit variation margin posting requirements associated with the long-term hedging program.

On August 6, 2007, Texas Competitive Holdings received a commitment from a financial institution for an uncapped liquidity facility that is intended to cover all of the cash and letter of credit posting requirements for a significant portion (approximately 850 million MMBtu) of the long-term hedging program position that requires cash or letter of credit margin postings. If this liquidity facility was in place on July 31, 2007 and a $1.00 per MMBtu increase in natural gas prices were to occur on that date as discussed above, then approximately $850 million of the $1.2 billion liquidity requirement would have come from this liquidity facility as opposed to existing credit facilities and cash from operations. Texas Competitive Holdings expects to have this liquidity facility finalized and available by the end of the third quarter, but there can be no guarantee that a definitive agreement will be executed by that time (if at all) or with the terms currently set forth in the commitment.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions

Financial Covenants

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 June 30, 2007, TXU Corp.’s subsidiaries were in compliance with all such applicable covenants.

Credit Ratings

Credit ratings for TXU Corp. and certain of its subsidiaries as of June 30, 2007 are presented below:


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

All the Fitch ratings reflect a one-notch downgrade in late February 2007 as a result of the announcement of the Proposed Merger. Fitch also placed all of these ratings on Rating Watch Negative. The S&P ratings for TXU Corp., US Holdings and Texas Competitive Holdings reflect a two-notch downgrade in early March 2007 also as a result of the announcement of the Proposed Merger. Further, due to the announcement of the Proposed Merger, S&P has placed all these ratings on CreditWatch negative and Moody’s has placed all these ratings on review for possible downgrade.

Oncor Electric Delivery’s senior unsecured debt is currently rated as investment grade by all of the rating agencies. Moody’s, S&P’s and Fitch’s rating of TXU Corp.’s senior unsecured debt, S&P’s and Fitch’s rating of US Holdings’ senior unsecured debt and S&P’s rating of Texas Competitive Holdings’ senior unsecured debt are below investment grade.

In late February 2007, Fitch downgraded the rating on commercial paper issued by Texas Competitive Holdings and Oncor Electric Delivery by one-notch to F3.

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 Corp. and Texas Competitive Holdings previously guaranteed the obligations under the lease agreement for TXU Corp.’s current headquarters building. As a result of the March 2007 downgrade by S&P of Texas Competitive Holdings’ credit rating to below investment grade, Texas Competitive Holdings has provided a $144 million letter of credit to replace TXU Corp.'s and its guarantees of these obligations. As a result of providing the letter of credit, this agreement no longer contains a material credit rating covenant.

The lessor under an operating lease for certain rail cars has notified Texas Competitive Holdings that it intends to exercise a termination right that has been triggered under the lease as a result of the S&P downgrade of Texas Competitive Holdings’ credit rating to below investment grade. Such termination will result in Texas Competitive Holdings being required to pay approximately $50 million to purchase the rail cars, which represents the remaining lease payments under the lease (principal as of June 30, 2007). In addition, the lease requires that Texas Competitive Holdings pay a make-whole amount upon termination of the lease. Texas Competitive Holdings currently expects that the make-whole payment will be approximately $10 million, although the actual amount paid will depend on prevailing interest rates at the time the lease is terminated. Texas Competitive Holdings intends to fund the approximately $50 million of remaining lease payments by refinancing the rail cars during the third quarter of 2007 with the make-whole payment being primarily funded from internal sources.

Texas Competitive Holdings has entered into certain retail and wholesale commodity contracts that in some instances give the other party the right, but not the obligation, to request Texas Competitive Holdings to post collateral in the event that its credit rating falls below investment grade. On March 2, 2007, S&P downgraded Texas Competitive Holdings’ credit rating to two notches below investment grade. Based on its commodity contract positions at June 30, 2007, should Texas Competitive Holdings’ credit rating be downgraded to below investment grade by one of the other rating agencies, counterparties would have the option to request Texas Competitive Holdings to post up to $122 million in additional collateral support. The amount Texas Competitive Holdings could be required to post under these transactions depends in part on the value of the contracts at the time of any such additional downgrade.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of the downgrade of Texas Competitive Holdings’ credit rating to below investment grade, Texas Competitive Holdings is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. Based on requests to post collateral support from utilities that have been received by Texas Competitive Holdings and its subsidiaries as of June 30, 2007, Texas Competitive Holdings has posted collateral support to the applicable utilities in an aggregate amount equal to $25 million, with $16 million of this amount posted for the benefit of Oncor Electric Delivery.

The Commission has rules in place to assure adequate credit worthiness of any REP. Under these rules, as a result of the downgrade of Texas Competitive Holdings’ credit rating to below investment grade by S&P, Texas Competitive Holdings has agreed to maintain at all times availability under its credit facilities an amount no less than the aggregate amount of customer deposits and any advanced payments received from customers. As of June 30, 2007, the amount of customer deposits received from customers held by Texas Competitive Holdings’ REP subsidiaries totaled approximately $125 million.

ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, as a result of the downgrade of Texas Competitive Holdings’ credit rating to below investment grade, Texas Competitive Holdings posted additional collateral support of $34 million on March 7, 2007, which is subject to periodic adjustments.

Other arrangements of TXU Corp. and its subsidiaries, including credit facilities, the $1.8 billion floating rate senior notes due in 2008, the sale of receivables program 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 Texas Competitive Holdings or Oncor 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 Texas Competitive Holdings or any subsidiary thereof may cause the maturity of outstanding balances ($2.2 billion at June 30, 2007) under such facility to be accelerated as to Texas Competitive Holdings but not as to Oncor Electric Delivery. Also, under these credit facilities, a default by Oncor Electric Delivery or any subsidiary thereof may cause the maturity of outstanding balances ($155 million as of June 30, 2007) under such facility to be accelerated as to Oncor Electric Delivery but not as to Texas Competitive Holdings.

In addition, a default by Texas Competitive Holdings or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross-default under its 364-day credit facility totaling $1.5 billion and may cause the maturity of outstanding balances (none as of June 30, 2007) under such facility to be accelerated.

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

TXU 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.

Each of TXU DevCo’s commodity hedging agreements contains a cross default provision. In the event of a default by TXU DevCo or its subsidiaries relating to certain obligations of TXU DevCo or its subsidiaries in an amount equal to or greater than $50 million with respect to one of the agreements (with such amount increasing to $100 million at December 31, 2007) or $100 million with respect to the other agreements, the applicable hedge counterparties may terminate the applicable transactions covered by the applicable hedging agreements and require all outstanding obligations thereunder to be settled. Texas Competitive Holdings has guaranteed these obligations, and they are secured by a lien on the two lignite/coal-fueled generation units at its Big Brown plant.

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

Guarantees — See discussion above under “Material Credit Rating Covenants” related to a TXU Corp. lease obligation with a credit rating provision.

Also see Note 10 to Financial Statements for details of guarantees.

OFF BALANCE SHEET ARRANGEMENTS

TXU Corp. has established an accounts receivable securitization program. See discussion above under “Sale of Receivables” and in Note 7 to Financial Statements.

Also see Note 10 to Financial Statements regarding guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 10 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Notes 1 and 3 to Financial Statements for a discussion of changes in accounting standards.

REGULATION AND RATES

Regulatory Investigations — See Note 10 to Financial Statements for discussion.

2007 Texas Legislative Session

The Texas Legislature convened in its regular biennial session on January 9, 2007 and adjourned on May 28, 2007. The session was not a “sunset” session for the Commission, so there was no requirement that the Legislature consider any electric industry-related bills. However, various measures pertaining to the electric industry were considered. The primary measures that were under consideration and would have materially affected TXU Corp.’s businesses and potentially the Proposed Merger were ultimately not enacted.

Report Filed with the Commission Regarding Proposed Merger

In April 2007, Oncor Electric Delivery and TEF (together, the Applicants) filed a Joint Report and Application (Report) with the Commission pursuant to Section 14.101(b) of PURA and Commission SUBST. R.25.75. Immediately following the Proposed Merger, TEF will own all or substantially all of the outstanding shares of TXU Corp., and Oncor Electric Delivery will remain a direct or indirect wholly-owned subsidiary of TXU Corp. This report contained commitments that would take effect upon the closing of the Proposed Merger. Such commitments include: maintenance of specified Oncor Electric Delivery debt-to-equity ratios, minimum Oncor Electric Delivery capital expenditure levels, increased demand-side management energy efficiency programs spending, minimum five year continued majority ownership by the Sponsors and that Oncor Electric Delivery will not incur any indebtedness and will not guarantee or use its assets to secure any affiliate indebtedness incurred to finance the Proposed Merger.

Section 14.101(b) of PURA requires that a transaction involving the sale of more than 50% of the stock of a public utility be reported to the Commission within a reasonable time subsequent to consummation of the transaction and that the Commission shall determine whether the transaction is consistent with the public interest standards set out therein. Although the Proposed Merger does not involve the direct sale of public utility stock, the Applicants filed the Report pursuant to Section 14.101(b) of PURA as it relates to Oncor Electric Delivery. A procedural schedule has been adopted, with the Hearing on the Merits currently scheduled for October 9-12, 2007.

The Report is available to the public at the Commission’s website (http://www.puc.state.tx.us/), Docket No. 34077. None of the information on the Commission website shall be deemed a part of, or incorporated by reference into, this quarterly report on Form 10-Q.

Commission Request for Oncor Electric Delivery Rate Filing

At the request of the Commission, the Commission Staff filed a petition in March 2007 requesting that the Commission order Oncor Electric Delivery to file a rate case based on a test year ending December 31, 2006. Commission Staff stated that it would be advantageous to review Oncor Electric Delivery’s costs prior to major ownership and organizational changes that TXU Corp. has announced in order to establish a baseline from which to assess any cost changes resulting from the announced changes. On April 30, 2007, the Commission issued an order requiring Oncor Electric Delivery to file a rate case based on a test year ending December 31, 2006. Oncor Electric Delivery is required to file the rate case within 120 days from the date that Oncor Electric Delivery receives notice of the order. Due to the previously disclosed 2006 Cities rate settlement, the 2006 test year rate case is not expected to apply to distribution rates in the Cities retaining original jurisdiction. The original jurisdiction Cities account for approximately 82% of Oncor Electric Delivery’s electricity distribution revenues. The rate case would also apply to Oncor Electric Delivery’s transmission rates; therefore, Oncor Electric Delivery estimates that approximately one-third of its operating revenues are subject to change in this rate proceeding. On July 24, 2007, Oncor filed a motion asking the Commission to extend the time for filing a rate filing package to July 1, 2008, to modify the test year to a 2007 calendar year and to consider the motion by the August 16, 2007 open meeting. Oncor Electric Delivery cannot predict whether the Commission will rule favorably on the motion. Oncor Electric Delivery cannot predict the outcome of any rate case.

Transmission Rates

In order to recover increased affiliate and third-party transmission costs from REPs, Oncor Electric Delivery is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rate charged to REPs. In January 2007, an application was filed to increase the TCRF, which was administratively approved on February 22, 2007 and became effective March 1, 2007. This increase is expected to increase annualized revenues by $14 million. In July 2007, an application was filed to increase the TCRF, which is expected to be administratively approved in August 2007 and become effective September 1, 2007. This increase is expected to increase annualized revenues by $26 million and includes the $15 million of the wholesale transmission rate increase which is recoverable from REPs as described below.

In February 2007, Oncor Electric Delivery filed an application for an interim update of its wholesale transmission rate. The application was approved by the Commission in April 2007 and the new rate went into effect immediately. Annualized revenues are expected to increase by approximately $38 million. Approximately $23 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $15 million is recoverable from REPs through the TCRF component of Oncor Electric Delivery’s delivery rates charged to REPs.

Competitive Renewable Energy Zones

In the first quarter of 2007, the Commission initiated a docket to identify the transmission facilities necessary to interconnect future renewable energy generating facilities. As part of the docket, the Commission considered which zones would contain the best renewable energy sources. On July 20, 2007, the Commission voted to designate zones with generation potential of over 20,000 MW.

The Commission also opened a project to evaluate potential transmission service providers that are interested in constructing the designated transmission facilities. In connection with this project, Oncor Electric Delivery indicated to the Commission its interest in constructing any designated transmission facilities, particularly those within its traditional service territory and those that interconnect with Oncor Electric Delivery's transmission facilities.

The Commission has not yet determined the desired capacity for any of the designated zones, the designated transmission facilities, or the transmission service providers that will construct the facilities. As such, Oncor Electric Delivery cannot predict the amount of transmission facilities in competitive renewable energy zones, if any, that it will construct.

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.

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 operation manages the commodity price, counterparty credit and operational risk related to 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 defined 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. 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.

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.

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 and power 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 operation 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 and settlement of energy has occurred, counterparties have fulfilled their financial commitments and related contracts have either matured or are settled. 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 "Recent Developments" for an update of the program, including potential effects on reported results.

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.

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.

Trading VaR— This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five to 60 days.

	Six Months Ended		Year Ended
	June 30, 2007		December 31, 2006
Month-end average Trading VaR:	$	9	$	12
Month-end high Trading VaR:	$	11	$	30
Month-end low Trading VaR:	$	6	$	5

VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting— This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.

	Six Months Ended		Year Ended
	June 30, 2007		December 31, 2006
Month-end average MtM VaR:	$	714	$	149
Month-end high MtM VaR:	$	1,013	$	391
Month-end low MtM VaR:	$	322	$	5

Earnings at Risk (EaR) — This measurement estimates the potential reduction of fair value of expected pretax earnings for the years presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). For this purpose, cash flow hedges are also included with transactions that are not marked-to-market in net income. A 95% confidence level and a five to 60 day holding period is assumed in determining EaR.

	Six Months Ended		Year Ended
	June 30, 2007		December 31, 2006
Month-end average EaR:	$	707	$	156
Month-end high EaR:	$	991	$	387
Month-end low EaR:	$	318	$	21

The increases in the risk measures (MtM VaR and EaR) above are driven by the dedesignation of positions in the long-term hedging program as cash flow hedges for accounting purposes as well as the increase in number of positions in the program.

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 analyzed 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. 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— TXU Corp.’s gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $2.0 billion at June 30, 2007.

Gross assets subject to credit risk as of June 30, 2007 include $532 million in accounts receivable from the retail sale of electricity to residential and small business customers. The risk of material loss (after consideration of bad debt 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 credit exposure is with large business retail customers and wholesale counterparties. These counterparties include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of June 30, 2007, 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 $23 million in credit collateral (cash, letters of credit and other security interests) held by TXU Corp. subsidiaries.

Of this $1.3 billion net exposure, 77% 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, Oncor Electric Delivery has exposure to credit risk totaling $233 million at June 30, 2007 arising from potential nonperformance by nonaffiliated REPs. This exposure consists almost entirely of noninvestment grade trade accounts receivable.

The following table presents the distribution of credit exposure as of June 30, 2007, for retail trade accounts receivable from large business customers, wholesale trade accounts receivable as well as net asset positions arising from hedging and trading activities, by investment grade and noninvestment grade, credit quality and maturity.

										Net Exposure byMaturity
	Exposure before Credit Collateral			Credit Collateral			Net Exposure			2 years or less		Between 2-5 years		Greater than 5 years		Total


Investment grade	$	1,004		$	16		$	988		$	596	$	140	$	252	$	988
Noninvestment grade		301			7			294			168		72		54		294
Totals	$	1,305		$	23		$	1,282		$	764	$	212	$	306	$	1,282

Investment grade		77	%		70	%		77	%
Noninvestment grade		23	%		30	%		23	%

Approximately 60% 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 each having an exposure greater than 10% of the net $1.3 billion credit exposure. These two counterparties represented 16% and 13%, respectively, of the net exposure. TXU Corp. views exposure to these two counterparties to be within an acceptable level of risk tolerance as they are rated investment grade.

TXU Corp.’s subsidiaries are exposed to credit risk related to its long-term hedging program. Of the transactions in the program, over 98% of the volumes are with counterparties with an A credit rating or better, and 99% are at least investment grade.

Additionally, under the long-term hedging program, TXU Corp. has potential credit risk exposure concentration related to a limited number of counterparties. The hedge transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of significant declines in natural gas prices and a material downgrade in the credit rating of the counterparties. TXU Corp. views the potential concentration of risk with these counterparties to be within an acceptable risk tolerance due to the strong financial profile of the counterparties and their respective A or above credit rating.

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 Texas Competitive Holdings and Oncor 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.

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, consummation of the Proposed Merger, 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, the US Congress, 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, including climate change initiatives;

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;

TXU Corp.’s ability to profitably serve its customers given the announced price protection and price cuts;

restrictions on competitive retail pricing;

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;

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;

changes in assumptions used to estimate future executive compensation payments;

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 for the program and the ability to satisfactorily resolve issues relating to any appeal to the final judgement issued with respect 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, the ability of TXU Corp. and its contractors to attract and retain, at projected rates, skilled labor for constructing the new generating units, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, supplier performance risk, 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 Proposed Merger: the occurrence of any event, change or other circumstances, including the enactment of any new applicable legislation, that could give rise to the termination of the Merger Agreement or the Proposed Merger; the outcome of any legal proceedings that may be instituted against TXU Corp. and others related to the Merger Agreement; failure to obtain shareholder approval or any other failure to satisfy other conditions required to complete the Proposed Merger, including required regulatory approvals; risks that the proposed transaction disrupts current plans and operations and the potential difficulties in employee retention as a result of the Proposed Merger; the amount of the costs, fees, expenses and charges related to the Proposed Merger and the execution of certain financings that will be obtained to consummate the Proposed Merger; and the impact of the substantial indebtedness incurred to finance the consummation of the Proposed Merger.

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.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS.

Reference is made to the discussion in Note 10 regarding legal proceedings.

Item 1A. RISK FACTORS.

Other than the 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 2006 Form 10-K as updated by the risk factors disclosed under the heading “Risk Factors” in Item 1A of the report on Form 10-Q for the quarterly period ended March 31, 2007 (“March 2007 10-Q”), except for information disclosed elsewhere in this Form 10-Q that provides factual updates to risk factors contained in the 2006 Form 10-K and March 2007 10-Q. The risk factors below update, and should be read in conjunction with, the risk factors disclosed in the 2006 Form 10-K and March 2007 10-Q.

Risks Relating to TXU Corp.’s Businesses

The liquidity needs of TXU Corp. and its subsidiaries could be difficult to satisfy under some circumstances, particularly during times of uncertainty in the financial markets and/or during times when there are significant increases in natural gas prices. The inability to access liquidity, particularly on favorable terms, could materially adversely affect TXU Corp.’s results of operations and/or financial condition.

TXU Corp.’s businesses are capital intensive. For example, TXU Corp. and its subsidiaries expect to make approximately $4.6 billion of capital expenditures for the period July 2007 through December 2008. TXU Corp. and its subsidiaries rely on access to financial markets as a significant source of liquidity for capital requirements not satisfied by cash on hand or operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty in the financial markets similar to that which is currently being experienced in the financial markets, could impact the ability of TXU Corp. and its subsidiaries to sustain and grow their businesses and would likely increase capital costs. TXU Corp.’s access to the financial markets could be adversely impacted by various factors, such as:

the announcement of the Proposed Merger;

changes in financial markets that reduce available credit or the ability to obtain or renew liquidity facilities on acceptable terms;

changes in interest rates;

a deterioration of TXU Corp.’s credit or the credit of its subsidiaries or a reduction in TXU Corp.’s credit ratings or the credit ratings of its subsidiaries;

volatility in commodity prices that increases margin or credit requirements;

a material breakdown in TXU Corp.’s risk management procedures; and

a material adverse change in one or more of TXU Corp.’s businesses that restricts access to liquidity facilities.

In addition, given the size of TXU Corp.’s long-term hedging program, any significant increase in the price of natural gas could result in subsidiaries of TXU Corp. being required to provide cash or letter of credit collateral (i.e. margin) in very large amounts. As of July 31, 2007, for each $1.00 per MMBtu increase in natural gas prices, TXU Corp.’s liquidity could be reduced by approximately $1.2 billion as a result of margin requirements associated with the long-term hedging program. While Texas Competitive Holdings has obtained a commitment from a financial institution for an uncapped liquidity facility that would support a significant amount of the variation margin requirements associated with the long-term hedging program, there can be no assurance that a definitive agreement will ultimately be executed. In addition, any perceived reduction in TXU Corp.’s or a subsidiary's credit quality could result in clearing agents or other counterparties requesting additional margin. In the event TXU Corp.’s liquidity facilities are being used largely to support its long-term hedging program as a result of a significant increase in the price of natural gas or significant reduction in credit quality, TXU Corp. and its subsidiaries may have to forego certain capital expenditures or other investments in their businesses or other business opportunities.

Further, a lack of available liquidity could adversely impact the evaluation of TXU Corp.’s and its subsidiaries’ creditworthiness by counterparties and rating agencies. In particular, such concerns by existing and potential counterparties could significantly limit Texas Competitive Holdings' wholesale markets activities, including its long-term hedging program.

Risks Relating to the Proposed Merger

TXU Corp. cannot guarantee that the Proposed Merger will be consummated. Any failure to consummate the Proposed Merger could have a material adverse impact on TXU Corp.’s results of operations, financial condition and stock price.

Consummation of the Proposed Merger is subject to the satisfaction of various closing conditions that have not yet been satisfied, including approval of the merger by a vote of two-thirds of the outstanding shares of TXU Corp. common stock, approval of the FERC and the NRC and other customary closing conditions described in the Merger Agreement. As a result, TXU Corp. cannot guarantee that the Proposed Merger will be consummated. In the event that the Proposed Merger is not consummated:

management’s attention from TXU Corp.’s day-to-day business may be diverted;

TXU Corp. may lose key employees;

TXU Corp.’s relationships with customers and vendors may be disrupted as a result of uncertainties with regard to its business and prospects;

TXU Corp. may be required to pay significant transaction costs related to the Proposed Merger, such as a transaction termination (break-up) fee of up to $1.0 billion; and

the market price of shares of TXU Corp. common stock may decline to the extent that the current market price of those shares reflects a market assumption that the Proposed Merger will be completed.

In addition, failure by the lenders, as a result of dislocations in the credit markets or for any other reason, to meet their commitments in connection with the Sponsors’ financing for the Proposed Merger could cause the Sponsors to breach their obligation to consummate the Proposed Merger once all of the closing conditions have been satisfied. TXU Corp.’s claims against the Sponsors in the event of such a breach would be limited to $1 billion and, while there is no limit to TXU Corp.’s potential claims against such lenders, any claim against such lenders as well as the Sponsors may not be successful and would likely result in litigation that would take several years to pursue.

Any such events could have a material negative impact on TXU Corp.’s results of operations and financial condition and could adversely affect TXU Corp.’s stock price.

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)

April 1, 2007 – April 30, 2007

152,836

63.95

152,836

─

May 1, 2007 – May 31, 2007

─

June 1, 2007 – June 30, 2007

─

Total as of June 30, 2007

152,836

63.95

152,836

23,296,153

________________

(a)

From July 1, 2007 to July 24, 2007, TXU Corp. purchased an additional 45 thousand shares at an average price of $67.70 per share. All of these share purchases were under TXU Corp.’s board of directors’ authority to repurchase up to 23 million shares of TXU Corp. common stock through the end of 2007. At July 24, 2007, the maximum number of shares that can yet be repurchased under the two Board authorizations is approximately 23 million shares. The Merger Agreement prohibits TXU Corp. from repurchasing shares of its common stock without the prior written consent of the Sponsors, and TXU Corp. has no intent to repurchase a significant number of shares prior to closing of the Proposed Merger.

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

None.

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.
10.1			―	First Amendment to Lease Agreement, dated as of June 1, 2007, between U.S. Bank, N.A. (as successor-in-interest to State Street Bank and Trust Company of Connecticut, National Association), as owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as Lessor, and TXU Properties Company, a Texas corporation, as Lessee (Energy Plaza Property)
10.2			―	Amended and Restated Engineering, Procurement and Construction Agreement, dated as of June 8, 2007, between Oak Grove Management Company LLC, a Delaware limited liability company and a wholly-owned, direct subsidiary of Texas Competitive Holdings Company LLC, and Fluor Enterprises, Inc., a California corporation (confidential treatment has been requested for portions of this exhibit)

Exhibits	Previously Filed With File Number*	As Exhibit
(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 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.
(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 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 June 30, 2007.

________________

* Incorporated here by reference.

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
	Name:	Stan Szlauderbach
	Title:	Senior Vice President and Controller

Date: August 9, 2007

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Energy Future (TXU) Inactive 10-Q2007 Q2 Quarterly report

Content analysis