Energy Future (TXU) 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2009

— OR —

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

Commission File Number 1-12833

Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

Texas	75-2669310
(State of incorporation)	(I.R.S. Employer Identification No.)
1601 Bryan Street, Dallas, TX 75201-3411	(214) 812-4600
(Address of principal executive offices) (Zip Code)	(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨ (The registrant is not currently required to submit such files.)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨                Accelerated filer  ¨                Non-Accelerated filer  x                Smaller reporting company  ¨

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

As of July 31, 2009, there were 1,666,417,409 shares of common stock outstanding, without par value, of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.’s parent holding company, and none of which is publicly traded).

TABLE OF CONTENTS
		PAGE
GLOSSARY		ii
PART I. FINANCIALINFORMATION
Item 1.	Financial Statements
	Condensed Statements of Consolidated Income (Loss) – Three and Six Months Ended June 30, 2009 and 2008	1
	Condensed Statements of Consolidated Comprehensive Income (Loss) – Three and Six Months Ended June 30, 2009 and 2008	2
	Condensed Statements of Consolidated Cash Flows – Six Months Ended June 30, 2009 and 2008	3
	Condensed Consolidated Balance Sheets – June 30, 2009 and December 31, 2008	4
	Notes to Condensed Consolidated Financial Statements	5
	Report of Independent Registered Public Accounting Firm	51
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	91
Item 4.	Controls and Procedures	97
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	97
Item 1A.	Risk Factors	97
Item 4.	Submission of Matters to a Vote of Security Holders	97
Item 6.	Exhibits	98
SIGNATURE		99

Energy Future Holdings Corp.’s (EFH Corp.) 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 EFH Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on EFH Corp.’s website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-Q. Readers should not rely on or assume the accuracy of any representation or warranty in any agreement that EFH Corp. has filed as an exhibit to this Form 10-Q because such representation or warranty may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties’ risk allocation in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes or may no longer continue to be true as of any given date.

This Form 10-Q and other Securities and Exchange Commission filings of EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or “we,” “our,” “us” or “the company”), EFC Holdings, Intermediate Holding, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor 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 any other affiliate.

i

GLOSSARY

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

2008 Form 10-K	EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2008 as recast in a Current Report on Form 8-K filed on May 20, 2009 to reflect the adoption of SFAS 160
Adjusted EBITDA	Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-Q (see reconciliation in Exhibit 99(b) and 99(c)) solely because of the important role that Adjusted EBITDA plays in respect of the certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
Competitive Electric segment	Refers to the EFH Corp. business segment that consists principally of TCEH.
CREZ	Competitive Renewable Energy Zones
DOE	US Department of Energy
EBITDA	Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.
EFC Holdings	Refers to Energy Future Competitive Holdings Company, a direct subsidiary of EFH Corp. and the direct parent of TCEH.
EFH Corp.	Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor.
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

ii

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 46(R)	FIN No. 46 (Revised 2003), “Consolidation of Variable Interest Entities”
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
FSP	FASB Staff Position
FSP SFAS 107-1 and APB 28-1	FSP SFAS No. 107-1 and Accounting Principles Board Opinion No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments”
FSP SFAS 115-2 and SFAS 124-2	FSP SFAS No. 115-2 and SFAS No. 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”
FSP SFAS 132(R)-1	FSP SFAS No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
FSP SFAS 157-4	FSP SFAS No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
GAAP	generally accepted accounting principles
GWh	gigawatt-hours
Intermediate Holding	Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.
IRS	US Internal Revenue Service
kWh	kilowatt-hours
LIBOR	London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.
Luminant	Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
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	The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.
Merger Agreement	Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.

iii

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	Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.
Oncor Holdings	Refers to Oncor Electric Delivery Holdings Company LLC, a direct wholly-owned subsidiary, consolidated as a variable interest entity under FIN 46(R), of Intermediate Holding and the direct majority owner of Oncor.
Oncor Ring-Fenced Entities	Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
Purchase accounting	The purchase method of accounting for a business combination as prescribed by SFAS No. 141, “Business Combinations,” whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
Regulated Delivery segment	Refers to the EFH Corp. business segment, the substantial majority of which consists of the activities of Oncor.
REP	retail electric provider
RRC	Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
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 123(R)	SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 132(R)	SFAS No. 132 (revised 2003), “Employers’ Disclosures About Pensions and Other Postretirement Benefits”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement No. 125”

iv

SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51”
SFAS 161	SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”
SFAS 165	SFAS No. 165, “Subsequent Events”
SFAS 166	SFAS No. 166, “Accounting for Transfers of Financial Assets, an Amendment of FASB Statement No. 140”
SFAS 167	SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”
SFAS 168	SFAS No. 168, “TheFASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles”
SG&A	selling, general and administrative
Sponsor Group	Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.)
TCEH	Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFC Holdings and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that is engaged in electricity generation, wholesale and retail energy markets and development and construction activities. Its major subsidiaries include Luminant and TXU Energy.
TCEH Finance	Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.
TCEH Senior Secured Facilities	Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 4 to Financial Statements for details of these facilities.
TCEQ	Texas Commission on Environmental Quality
Texas Holdings	Refers to Texas Energy Future Holdings Limited Partnership, a Delaware limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.
Texas Holdings Group	Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.
Texas Transmission	Refers to Texas Transmission Investment LLC, a Delaware limited liability company that purchased a 19.75% equity interest in Oncor in November 2008. It is not affiliated with EFH Corp., any of its subs or any member of the Sponsor Group.
TXU Energy	Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.
TXU Gas	TXU Gas Company, a former subsidiary of EFH Corp.
US	United States of America

v

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues	$	2,342		$	2,951		$	4,481		$	5,305
Fuel, purchased power costs and delivery fees		(700	)		(1,416	)		(1,301	)		(2,237	)
Net gain (loss) from commodity hedging and trading activities		(248	)		(4,727	)		880			(6,293	)
Operating costs		(395	)		(390	)		(783	)		(748	)
Depreciation and amortization		(423	)		(390	)		(830	)		(785	)
Selling, general and administrative expenses		(270	)		(247	)		(516	)		(464	)
Franchise and revenue-based taxes		(79	)		(81	)		(165	)		(167	)
Impairment of goodwill (Note 2)		—			—			(90	)		—
Other income (Note 13)		13			15			26			29
Other deductions (Note 13)		(7	)		(26	)		(18	)		(42	)
Interest income		11			8			12			13
Interest expense and related charges (Note 13)		(431	)		(831	)		(1,096	)		(1,674	)
Income (loss) before income taxes		(187	)		(5,134	)		600			(7,063	)
Income tax (expense) benefit		48			1,803			(285	)		2,463
Net income (loss)		(139	)		(3,331	)		315			(4,600	)
Net income attributable to noncontrolling interests		(16	)		—			(28	)		—
Net income (loss) attributable to EFH Corp.	$	(155	)	$	(3,331	)	$	287		$	(4,600	)

See Notes to Financial Statements.

1

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income (loss)	$	(139	)	$	(3,331	)	$	315		$	(4,600	)
Other comprehensive income (loss), net of tax effects:
Reclassification of pension and other retirement benefit costs (net of tax expense of $— in all periods)		—			1			—			1
Cash flow hedges:
Net increase (decrease) in fair value of derivatives (net of tax (expense) benefit of $—, $(208), $9 and $23)		1			385			(16	)		(43	)
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $17, $13, $32 and $23)		32			24			58			42
Total effect of cash flow hedges		33			409			42			(1	)
Total adjustments to net income (loss)		33			410			42			—
Comprehensive income (loss) operations		(106	)		(2,921	)		357			(4,600	)
Comprehensive income attributable to noncontrolling interests		(16	)		—			(28	)		—
Comprehensive income (loss) attributable to EFH Corp.	$	(122	)	$	(2,921	)	$	329		$	(4,600	)

See Notes to Financial Statements.

2

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(millions of dollars)

	Six Months Ended June 30,
	2009			2008
Cash flows – operating activities:
Net income (loss)	$	315		$	(4,600	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization		1,129			1,037
Deferred income tax expense (benefit)		223			(2,533	)
Impairment of goodwill (Note 2)		90			—
Unrealized net (gains) losses from mark-to-market valuations of commodity positions		(710	)		6,363
Unrealized net gains from mark-to-market valuations of interest rate swaps		(665	)		—
Bad debt expense		41			34
Stock-based incentive compensation expense		12			10
Other – net		(3	)		1
Changes in operating assets and liabilities:
Margin deposits – net		98			(2,003	)
Deferred advanced metering system revenues (Note 13)		37			—
Other operating assets and liabilities		(63	)		(209	)
Cash provided by (used in) operating activities		504			(1,900	)
Cash flows – financing activities:
Issuances of long-term debt/securities
Pollution control revenue bonds		—			242
Other long-term debt (Note 4)		435			762
Common stock		—			34
Repayments/repurchases of long-term debt/securities:
Pollution control revenue bonds		—			(242	)
Other long-term debt (Note 4)		(228	)		(363	)
Common stock		—			(1	)
Increase in short-term borrowings (Note 4)		205			3,015
Contributions from noncontrolling interests		32			—
Distributions paid to noncontrolling interests		(17	)		—
Debt discount, financing and reacquisition expenses		(4	)		(6	)
Other – net		21			22
Cash provided by financing activities		444			3,463
Cash flows – investing activities:
Capital expenditures		(1,256	)		(1,480	)
Nuclear fuel purchases		(87	)		(84	)
Redemption of investment held in money market fund		142			—
Investment posted with counterparty (Note 4)		(400	)		—
Reduction of restricted cash related to pollution control revenue bonds		—			29
Reduction of restricted cash related to letter of credit facility (Note 4)		115			—
Transfer of cash collateral to custodian account		3			(179	)
Other changes in restricted cash		11			8
Proceeds from sale of assets		1			46
Proceeds from sale of environmental allowances and credits		7			28
Purchases of environmental allowances and credits		(14	)		(17	)
Proceeds from sales of nuclear decommissioning trust fund securities		2,231			475
Investments in nuclear decommissioning trust fund securities		(2,238	)		(482	)
Cost to remove retired property		(21	)		(17	)
Other		28			19
Cash used in investing activities		(1,478	)		(1,654	)
Net change in cash and cash equivalents		(530	)		(91	)
Cash and cash equivalents – beginning balance		1,689			281
Cash and cash equivalents – ending balance	$	1,159		$	190

See Notes to Financial Statements.

3

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)

	June 30, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	1,159		$	1,689
Investment posted with counterparty (Note 4)		400			—
Investments held in money market fund		—			142
Restricted cash (Note 13)		43			55
Trade accounts receivable – net (Note 3)		1,169			1,219
Income taxes receivable – net		—			42
Inventories		453			426
Commodity and other derivative contractual assets (Note 7)		3,198			2,534
Accumulated deferred income taxes		122			44
Margin deposits related to commodity positions		345			439
Other current assets		167			165
Total current assets		7,056			6,755
Restricted cash (Note 13)		1,150			1,267
Investments		647			645
Property, plant and equipment – net		29,929			29,522
Goodwill (Note 2)		14,316			14,386
Intangible assets – net (Note 2)		2,980			2,993
Regulatory assets – net		1,810			1,892
Commodity and other derivative contractual assets (Note 7)		1,219			962
Other noncurrent assets, principally unamortized debt issuance costs		902			841
Total assets	$	60,009		$	59,263
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 4)	$	1,442		$	1,237
Long-term debt due currently (Note 4)		325			385
Trade accounts payable		930			1,143
Commodity and other derivative contractual liabilities (Note 7)		3,167			2,908
Margin deposits related to commodity positions		528			525
Accrued interest		512			524
Other current liabilities		582			612
Total current liabilities		7,486			7,334
Accumulated deferred income taxes		6,131			5,926
Investment tax credits		40			42
Commodity and other derivative contractual liabilities (Note 7)		1,358			2,095
Long-term debt, less amounts due currently (Note 4)		41,406			40,838
Other noncurrent liabilities and deferred credits (Note 13)		5,383			5,205
Total liabilities		61,804			61,440
Commitments and Contingencies (Note 5)
Equity (Note 6):
EFH Corp. shareholders’ equity		(3,193	)		(3,532	)
Noncontrolling interests in subsidiaries		1,398			1,355
Total equity		(1,795	)		(2,177	)
Total liabilities and equity	$	60,009		$	59,263

See Notes to Financial Statements.

4

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFH Corp., a Texas corporation, is a Dallas-based holding company conducting its operations principally through its TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary engaged in regulated electricity transmission and distribution operations in Texas.

References in this report to “we,” “our,” “us” and “the company” are to EFH Corp. and/or its subsidiaries, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.

Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the sale of a 19.75% equity interest in Oncor to Texas Transmission; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor’s board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or other obligations of any member of the Texas Holdings Group. Moreover, Oncor’s operations are conducted, and its cash flows managed, independently from the Texas Holdings Group. Oncor Holdings is consolidated with EFH Corp. as a variable interest entity under FIN 46(R).

We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Note 12 for further information concerning reportable business segments.

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in the 2008 Form 10-K, with the exception of the adoption of SFAS 161 and 165, FSP SFAS 157-4 and FSP SFAS 107-1 and APB 28-1 as discussed below. 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 2008 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. Subsequent events have been evaluated through August 3, 2009, the date these condensed consolidated financial statements were issued.

5

Use of Estimates

Preparation of the financial statements requires 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 fair value measurements. 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.

Changes in Accounting Standards

In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” SFAS 160 is effective for fiscal years beginning on or after December 15, 2008 and requires noncontrolling interests in subsidiaries initially to be measured at fair value and classified as a separate component of equity. Effective January 1, 2009, on a retrospective basis, we classified the noncontrolling interests created as a result of Oncor’s November 2008 sale of equity interests ($1.355 billion as of December 31, 2008) and those created as part of the nuclear generation development joint venture formed in the first quarter of 2009 as a separate component of equity in the balance sheet, and reported consolidated net income (loss) includes the net income attributable to noncontrolling interests.

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement 133.” SFAS 161 enhances required disclosures regarding derivatives and hedging activities to enable investors to better understand their effects on an entity’s financial position, financial performance and cash flows. This statement was effective with reporting for the three months ended March 31, 2009. As SFAS 161 provides only disclosure requirements, the adoption of this standard did not have any effect on reported results of operations or financial condition. The disclosures are provided in Note 7.

In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP amends SFAS 132(R) to provide enhanced disclosures regarding how investment allocation decisions are made and certain aspects of fair value measurements on plan assets. The disclosures required by this FSP are intended to provide transparency related to the types of assets and associated risks in an employer’s defined benefit pension or other postretirement employee benefits plan and events in the economy and markets that could have a significant effect on the value of plan assets. This FSP is effective for fiscal years ending after December 15, 2009. As the FSP provides only disclosure requirements, the adoption of this FSP will not have any effect on reported results of operations, financial condition or cash flows.

In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which requires the disclosure of summarized financial information about the fair value of financial instruments for interim reporting. This FSP is effective for interim reporting periods ending after June 15, 2009, and we adopted it as of April 1, 2009. As the FSP provides only disclosure requirements, the adoption of this FSP did not have any effect on reported results of operations, financial condition or cash flows. The disclosures are provided in Note 9.

In April 2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” which changed the guidance for recording impairment of investments in debt securities. This FSP is effective for interim and annual reporting periods ending after June 15, 2009, and is expected to affect many utility companies that hold debt securities in nuclear decommissioning trust funds. However, our adoption of this FSP as of April 1, 2009 did not affect the accounting for our nuclear decommissioning trust fund because the trust balance is reported at fair value, with changes in fair value of the trust resulting in changes in Oncor’s regulatory asset or liability related to the decommissioning cost. This FSP also requires the disclosure of information about the fair value of the investments for interim reporting as provided in Note 13.

6

In April 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” This FSP is effective for interim reporting periods ending after June 15, 2009, and we adopted it as of April 1, 2009. This FSP did not change our fair value measurement techniques. However, the FSP requires disclosures of additional detail of securities held in our nuclear decommissioning trust that are provided in Note 8.

In May 2009, the FASB issued SFAS 165, “Subsequent Events,” which requires disclosure of the date through which we have evaluated subsequent events related to the financial statements being issued and the basis for that date. SFAS 165 is effective for interim and annual reporting periods ending after June 15, 2009. Our adoption of this rule as of April 1, 2009 did not affect reported results of operations, financial condition or cash flows, and the required disclosure is provided above in “Basis of Presentation.”

In June 2009, the FASB issued SFAS 166, “Accounting for Transfers of Financial Assets, an Amendment of FASB Statement No. 140,” which eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. SFAS 166 is effective for periods beginning after November 15, 2009. We are evaluating the impact of SFAS 166 on our financial statements and footnote disclosures with respect to our sales of accounts receivables program discussed in Note 3.

In June 2009, the FASB issued SFAS 167, “Amendments to FASB Interpretation No. 46(R),” which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated and requires additional disclosures. SFAS 167 is effective for periods beginning after November 15, 2009. We are evaluating the impact of SFAS 167, but currently do not expect a material effect on our financial statements.

In June 2009, the FASB issued SFAS 168, “TheFASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles,” which establishes theFASB Accounting Standards Codification™ (Codification) as the source of authoritative US GAAP recognized by the FASB to be applied to nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also included in the Codification as sources of authoritative US GAAP for SEC registrants. SFAS 168 and the Codification are effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of this rule will not affect reported results of operations, financial condition or cash flows. We will implement SFAS 168 in our third quarter Form 10-Q by updating the previous FASB references to the Codification.

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2. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Reported goodwill as of June 30, 2009 totaled $14.3 billion, with $10.2 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. Reported goodwill as of December 31, 2008 totaled $14.4 billion, with $10.3 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.

In the first quarter of 2009, we recorded a $90 million goodwill impairment charge largely related to the Competitive Electric segment. This charge resulted from the completion of fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter of 2008. The impairment charge primarily reflected the dislocation in the capital markets during the fourth quarter of 2008 that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies. The impairment determination involved significant assumptions and judgments in estimating enterprise values of the Competitive Electric and Regulated Delivery segments and the fair values of their assets and liabilities. There have been no other goodwill impairments recorded since the Merger.

The calculations supporting the impairment determination utilized models that take into consideration multiple inputs, including commodity prices, debt yields, equity prices of comparable companies and other inputs. Those models were generally used in developing long-term forward price curves for certain commodities and discount rates for determining fair values of our reporting units as well as certain individual assets and liabilities of those businesses. The fair value measurements resulting from such models are classified as Level 3 measurements consistent with the guidance in SFAS 157 (see Note 8).

Identifiable Intangible Assets

Identifiable intangible assets reported in the balance sheet are comprised of the following:

	As of June 30, 2009						As of December 31, 2008
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	173	$	290	$	463	$	130	$	333
Favorable purchase and sales contracts		700		322		378		700		249		451
Capitalized in-service software		435		139		296		255		116		139
Environmental allowances and credits		989		162		827		994		121		873
Land easements and other		203		73		130		203		71		132
Total intangible assets subject to amortization	$	2,790	$	869		1,921	$	2,615	$	687		1,928
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization)						104						110
Total intangible assets					$	2,980					$	2,993

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Amortization expense related to intangible assets consisted of:

			Three Months Ended June 30,				Six Months Ended June 30,
	Income Statement Line	Segment	2009		2008		2009		2008
Retail customer relationship	Depreciation and amortization	Competitive Electric	$	21	$	13	$	43	$	26
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	Competitive Electric		32		44		73		103
Capitalized in-service software	Depreciation and amortization	All		12		11		23		22
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	Competitive Electric		20		24		41		50
Land easements and other	Depreciation and amortization	All		1		—		2		1
Total amortization expense			$	86	$	92	$	182	$	202

Estimated Amortization of Intangible Assets — The estimated aggregate amortization expense related to identifiable intangible assets for each of the next five fiscal years is as follows:

Year	Amount
2009	$	373
2010		245
2011		199
2012		155
2013		129

9

3. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Subsidiaries of TCEH engaged in retail sales of electricity 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, such subsidiaries (originators) sell trade accounts receivable to TXU Receivables Company, which is a special purpose entity created for the purpose of purchasing receivables from the originators and is a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities).

The maximum amount currently available under the accounts receivable securitization program is $700 million, and the program funding totaled $496 million at June 30, 2009. Under the terms of the program, available funding was reduced by the total of $103 million of customer deposits held by the originators at June 30, 2009 because TCEH’s credit ratings were lower than Ba3/BB-.

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 and 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 $268 million at June 30, 2009 and December 31, 2008, respectively.

The discount from face amount on the purchase of receivables from the originators principally funds program fees paid to the funding entities. The program fees, which are also referred to as losses on sale of the receivables under SFAS 140, consist primarily of interest costs on the underlying financing. The discount also funds a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company, a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.

Program fee amounts, which are reported in SG&A expenses, were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Program fees	$	3		$	4		$	7		$	11
Program fees as a percentage of average funding (annualized)		2.9	%		4.9	%		3.3	%		6.0	%

The trade accounts receivable balance reported in the June 30, 2009 consolidated balance sheet includes $846 million face amount of retail accounts receivable sold and has been reduced by proceeds from the sale of undivided interests in those receivables totaling $496 million. Funding under the program increased $80 million and $119 million for the six month periods ending June 30, 2009 and 2008, respectively. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.

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Activities of TXU Receivables Company were as follows:

	Six Months Ended June 30,
	2009			2008
Cash collections on accounts receivable	$	2,769		$	2,844
Face amount of new receivables purchased		(2,931	)		(2,987	)
Discount from face amount of purchased receivables (to fund fees paid)		8			13
Program fees paid to funding entities		(7	)		(11	)
Servicing fees paid to EFH Corp. subsidiary for recordkeeping and collection services		(1	)		(2	)
Increase in subordinated notes payable		82			24
Operating cash flows provided to originators under the program	$	(80	)	$	(119	)

The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if 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 funding entities 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. In addition, the program may be terminated if TXU Receivables Company or the EFH Corp. subsidiary acting as collection agent defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than the EFH Corp. subsidiary, any parent guarantor of an originator or any originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of June 30, 2009, there were no such events of termination.

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.

The subordinated notes issued by TXU Receivables Company are subordinated to the undivided interests of the funding entities in the purchased receivables.

Trade Accounts Receivable

	June 30, 2009			December 31, 2008
Gross wholesale and retail trade accounts receivable	$	1,724		$	1,705
Undivided interests in retail accounts receivable sold by TXU Receivables Company		(496	)		(416	)
Allowance for uncollectible accounts		(59	)		(70	)
Trade accounts receivable – reported in balance sheet	$	1,169		$	1,219

Gross trade accounts receivable at June 30, 2009 and December 31, 2008 included unbilled revenues of $635 million and $505 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Six Months Ended June 30,
	2009			2008
Allowance for uncollectible accounts receivable as of beginning of period	$	70		$	32
Increase for bad debt expense		41			34
Decrease for account write-offs		(51	)		(34	)
Other		(1	)		—
Allowance for uncollectible accounts receivable as of end of period	$	59		$	32

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4. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At June 30, 2009, we had outstanding short-term borrowings of $1.442 billion at a weighted average interest rate of 2.62%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $542 million for Oncor.

At December 31, 2008, we had outstanding short-term borrowings of $1.237 billion at a weighted average interest rate of 3.41%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $337 million for Oncor.

Credit Facilities

Our credit facilities with cash borrowing and/or letter of credit availability at June 30, 2009 are presented below. The facilities are all senior secured facilities of the authorized borrower.

		At June 30, 2009
Authorized Borrowers and Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Delayed Draw Term Loan Facility (a)	October 2014	$	4,100	$	—	$	3,997	$	87
TCEH Revolving Credit Facility (b)	October 2013		2,700		48		900		1,726
TCEH Letter of Credit Facility (c)	October 2014		1,250		—		1,250		—
Subtotal TCEH (d)		$	8,050	$	48	$	6,147	$	1,813
TCEH Commodity Collateral Posting Facility (e)	December 2012		Unlimited	$	—	$	—		Unlimited
Oncor Revolving Credit Facility (f)	October 2013	$	2,000	$	—	$	542	$	1,336

(a) Facility to be used to fund expenditures for constructing certain new generation facilities and environmental upgrades of existing generation facilities, including previously incurred expenditures not yet funded under this facility. Borrowings are classified as long-term debt. Availability amount excludes $16 million of commitments from a subsidiary of Lehman Brothers Holding Inc. (such subsidiary, Lehman) that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. The commitment under this facility terminates in October 2009. In July 2009, this facility was fully drawn.

(b) Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $139 million of commitments from Lehman that are only available from the fronting banks and the swingline lender and excludes $26 million of requested cash draws that have not been funded by Lehman. All outstanding borrowings under this facility at June 30, 2009 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility.

(c) Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the closing of the Merger, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $668 million issued as of June 30, 2009 are supported by the restricted cash, and the remaining letter of credit availability totals $467 million.

(d) Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at June 30, 2009, the total availability under the TCEH credit facilities should be further reduced by $231 million.

(e) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 680 million MMBtu as of June 30, 2009. As of June 30, 2009, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.

(f) Facility used by Oncor for its general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount excludes $122 million of commitments from Lehman, but includes a $32 million portion of the Lehman commitment purchased in April 2009 by a third party. All outstanding borrowings under this facility at June 30, 2009 bear interest at LIBOR plus 0.350%, and a facility fee is payable (currently at a rate per annum equal to 0.125%) on the commitments under the facility. The interest rate and facility fee rate per annum declined in June 2009 from LIBOR plus 0.425% and 0.150%, respectively, due to a two notch upgrade in Oncor’s credit ratings by Moody’s.

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Long-Term Debt

At June 30, 2009 and December 31, 2008, long-term debt consisted of the following:

	June 30, 2009			December 31, 2008
TCEH
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
8.250% Fixed Series 2001A due October 1, 2030		71			71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)		217			217
8.250% Fixed Series 2001D-1 due May 1, 2033		171			171
0.400% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.550% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.400% 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
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028		14			14
Unamortized fair value discount related to pollution control revenue bonds (d)		(154	)		(161	)
Senior Secured Facilities:
3.821% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)		16,162			16,244
3.821% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		3,997			3,562
3.810% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
0.295% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (g)		—			—
Other:
10.25% Fixed Senior Notes due November 1, 2015		3,000			3,000
10.25% Fixed Senior Notes Series B due November 1, 2015		2,000			2,000
10.50 / 11.25% Senior Toggle Notes due November 1, 2016		1,848			1,750
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.100% Promissory Note due January 5, 2009		—			65
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		55			67
Capital lease obligations		163			159
Unamortized fair value discount (d)		(5	)		(6	)
Total TCEH	$	29,856		$	29,470

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	June 30, 2009			December 31, 2008
EFC Holdings
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	55		$	55
8.254% Fixed Notes due in quarterly installments through December 31, 2021		51			53
1.828% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (f)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized fair value discount (d)		(12	)		(12	)
Total EFC Holdings		103			105
EFH Corp. (parent entity)
10.875% Fixed Senior Notes due November 1, 2017		2,000			2,000
11.25 / 12.00% Senior Toggle Notes due November 1, 2017		2,650			2,500
4.800% Fixed Senior Notes Series O due November 15, 2009		3			3
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)		75			80
Unamortized fair value premium related to Building Financing (d)		22			22
Unamortized fair value discount (d)		(632	)		(661	)
Total EFH Corp.		6,618			6,444
Oncor (i)
6.375% Fixed Senior Notes due May 1, 2012		700			700
5.950% Fixed Senior Notes due September 1, 2013		650			650
6.375% Fixed Senior Notes due January 15, 2015		500			500
6.800% Fixed Senior Notes due September 1, 2018		550			550
7.000% Fixed Debentures due September 1, 2022		800			800
7.000% Fixed Senior Notes due May 1, 2032		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
7.500% Fixed Senior Notes due September 1, 2038		300			300
Unamortized discount		(16	)		(16	)
Total Oncor		4,334			4,334
Oncor Electric Delivery Transition Bond Company LLC (j)
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		31			54
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		10			39
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		827			879
Unamortized fair value discount related to transition bonds (d)		(7	)		(9	)
Total Oncor consolidated		5,154			5,204
Total EFH Corp. consolidated		41,731			41,223
Less amount due currently		(325	)		(385	)
Total long-term debt	$	41,406		$	40,838

(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, 2009. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(c) Interest rate in effect at June 30, 2009. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

(d) Amount represents unamortized fair value adjustments recorded under purchase accounting.

(e) Interest rate swapped to fixed on $17.55 billion principal amount.

(f) Interest rates in effect at June 30, 2009. The TCEH Delayed Draw Term loan facility rate excludes a commitment fee paid quarterly in arrears on the undrawn portion of the commitments at a rate equal to 1.50% per annum.

(g) Interest rates in effect at June 30, 2009, excluding a quarterly maintenance fee of approximately $11 million. See “Credit Facilities” above for more information.

14

(h) This financing is secured and will be serviced with $115 million in restricted cash drawn in June 2009 by the beneficiary of a letter of credit. The issuer elected not to extend the expiration date of the letter of credit, and TCEH elected to allow the drawing in lieu of reissuing the letter of credit under the TCEH Revolving Credit Facility. The $115 million is included in other current assets and other noncurrent assets on the balance sheet.

(i) Secured with first priority lien as discussed under “Oncor Revolving Credit Facility” below.

(j) These bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.

Debt-Related Activity in 2009— Repayments of long-term debt in 2009 totaling $228 million represented principal payments at scheduled maturity dates as well as other repayments totaling $29 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $82 million repaid under the TCEH Initial Term Loan Facility, $65 million of a TCEH promissory note, and $52 million of Oncor transition bond principal payments.

Increases in long-term debt during 2009 totaling $435 million consisted of borrowings under the TCEH Delayed Draw Term Loan Facility to fund expenditures related to construction of new generation facilities and environmental upgrades of existing lignite/coal-fueled generation facilities. In addition, long-term debt increased as a result of the issuance of $150 million of EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes) and $98 million of TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes) in lieu of cash interest payments as discussed below.

EFH Corp. and TCEH have the option every six months until November 1, 2012, at their election, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments.

EFH Corp. made its May 2009 interest payment and will make its November 2009 interest payment by using the PIK feature of the EFH Corp. Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the EFH Corp. Toggle Notes by $150 million on May 1, 2009 and will further increase the aggregate principal amount of the EFH Corp. Toggle Notes by $159 million on November 1, 2009. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $141 million and will further increase liquidity as of November 1, 2009 by an amount equal to approximately $149 million, with such amounts constituting the amount of cash interest that otherwise would have been payable on May 1, 2009 and November 1, 2009, respectively, and will increase the expected annual cash interest expense by approximately $35 million, constituting the additional cash interest that will be payable with respect to the $309 million of additional toggle notes.

Similarly, TCEH made its May 2009 interest payment and will make its November 2009 interest payment by using the PIK feature of the TCEH Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the TCEH Toggle Notes by $98 million on May 1, 2009 and will further increase the aggregate principal amount of the TCEH Toggle Notes by approximately $104 million on November 1, 2009. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $92 million and will further increase liquidity as of November 1, 2009 by an amount equal to approximately $97 million, with such amounts constituting the amount of cash interest that otherwise would have been payable on May 1, 2009 and November 1, 2009, respectively, and will increase the expected annual cash interest expense by approximately $21 million, constituting the additional cash interest that will be payable with respect to the $202 million of additional toggle notes.

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TCEH Senior Secured Facilities — The applicable rate on borrowings under the TCEH Initial Term Loan Facility, the TCEH Delayed Draw Term Loan Facility, the TCEH Revolving Credit Facility and the TCEH Letter of Credit Facility as of June 30, 2009 is provided in the long-term debt table above and reflects LIBOR-based borrowings.

The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis by EFC Holdings and subject to certain exceptions, each existing and subsequently acquired or organized direct or indirect wholly-owned US restricted subsidiary of TCEH. The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Hedges” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility (approximately $41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments beginning in December 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of such date, with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.

TCEH Senior Notes — Borrowings under TCEH’s and TCEH Finance’s (collectively, the Co-Issuers) 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes Series B due November 1, 2015 (collectively, TCEH Cash-Pay Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum. Borrowings under the TCEH Toggle Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK Interest (as defined below). For any interest period until November 1, 2012, the Co-Issuers may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (Payment-in-Kind or PIK Interest); or (iii) 50% in cash and 50% in PIK Interest.

The TCEH Cash-Pay Notes and the TCEH Toggle Notes (collectively the TCEH Senior Notes) are fully and unconditionally guaranteed on a joint and several basis by TCEH’s direct parent, EFC Holdings (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.

The Co-Issuers may redeem the TCEH Cash-Pay Notes, in whole or in part, at any time on or after November 1, 2011, or the TCEH Toggle Notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before November 1, 2010, the Co-Issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of TCEH Cash-Pay Notes and TCEH Toggle Notes from time to time at a redemption price of 110.250% and 110.500%, respectively, of their respective aggregate principal amount plus accrued and unpaid interest, if any. The Co-Issuers may also redeem the TCEH Cash-Pay Notes at any time prior to November 1, 2011 or the TCEH Toggle Notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. Upon the occurrence of a change in control of TCEH, the Co-Issuers must offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

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EFH Corp. Senior Notes — Borrowings under EFH Corp.��s 10.875% Senior Notes due November 1, 2017 (EFH Corp. Cash-Pay Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum. Borrowings under EFH Corp.’s 11.250%/12.000% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes and collectively with the EFH Corp. Cash-Pay Notes, the EFH Corp. Senior Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the notes, at EFH Corp.’s option (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes; or (iii) 50% in cash and 50% in PIK Interest.

The EFH Corp. Senior Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding.

EFH Corp. may redeem the EFH Corp. Senior Notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before November 1, 2010, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFH Corp. Toggle Notes from time to time at a redemption price of 110.875% of the aggregate principal amount of the EFH Corp. Cash-Pay Notes, plus accrued and unpaid interest, if any, or 111.250% of aggregate principal amount of the EFH Corp. Toggle Notes, plus accrued and unpaid interest, if any. EFH Corp. may also redeem the EFH Corp. Senior Notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. Upon the occurrence of a change in control of EFH Corp., EFH Corp. must offer to repurchase the EFH Corp. Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

TCEH Interest Rate Swap Transactions— TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $17.55 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2009 to 2014. Interest rate swaps on an aggregate of $15.05 billion were being accounted for as cash flow hedges related to variable interest rate cash flows until August 29, 2008, at which time these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at the dedesignation date and was recorded in accumulated other comprehensive income. This balance will be reclassified into net income as interest on the hedged debt is reflected in net income. No ineffectiveness gains or losses were recorded.

As of June 30, 2009, TCEH has interest rate basis swap transactions entered into prior to 2009 pursuant to which quarterly payment of the floating interest rates at three-month LIBOR on an aggregate of $10.95 billion of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.076% to 0.292%. TCEH added interest rate basis swap transactions in January and February 2009 pursuant to which payments of the floating interest rates at three-month LIBOR on an aggregate of $5 billion of senior secured term loans of TCEH were exchanged for floating interest rates at one-month LIBOR plus spreads ranging from 0.201% to 0.353%. In addition, in May 2009, concurrent with the maturity of a basis swap related to $2.095 billion of debt, TCEH entered into interest rate basis swap transactions pursuant to which payment of the floating interest rates at three-month LIBOR on an aggregate of $1.45 billion of senior secured term loans of TCEH were exchanged for floating interest rates at one-month LIBOR plus a spread of approximately 0.191%.

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The interest rate swap counterparties are secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Subsequent to the dedesignation in August 2008 discussed above, changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market net gains totaled $460 million and $665 million in the three and six months ended June 30, 2009, respectively. There were no unrealized mark-to-market gains or losses in net income on interest rate swaps for the three and six months ended June 30, 2008. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.3 billion at June 30, 2009, of which $294 million (pre-tax) was reported in accumulated other comprehensive income.

In February and March 2009, EFH Corp. and TCEH entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which the companies elected to enter into as a cash management measure, as of June 30, 2009 EFH Corp. has posted $400 million in cash and TCEH has posted $65 million in letters of credit (including $15 million posted pursuant to an April 2009 amendment) to the counterparties, with the outstanding balance of such collateral earning interest. At June 30, 2009, the mark-to-market liability under each interest rate swap agreement exceeded the collateral posted under such agreement. In particular, the mark-to-market liability related to the $400 million cash posting totaled $707 million at June 30, 2009. EFH Corp. and TCEH are not required to post any additional collateral to these counterparties, regardless of the mark-to-market liability under the applicable swap agreement, and the applicable counterparty will return the cash collateral to the extent the mark-to-market liability under the applicable swap agreement falls below the funded amount, subject to a $50 million minimum transfer amount. The counterparties are required to return any remaining collateral to EFH Corp. and TCEH, respectively, on March 31, 2010. The cash collateral was recorded as an investment and is presented in the balance sheet as a separate line item under current assets, and interest received is recorded as interest income.

Oncor Secured Revolving Credit Facility— Oncor has a $2.0 billion credit facility to be used for its working capital and general corporate purposes, including issuances of commercial paper and letters of credit. Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Amounts borrowed under the facility, once repaid, can be reborrowed by Oncor from time to time until October 10, 2013. Oncor secured this credit facility with a first priority lien on certain of its transmission and distribution assets. Oncor also secured all of its existing long-term debt securities (excluding the transition bonds) with the same lien in accordance with the terms of those securities. The lien contains customary provisions allowing Oncor to use the assets in its business, as well as to replace and/or release collateral as long as the market value of the aggregate collateral is at least 115% of the aggregate secured debt. The lien may be terminated at Oncor’s option upon the termination of Oncor’s credit facility. Borrowings under this credit facility totaled $542 million and $337 million at June 30, 2009 and December 31, 2008, respectively. The applicable rate on borrowings under this credit facility as of June 30, 2009 was 0.67% (see detail provided in the credit facilities table above).

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5. COMMITMENTS AND CONTINGENCIES

Generation Development

TCEH has executed EPC agreements for the development of three lignite-fueled generation units in Texas, two units at Oak Grove and one at Sandow. Significant progress has been made on the construction of the Oak Grove units, and the unit at Sandow is in the commissioning and start-up phase.

In connection with the acquisition of the development rights to the Sandow unit, a subsidiary of TCEH (Sandow Power Company LLC, or Sandow Power) became a party to a federal consent decree with, among others, the US Department of Justice in August 2007 (the Consent Decree). A 2007 federal court order related to the Consent Decree requires that, among other things, the Sandow unit achieve commercial operations (as defined in the Consent Decree) and meet certain emission rate limits by August 31, 2009. The Sandow unit met the commercial operation deadline by synchronizing to the ERCOT grid in early July 2009. However, due to unforeseen weather events and equipment malfunctions experienced during commissioning and start-up activities, Sandow Power does not expect that the Sandow unit, operating at full capacity, would meet the required emission rate limits on or before August 31, 2009. Under the terms of the Consent Decree, Sandow Power may request an extension to the emission rate deadlines for certain force majeure events (including such events as the weather events and equipment malfunctions described above). On July 14, 2009, pursuant to these provisions, Sandow Power requested a 59-day extension of the emissions rate deadlines and certain other requirements that apply beginning on August 31, 2009. If the parties to the Consent Decree do not agree to an extension or the federal district court that presides over the Consent Decree does not grant an extension, Sandow Power could incur material non-compliance penalties for failing to meet the applicable emission rate limits on a sustained basis. Because of a number of variables, including duration of any violations, applicable penalty rates and potential recoveries, we cannot currently estimate the amount of such penalties, if any. This matter is not expected to have a material effect on the continuing progress of the unit commissioning and start-up.

TCEH has received the air permits for the Sandow and Oak Grove units. However, the Oak Grove air permit remains the subject of litigation as discussed below under “Litigation Related to Generation Facilities.”

Construction work-in-process asset balances for the Oak Grove units totaled approximately $3.1 billion as of June 30, 2009, which includes the effects of the fair value adjustments related to purchase accounting and capitalized interest. In the unexpected event the development of the Oak Grove units was cancelled, the cancellation exposure as of June 30, 2009 totaled $3.2 billion, which includes the carrying value of the project and up to approximately $150 million of termination obligations. This estimated exposure amount excludes any potential recovery values for assets acquired to date and for assets already owned prior to executing such agreements that are being utilized in these projects.

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Litigation Related to Generation Facilities

In September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs has asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. We believe the Oak Grove air permit granted by the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Oak Grove project.

In July 2008, the Sierra Club announced that it may sue Luminant, after the expiration of a 60-day waiting period, for violating federal Clean Air Act provisions in connection with Luminant’s Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit relating to Martin Lake or the outcome of any such proceeding.

Other Litigation

In September 2005, a lawsuit was filed in the US District Court for the Northern District of Texas, Dallas Division against EFH Corp. (then known as TXU Corp.) and C. John Wilder, EFH Corp.’s former Chief Executive Officer. The plaintiffs asserted claims on behalf of themselves and a putative class of owners of certain EFH Corp. securities who tendered such securities in connection with a tender offer conducted by EFH Corp. in 2004. The plaintiffs alleged 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 thereunder. In August 2006, the District Court dismissed this litigation with prejudice. In 2007, the US Court of Appeals for the Fifth Circuit remanded the dismissal to the District Court in light of the US Supreme Court’s then-recent decision in Tellabs, Inc. v. Makor Issues & Rights, Ltd. On remand, in April 2008, the District Court again dismissed this litigation with prejudice. In April 2009, the US Court of Appeals for the Fifth Circuit affirmed the dismissal of all claims against EFH Corp. and Mr. Wilder. In June 2009, the plaintiffs requested that the US Supreme Court review the merits of the case. The US Supreme Court has not yet indicated if it will hear the case. We believe the claims in this litigation are without merit and intend to vigorously defend this appeal.

In July 2008, Alcoa Inc. filed a lawsuit in Milam County, Texas district court against EFH Corp. and a number of its subsidiaries. The lawsuit makes various claims concerning the operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud and conversion, and requests money damages in an unspecified amount, declaratory judgment, and other forms of equitable relief. In March 2009, Alcoa Inc. filed an amended complaint and added seven new defendants to the lawsuit, including Texas Holdings and additional subsidiaries of EFH Corp. An agreed scheduling order is currently in place setting trial for May 2010. While we are unable to estimate any possible loss or predict the outcome of this litigation, we believe the claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation.

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Regulatory Investigations and Reviews

In June 2008, the EPA issued a request for information to TCEH under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.

Other Proceedings

In addition to the above, we 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 our financial position, results of operations or cash flows.

Guarantees

We have entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions. Material guarantees are discussed below.

Disposed TXU Gas operations —In connection with the TXU Gas transaction in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, 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, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.

Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. At June 30, 2009, the aggregate maximum amount of residual values guaranteed was approximately $55 million with an estimated residual recovery of approximately $60 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the residual value guarantees under the lease portfolio is approximately four years.

See Note 4 above and Note 15 to Financial Statements in the 2008 Form 10-K for discussion of guarantees and security for certain of our indebtedness.

Letters of Credit

At June 30, 2009, TCEH had outstanding letters of credit under its credit facilities totaling $716 million as follows:

• $366 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

• $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million. The letters of credit are available to fund the payment of such debt obligations and expire in 2014;

• $65 million for collateral funding transactions with counterparties to interest rate swap agreements related to TCEH debt (see Note 4), and

• $77 million for miscellaneous credit support requirements.

Long-Term Contractual Obligations and Commitments— As of June 30, 2009, we entered into contractual obligations totaling approximately $308 million to purchase nuclear fuel in periods between 2010 and 2020.

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6. EQUITY

Dividend Restrictions

The indenture governing the EFH Corp. Senior Notes includes covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our capital stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under the indenture and/or after such distributions, on a pro forma basis, after giving effect to such payment, our consolidated leverage ratio is equal to or less than 7.0 to 1.0. Consolidated leverage ratio is generally defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA, in each case, on a consolidated basis, excluding Oncor Holdings and its subsidiaries.

The TCEH Senior Secured Facilities generally restrict TCEH from making any distribution to any of its parent companies for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0.

In addition, under applicable law, we would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent. See “Shareholder Actions” below.

EFH Corp. has not paid any cash dividends subsequent to the Merger.

Shareholder Actions

In May 2009, the shareholders of EFH Corp. approved the reduction of the stated capital of EFH Corp.’s common stock, no par value per share, to an amount equal to $0.001 for each outstanding share of common stock, resulting in total stated value of outstanding common stock of $2 million. Also in May 2009, EFH Corp.’s board of directors approved a decrease in additional paid-in capital of the same amount and the allocation of $0.001 per share to stated value of common stock upon issuance of any authorized but unissued shares of common stock that may occur from time to time, with the remainder of any amounts received for such shares allocated to additional paid-in capital.

Noncontrolling Interests

In November 2008, Oncor sold equity interests to Texas Transmission. Texas Transmission is an entity indirectly owned by a private investment group led by OMERS Administration Corporation, acting through its infrastructure investment entity, Borealis Infrastructure Management Inc., and the Government of Singapore Investment Corporation, acting through its private equity and infrastructure arm, GIC Special Investments Pte Ltd. The investor group is not affiliated with any member of the Sponsor Group, Texas Holdings or EFH Corp. Oncor also indirectly sold equity interests to certain members of its board of directors and its management team. Accordingly, after giving effect to all equity issuances, as of June 30, 2009, Oncor’s ownership was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission (see Note 1). Of the noncontrolling interests balance at June 30, 2009 in the table below, $1.366 billion related to Oncor’s noncontrolling interests.

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In connection with the filing of a combined operating license application with the NRC for two new nuclear generation units, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, known as Comanche Peak Nuclear Power Company LLC, to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary under FIN 46(R).

Equity

The following table presents the changes to equity during the six months ended June 30, 2009.

	EFH Corp. Shareholders’ Equity
	Common Stock (a)		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests (b)			Total Equity
Balance at December 31, 2008	$	—	$	8,045		$	(11,198	)	$	(379	)	$	1,355		$	(2,177	)
Net income		—		—			287			—			28			315
Effects of shareholder actions related to stated value of common stock		2		(2	)		—			—			—			—
Effects of EFH Corp. stock-based incentive compensation plans		—		10			—			—			—			10
Net effects of cash flow hedges		—		—			—			42			—			42
Distributions to noncontrolling interests		—		—			—			—			(17	)		(17	)
Investment by noncontrolling interests		—		—			—			—			32			32
Balance at June 30, 2009	$	2	$	8,053		$	(10,911	)	$	(337	)	$	1,398		$	(1,795	)

(a) Authorized shares totaled 2,000,000,000 ($0.001 stated value) as of June 30, 2009. Outstanding shares totaled 1,666,417,409 and 1,667,149,663 as of June 30, 2009 and December 31, 2008, respectively.

(b) See Note 1 for discussion of adoption of SFAS 160.

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7. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Risk Management Hedging Strategy

We enter into physical and financial derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term hedging program and the hedging of interest costs on our long-term debt. See Note 8 for a discussion of the fair value of all derivatives.

Long-Term Hedging Program —TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas over the next five years. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to a fixed basis, thereby hedging future interest costs and related cash flows. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 4 for additional information about these and other interest rate swap agreements.

Other Commodity Hedging and Trading Activity —In addition to the long-term hedging program, TCEH enters into derivatives, including electricity, natural gas, fuel oil and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.

As of June 30, 2009, 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 through 2009.

The following table provides detail of commodity and other derivative contractual assets and liabilities as presented in the balance sheet at June 30, 2009:

	Derivatives not under hedge accounting										Cash flow hedges
	Derivative assets				Derivative liabilities						Derivative assets
	Commodity contracts		Interest rate swaps		Commodity contracts			Interest rate swaps			Commodity contracts		Total
Current assets	$	3,124	$	65	$	5		$	—		$	4	$	3,198
Noncurrent assets		1,214		1		4			—			—		1,219
Current liabilities		3		—		2,517			647			—		3,167
Noncurrent liabilities		2		—		662			694			—		1,358
Net assets (liabilities)	$	4,333	$	66	$	(3,170	)	$	(1,341	)	$	4	$	(108	)

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Margin deposits related to these derivative instruments are reported separately in the balance sheet and totaled $246 million and $190 million in net liabilities at June 30, 2009 and December 31, 2008, respectively. Amounts presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

The following table presents the pre-tax effect of derivatives not under hedge accounting on net income for the three and six months ended June 30, 2009:

Derivative	Income statement presentation	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Commodity contracts	Net gain (loss) from commodity hedging and trading activities	$	(265	)	$	890
Interest rate swaps	Interest expense and related charges (a)		288			333
	Net gain	$	23		$	1,223

(a) Includes unrealized mark-to-market net gains totaling $460 million and $665 million, less amounts accrued or settled under interest rate swaps totaling $172 million and $332 million, for the three and six months ended June 30, 2009, respectively.

Results for the three and six months ended June 30, 2009 include a “day one” loss of $3 million and results for the three and six months ended June 30, 2008 include net “day one” losses totaling $39 million and $58 million, respectively, primarily associated with commodity contracts entered into at below market prices. Substantially all of these amounts represent losses associated with related series of transactions involving natural gas financial instruments intended to hedge exposure to future changes in electricity prices. The losses are reported in the income statement in net losses from commodity hedging and trading activities, consistent with other mark-to-market hedging and trading gains and losses, and are included in the results of the Competitive Electric segment.

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The following tables present the pre-tax effect of derivative instruments accounted for as cash flow hedges on net income (loss) and other comprehensive income (loss) (OCI) for the three and six months ended June 30, 2009:

Three Months Ended June 30, 2009
Derivative	Amount of initial gain (loss) recognized in OCI (effective portion)			Income statement presentation of gain (loss) reclassified from accumulated OCI into income (effective portion)	Amount
Interest rate swaps	$	—		Interest expense and related charges	$	(44	)
Commodity contracts:		1		Fuel, purchased power costs and delivery fees		(4	)
				Operating revenues		(1	)
Total	$	1			$	(49	)
Six Months Ended June 30, 2009
Derivative	Amount of initial gain (loss) recognized in OCI (effective portion)			Income statement presentation of gain (loss) reclassified from accumulated OCI into income (effective portion)	Amount
Interest rate swaps	$	—		Interest expense and related charges	$	(84	)
Commodity contracts:		(25	)	Fuel, purchased power costs and delivery fees		(4	)
				Operating revenues		(2	)
Total	$	(25	)		$	(90	)

There were no ineffectiveness net gains or losses related to transactions currently designated as cash flow hedges in the three and six months ended June 30, 2009.

Accumulated other comprehensive income related to cash flow hedges at June 30, 2009 totaled $196 million in net losses (after-tax), substantially all of which relates to interest rate swaps. We expect that $105 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of June 30, 2009 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

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The following table presents the gross notional amounts of derivative volumes, including cash flow hedge volumes, at June 30, 2009:

Derivative type	Notional Volume		Unit of Measure
Interest rate swaps:
Floating/fixed	$	19,250	Million US dollars
Basis	$	17,400	Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		3,533	Million MMBtu
Locational basis swaps		1,016	Million MMBtu
All other		1,351	Million MMBtu
Electricity		196,377	GWh
Coal		10	Million tons
Fuel oil		180	Million gallons

(a) Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, is 1.8 billion MMBtu.

Credit Risk-Related Contingent Features

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if our credit rating is downgraded by one or more of the credit rating agencies; however, due to our below investment grade ratings, substantially all of such collateral posting requirements are already effective.

As of June 30, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $1.142 billion. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $181 million as of June 30, 2009. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of June 30, 2009, the remaining related liquidity requirement would have totaled $40 million after reduction for net accounts receivable and derivative assets under netting arrangements.

In addition, certain derivative agreements that are collateralized solely with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of June 30, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.731 billion (before consideration of the amount of assets under the liens). The liquidity exposure associated with these liabilities was reduced by cash investments and letters of credit posted with counterparties totaling $465 million as of June 30, 2009 (see Note 4). If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of June 30, 2009, the remaining related liquidity requirement would have totaled $834 million after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 15 to the Financial Statements in the 2008 Form 10-K for a description of other obligations that are supported by asset liens.

The aggregate fair values of liabilities under agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.873 billion at June 30, 2009. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.

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Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

While the disclosures above address our derivative liabilities, we also manage our counterparty credit exposure with respect to derivative assets.

8. FAIR VALUE MEASUREMENTS

SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. With the adoption of SFAS 157, we use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement under SFAS 133 and other accounting rules that require such measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy established by SFAS 157:

• Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities normally include exchange traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures and swaps transacted through clearing brokers for which prices are actively quoted.

• Level 2 valuations use inputs, in the absence of actively quoted market prices, that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available.

• Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, certain derivative assets or liabilities are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means.

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

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In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.

Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

With respect to amounts presented in the following fair value hierarchy table, the fair value measurement of an asset or liability (e.g. a contract) is required under SFAS 157 to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

At June 30, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity-related contracts	$	1,184	$	2,888	$	265	$	14	$	4,351
Interest rate swaps		—		66		—		—		66
Nuclear decommissioning trust – equity securities (c) (e)		119		85		—		—		204
Nuclear decommissioning trust – debt securities (d) (e)		4		200		—		—		204
Total assets	$	1,307	$	3,239	$	265	$	14	$	4,825
Liabilities:
Commodity-related contracts	$	1,424	$	1,409	$	337	$	14	$	3,184
Interest rate swaps		—		1,341		—		—		1,341
Total liabilities	$	1,424	$	2,750	$	337	$	14	$	4,525

(a) Level 3 assets and liabilities consist primarily of more complex long-term power purchase and sales agreements, including longer-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program.

(b) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

(d) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities have an average coupon rate of 4.27% and an average maturity of 8.78 years.

(e) The nuclear decommissioning trust investment is included in the Investments line on the balance sheet.

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At December 31, 2008, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Total
Assets:
Commodity-related contracts	$	1,010	$	2,061	$	283	$	3,354
Interest rate swaps		—		142		—		142
Nuclear decommissioning trust – equity securities (b) (d)		109		83		—		192
Nuclear decommissioning trust – debt securities (c) (d)		—		193		—		193
Total assets	$	1,119	$	2,479	$	283	$	3,881
Liabilities:
Commodity-related contracts	$	1,288	$	1,274	$	355	$	2,917
Interest rate swaps		—		2,086		—		2,086
Total liabilities	$	1,288	$	3,360	$	355	$	5,003

(a) Level 3 assets and liabilities consist primarily of more complex long-term power purchase and sales agreements, including longer-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program.

(b) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

(c) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities have an average coupon rate of 3.77% and an average maturity of 8.0 years.

(d) The nuclear decommissioning trust investment is included in the Investments line on the balance sheet.

Commodity-related contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales under SFAS 133. See Note 7 for further discussion regarding the company’s use of derivative instruments.

Interest rate swaps consist largely of variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt, as well as interest rate basis swaps designed to further reduce fixed borrowing costs. See Note 4 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of TCEH’s nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

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The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Balance at beginning of period	$	(78	)	$	(272	)	$	(72	)	$	(173	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		(1	)		(217	)		16			(345	)
Included in other comprehensive income (loss)		1			14			(25	)		15
Purchases, sales, issuances and settlements (net) (b)		7			(18	)		(10	)		(3	)
Net transfers in and/or out of Level 3 (c)		(1	)		(46	)		19			(33	)
Balance at end of period	$	(72	)	$	(539	)	$	(72	)	$	(539	)
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period (d)	$	2		$	(256	)	$	16		$	(375	)

(a) Substantially all changes in values of commodity-related contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

(b) Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Purchases and issuances reflect option premiums paid or received.

(c) Includes transfers due to changes in the observability of significant inputs used in valuing derivatives. Transfers in are assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter, which is when the assessments are performed. Any changes in value during the period are reported as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities.

(d) Includes unrealized gains and losses of instruments held at the end of the period only related to the periods in which the instrument was classified as a Level 3 asset or liability.

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9. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

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

	June 30, 2009						December 31, 2008
	Carrying Amount			Fair Value (a)			Carrying Amount			Fair Value (a)
On balance sheet assets (liabilities):
Long-term debt (including current maturities) (b):
TCEH, EFH Corp., and other	$	(36,414	)	$	(25,147	)	$	(35,860	)	$	(24,162	)
Oncor	$	(5,154	)	$	(5,509	)	$	(5,204	)	$	(4,990	)
Total	$	(41,568	)	$	(30,656	)	$	(41,064	)	$	(29,152	)
Off balance sheet assets (liabilities):
Financial guarantees	$	—		$	(9	)	$	—		$	(3	)

(a) Fair value determined in accordance with SFAS 157.

(b) Excludes capital leases.

See Notes 7 and 8 for discussion of accounting for financial instruments that are derivatives.

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

Net pension and OPEB costs for the three and six months ended June 30, 2009 and 2008 are comprised of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Components of net pension costs:
Service cost	$	9		$	7		$	18		$	16
Interest cost		39			29			78			66
Expected return on assets		(41	)		(32	)		(83	)		(76	)
Prior service cost		—			—			—			—
Net loss		2			—			4			—
Net pension costs		9			4			17			6
Components of net OPEB costs:
Service cost		3			3			6			5
Interest cost		15			15			30			30
Expected return on assets		(3	)		(5	)		(6	)		(10	)
Prior service cost		—			—			—			—
Net loss		3			2			6			6
Net OPEB costs		18			15			36			31
Net pension and OPEB costs		27			19			53			37
Less amounts deferred principally as a regulatory asset or property		(17	)		(11	)		(33	)		(22	)
Net amounts recognized as expense	$	10		$	8		$	20		$	15

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The discount rates reflected in net pension and OPEB costs in 2009 are 6.90% and 6.85%, respectively. The expected rates of return on pension and OPEB plan assets reflected in the 2009 cost amounts are 8.25% and 7.64%, respectively.

We made cash contributions related to our pension and OPEB plans of $36 million and $11 million, respectively, in the first half of 2009, and we expect to make additional contributions of $42 million and $11 million, respectively, in the remainder of 2009.

11. RELATED PARTY TRANSACTIONS

We incur an annual management fee under terms of a management agreement with the Sponsor Group for which we accrued $9 million for both the three months ended June 30, 2009 and 2008, and $18 million for both the six months ended June 30, 2009 and 2008. The fee is reported as SG&A expense in Corporate and Other activities.

At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities and Oncor entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (a member of the Sponsor Group) have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business.

Affiliates of Goldman Sachs & Co. are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

Affiliates of the Sponsor Group may sell or acquire debt or debt securities issued by us in open market transactions or through loan syndications.

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12. SEGMENT INFORMATION

Our 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.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, the development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted by TCEH. The results of this segment also include equipment salvage and resale activities related to the 2007 cancellation of the development of eight new coal-fueled generation units; such activities were not material for the periods presented.

The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly-owned bankruptcy-remote financing subsidiary.

Corporate and Other represents the remaining nonsegment operations consisting primarily of general corporate expenses and interest on EFH Corp. (parent entity) and EFC Holdings debt.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 above and in Note 1 in the 2008 Form 10-K. We evaluate performance based on income from continuing operations. We record intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues:
Competitive Electric	$	1,945		$	2,567		$	3,711		$	4,550
Regulated Delivery		653			626			1,266			1,241
Corporate and Other		6			7			13			17
Eliminations		(262	)		(249	)		(509	)		(503	)
Consolidated	$	2,342		$	2,951		$	4,481		$	5,305
Affiliated revenues included in operating revenues:
Competitive Electric	$	1		$	2		$	3		$	4
Regulated Delivery		257			241			496			484
Corporate and Other		4			6			10			15
Eliminations		(262	)		(249	)		(509	)		(503	)
Consolidated	$	—		$	—		$	—		$	—
Net income (loss):
Competitive Electric	$	(78	)	$	(3,257	)	$	479		$	(4,474	)
Regulated Delivery		82			85			140			170
Corporate and Other		(143	)		(159	)		(304	)		(296	)
Consolidated	$	(139	)	$	(3,331	)	$	315		$	(4,600	)

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13. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues
Regulated	$	653		$	626		$	1,266		$	1,241
Unregulated		1,951			2,574			3,724			4,567
Intercompany sales eliminations – regulated		(257	)		(241	)		(496	)		(484	)
Intercompany sales eliminations – unregulated		(5	)		(8	)		(13	)		(19	)
Total operating revenues		2,342			2,951			4,481			5,305
Fuel, purchased power and delivery fees – unregulated (a)		(700	)		(1,416	)		(1,301	)		(2,237	)
Net gain (loss) from commodity hedging and trading activities – unregulated		(248	)		(4,727	)		880			(6,293	)
Operating costs – regulated		(221	)		(208	)		(441	)		(407	)
Operating costs – unregulated		(174	)		(182	)		(342	)		(341	)
Depreciation and amortization – regulated		(132	)		(121	)		(258	)		(242	)
Depreciation and amortization – unregulated		(291	)		(269	)		(572	)		(543	)
Selling, general and administrative expenses – regulated		(44	)		(43	)		(88	)		(83	)
Selling, general and administrative expenses – unregulated		(226	)		(204	)		(428	)		(381	)
Franchise and revenue-based taxes – regulated		(58	)		(58	)		(118	)		(119	)
Franchise and revenue-based taxes – unregulated		(21	)		(23	)		(47	)		(48	)
Impairment of goodwill		—			—			(90	)		—
Other income		13			15			26			29
Other deductions		(7	)		(26	)		(18	)		(42	)
Interest income		11			8			12			13
Interest expense and other charges		(431	)		(831	)		(1,096	)		(1,674	)
Income (loss) before income taxes	$	(187	)	$	(5,134	)	$	600		$	(7,063	)

(a) Includes unregulated cost of fuel consumed of $298 million and $456 million for the three months ended June 30, 2009 and 2008, respectively, and $582 million and $782 million for the six months ended June 30, 2009 and 2008, respectively. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

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Other Income and Deductions

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Other income:
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting	$	10	$	11	$	20	$	22
Mineral rights royalty income		1		1		2		2
Other		2		3		4		5
Total other income	$	13	$	15	$	26	$	29
Other deductions:
Net charges related to cancelled development of generation facilities	$	1	$	2	$	2	$	7
Severance charges		1		—		7		—
Asset writeoffs		—		2		—		2
Professional fees incurred related to the Merger		—		2		—		3
Costs related to 2006 cities rate settlement		—		7		1		13
Litigation/regulatory settlements		—		7		—		6
Ongoing pension and other postretirement benefit expense related to discontinued businesses		—		3		—		1
Other		5		3		8		10
Total other deductions	$	7	$	26	$	18	$	42

Interest Expense and Related Charges

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Interest (including net amounts settled/ accrued under interest rate swaps)	$	873		$	854		$	1,745		$	1,724
Unrealized mark-to-market net gain on interest rate swaps		(460	)		—			(665	)		—
Amortization of interest rate swap losses at dedesignation of hedge accounting		44			—			84			—
Amortization of fair value debt discounts resulting from purchase accounting		20			19			39			36
Amortization of debt issuance costs and discounts		35			31			69			63
Capitalized interest, primarily related to generation facility and regulated utility asset construction		(81	)		(73	)		(176	)		(149	)
Total interest expense and related charges	$	431		$	831		$	1,096		$	1,674

Restricted Cash

	At June 30, 2009				At December 31, 2008
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to the TCEH Letter of Credit Facility (See Note 4)	$	—	$	1,135	$	—	$	1,250
Amounts related to margin deposits held		1		—		4		—
Amounts related to securitization (transition) bonds		42		15		51		17
Total restricted cash	$	43	$	1,150	$	55	$	1,267

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Inventories by Major Category

	June 30, 2009		December 31, 2008
Materials and supplies	$	216	$	199
Fuel stock		209		162
Natural gas in storage		28		65
Total inventories	$	453	$	426

Investments

	June 30, 2009		December 31, 2008
Nuclear decommissioning trust	$	408	$	385
Assets related to employee benefit plans, including employee savings programs, net of distributions		190		210
Land		44		44
Miscellaneous other		5		6
Total investments	$	647	$	645

Nuclear Decommissioning Trust —Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’s customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding adjustment to a regulatory asset/liability. A summary of investments in the fund follows:

	June 30, 2009
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities	$	207	$	5	$	(8	)	$	204
Equity securities		187		48		(31	)		204
Total	$	394	$	53	$	(39	)	$	408
	December 31, 2008
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities	$	203	$	4	$	(14	)	$	193
Equity securities		181		46		(35	)		192
Total	$	384	$	50	$	(49	)	$	385

(a) Includes realized gains and losses of securities sold.

Debt securities held at June 30, 2009 mature as follows: $60 million in one to five years, $44 million in five to ten years and $100 million after ten years.

Property, Plant and Equipment

As of June 30, 2009 and December 31, 2008, property, plant and equipment of $29.9 billion and $29.5 billion, respectively, is stated net of accumulated depreciation and amortization of $6.3 billion and $5.6 billion, respectively.

37

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’s rates.

The following table summarizes the changes to the asset retirement liability, reported in other noncurrent liabilities and deferred credits in the balance sheet, during the six months ended June 30, 2009:

Asset retirement liability at January 1, 2009	$	859
Additions:
Accretion		30
Reductions:
Payments, essentially all mining reclamation		(14	)
Asset retirement liability at June 30, 2009	$	875

38

Oncor’s Regulatory Assets and Liabilities

	June 30, 2009		December 31, 2008
Regulatory assets
Generation-related regulatory assets securitized by transition bonds	$	815	$	865
Employee retirement costs		663		659
Self-insurance reserve (primarily storm recovery costs)		212		214
Nuclear decommissioning cost under-recovery		128		127
Securities reacquisition costs		93		97
Recoverable deferred income taxes – net		76		77
Employee severance costs		20		20
Other		17		12
Total regulatory assets		2,024		2,071
Regulatory liabilities
Committed spending for demand-side management initiatives		90		96
Investment tax credit and protected excess deferred taxes		47		49
Deferred advanced metering system revenues		37		—
Over-collection of securitization (transition) bond revenues		26		28
Other regulatory liabilities		14		6
Total regulatory liabilities		214		179
Net regulatory assets	$	1,810	$	1,892

Regulatory assets that have been reviewed and approved by the PUCT and are not earning a return totaled $975 million and $1.021 billion at June 30, 2009 and December 31, 2008, respectively, including the generation-related regulatory assets securitized by transition bonds that have a remaining recovery period of approximately seven years. As part of purchase accounting, the carrying value of the generation-related regulatory assets was reduced by $213 million, and this amount is being accreted to other income over the approximate nine-year recovery period remaining as of the date of the Merger.

As of June 30, 2009, regulatory assets totaling $937 million have not been reviewed by the PUCT but are deemed by management to be probable of recovery. Recovery of employee retirement costs and self-insurance reserve costs, which represent the substantial majority of the amounts not reviewed by the PUCT, are specifically authorized by statute, subject to reasonableness review by the PUCT.

In September 2008, the PUCT approved a settlement for Oncor to recover its estimated future investment for advanced metering deployment. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.035 billion over the 11-year recovery period and includes a cost recovery factor of $2.21 per month per residential retail customer and $2.42 to $5.21 per month for non-residential retail customers. We account for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability; such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at June 30, 2009 totaled $37 million.

39

Exit Liabilities

As part of purchase accounting for the Merger, we accrued $54 million in costs expected to be incurred related to the termination and transition of outsourcing arrangements. We incurred $10 million of the exit liabilities in the six months ended June 30, 2009, and the remaining accrual is expected to be settled no later than June 30, 2010, the targeted date of completion of transition of outsourced activities back to us or to service providers.

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

	June 30, 2009		December 31, 2008
Uncertain tax positions (including accrued interest)	$	1,933	$	1,780
Retirement plan and other employee benefits		1,456		1,451
Asset retirement obligations		875		859
Unfavorable purchase and sales contracts		713		727
Liabilities related to subsidiary tax sharing agreement		309		299
Other		97		89
Total other noncurrent liabilities and deferred credits	$	5,383	$	5,205

We do not expect the total amount of liabilities recorded related to uncertain tax positions to significantly increase or decrease within the next 12 months. As of June 30, 2009, the federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes.

Unfavorable Purchase and Sales Contracts— The amortization of unfavorable purchase and sales contracts totaled $7 million and $6 million in the three months ended June 30, 2009 and 2008, respectively, and $14 million and $13 million in the six months ended June 30, 2009 and 2008, respectively. Favorable purchase and sales contracts are recorded as intangible assets (see Note 2).

The estimated amortization of unfavorable purchase and sales contracts for each of the five succeeding fiscal years from December 31, 2008 is as follows:

Year	Amount
2009	$	27
2010		27
2011		27
2012		27
2013		26

Liabilities Related to Subsidiary Tax Sharing Agreement —Amount represents the noncontrolling interests’ portion of the previously recorded net deferred tax liabilities of Oncor. Upon the sale of noncontrolling interests in Oncor (see Note 6), Oncor became a partnership for US federal income tax purposes, and the temporary differences which gave rise to the deferred taxes will, over time, become taxable to the minority interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses its equity holders for federal income taxes as the partnership earnings become taxable to such holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be reimbursed to rate payers. The net changes in the liability for the six months ended June 30, 2009 of $10 million reflected changes in temporary differences.

40

Supplemental Cash Flow Information

	Six Months Ended June 30,
	2009			2008
Cash payments (receipts) related to:
Interest paid (including net amounts under interest rate swaps)	$	1,513		$	1,724
Capitalized interest		(176	)		(149	)
Interest paid (net of capitalized interest) (a)		1,337			1,575
Income taxes		(45	)		33
Noncash investing and financing activities:
Issuance of toggle notes as consideration for cash interest for EFH Corp. and TCEH		248			—
Noncash construction expenditures (b)		175			138
Capital leases		15			9

(a) Net of interest received on interest rate swaps.

(b) Represents end-of-period accruals.

41

14. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

In 2007, EFH Corp. issued $2.0 billion 10.875% Senior Notes Due 2017 and $2.5 billion 11.25%/12.00% Senior Toggle Notes Due 2017 (collectively, the EFH Corp. Senior Notes). In May 2009, EFH Corp. issued an additional $150 million of the EFH Corp. Toggle Notes (see Note 4). The EFH Corp. Senior Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes. The guarantees rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Senior Notes (collectively, the Non-Guarantors). The indenture governing the EFH Corp. Senior Notes contains certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 6.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the three-month and six-month periods ended June 30, 2009 and 2008, the condensed consolidating statements of cash flows of the Parent/Issuer, the Guarantors and the Non-Guarantors for the six-month periods ended June 30, 2009 and 2008 and the condensed consolidating balance sheets as of June 30, 2009 and December 31, 2008 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, Push Down Basis of Accounting Required in Certain Limited Circumstances, including the effects of the push down of the $4.65 billion and $4.5 billion EFH Corp. Senior Notes to the Guarantors as of June 30, 2009 and December 31, 2008, respectively (see Notes 4 and 5).

EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $58 million and $135 million for the six months ended June 30, 2009 and 2008, respectively.

42

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended June 30, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,342		$	—		$	2,342
Fuel, purchased power costs and delivery fees		—			—			(700	)		—			(700	)
Net gain from commodity hedging and trading activities		—			—			(248	)		—			(248	)
Operating costs		—			—			(395	)		—			(395	)
Depreciation and amortization		—			—			(423	)		—			(423	)
Selling, general and administrative expenses		(35	)		—			(235	)		—			(270	)
Franchise and revenue-based taxes		—			—			(79	)		—			(79	)
Other income		1			—			12			—			13
Other deductions		(3	)		—			(4	)		—			(7	)
Interest income		60			—			32			(81	)		11
Interest expense and related charges		(240	)		(141	)		(269	)		219			(431	)
Income (loss) before income taxes and equity earnings of subsidiaries		(217	)		(141	)		33			138			(187	)
Income tax (expense) benefit		67			47			(19	)		(47	)		48
Equity earnings of subsidiaries		(5	)		7			—			(2	)		—
Net income (loss)		(155	)		(87	)		14			89			(139	)
Net income attributable to noncontrolling interests		—			—			(16	)		—			(16	)
Net loss attributable to EFH Corp.	$	(155	)	$	(87	)	$	(2	)	$	89		$	(155	)

43

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended June 30, 2008

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,951		$	—		$	2,951
Fuel, purchased power costs and delivery fees		—			—			(1,416	)		—			(1,416	)
Net gain from commodity hedging and trading activities		—			—			(4,727	)		—			(4,727	)
Operating costs		—			—			(390	)		—			(390	)
Depreciation and amortization		—			—			(390	)		—			(390	)
Selling, general and administrative expenses		(33	)		—			(214	)		—			(247	)
Franchise and revenue-based taxes		—			1			(82	)		—			(81	)
Other income		—			—			14			1			15
Other deductions		(6	)		—			(20	)		—			(26	)
Interest income		40			(6	)		37			(63	)		8
Interest expense and related charges		(224	)		(135	)		(666	)		194			(831	)
Income (loss) before income taxes and equity earnings of subsidiaries		(223	)		(140	)		(4,903	)		132			(5,134	)
Income tax (expense) benefit		62			47			1,737			(43	)		1,803
Equity earnings of subsidiaries		(3,170	)		(3,155	)		—			6,325			—
Net income (loss)	$	(3,331	)	$	(3,248	)	$	(3,166	)	$	6,414		$	(3,331	)

44

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Six Months Ended June 30, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	4,481		$	—		$	4,481
Fuel, purchased power costs and delivery fees		—			—			(1,301	)		—			(1,301	)
Net gain from commodity hedging and trading activities		—			—			880			—			880
Operating costs		—			—			(783	)		—			(783	)
Depreciation and amortization		—			—			(830	)		—			(830	)
Selling, general and administrative expenses		(63	)		—			(453	)		—			(516	)
Franchise and revenue-based taxes		—			—			(165	)		—			(165	)
Impairment of goodwill		—			—			(90	)		—			(90	)
Other income		2			—			24			—			26
Other deductions		(3	)		—			(15	)		—			(18	)
Interest income		111			—			57			(156	)		12
Interest expense and related charges		(476	)		(281	)		(770	)		431			(1,096	)
Income (loss) before income taxes and equity earnings of subsidiaries		(429	)		(281	)		1,035			275			600
Income tax (expense) benefit		137			92			(421	)		(93	)		(285	)
Equity earnings of subsidiaries		579			629			—			(1,208	)		—
Net income		287			440			614			(1,026	)		315
Net income attributable to noncontrolling interests		—			—			(28	)		—			(28	)
Net income attributable to EFH Corp.	$	287		$	440		$	586		$	(1,026	)	$	287

45

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Six Months Ended June 30, 2008

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	5,305		$	—		$	5,305
Fuel, purchased power costs and delivery fees		—			—			(2,237	)		—			(2,237	)
Net gain from commodity hedging and trading activities		—			—			(6,293	)		—			(6,293	)
Operating costs		—			—			(748	)		—			(748	)
Depreciation and amortization		—			—			(785	)		—			(785	)
Selling, general and administrative expenses		(54	)		—			(410	)		—			(464	)
Franchise and revenue-based taxes		—			1			(168	)		—			(167	)
Other income		—			—			29			—			29
Other deductions		(9	)		—			(33	)		—			(42	)
Interest income		79			4			69			(139	)		13
Interest expense and related charges		(450	)		(270	)		(1,356	)		402			(1,674	)
Income (loss) before income taxes and equity earnings of subsidiaries		(434	)		(265	)		(6,627	)		263			(7,063	)
Income tax (expense) benefit		131			89			2,330			(87	)		2,463
Equity earnings of subsidiaries		(4,297	)		(4,269	)		—			8,566			—
Net income (loss)	$	(4,600	)	$	(4,445	)	$	(4,297	)	$	8,742		$	(4,600	)

46

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Six Months Ended June 30, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(114	)	$	50		$	684		$	(116	)	$	504
Cash flows – financing activities:
Issuances of long-term borrowings		—			—			435			—			435
Retirements of long-term borrowings		—			(2	)		(226	)		—			(228	)
Change in short-term borrowings		—			—			205			—			205
Contributions from noncontrolling interests		—			—			32			—			32
Distributions paid to noncontrolling interests		—			—			(17	)		—			(17	)
Cash dividends paid		—			(58	)		(58	)		116			—
Change in advances – affiliates		281			10			—			(291	)		—
Other, net		20			—			(3	)		—			17
Cash provided by (used in) financing activities		301			(50	)		368			(175	)		444
Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(1,343	)		—			(1,343	)
Redemption of investment held in money market fund		—			—			142			—			142
Investment posted with counterparty		(400	)		—			—			—			(400	)
Reduction of restricted cash from letter of credit facility posted with trustee		—			—			115			—			115
Proceeds from sale of environmental allowances and credits		—			—			7			—			7
Purchases of environmental allowances and credits		—			—			(14	)		—			(14	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			2,231			—			2,231
Investments in nuclear decommissioning trust fund securities		—			—			(2,238	)		—			(2,238	)
Change in advances – affiliates		—			—			(291	)		291			—
Other, net		—			—			22			—			22
Cash provided by (used in) investing activities		(400	)		—			(1,369	)		291			(1,478	)
Net change in cash and cash equivalents		(213	)		—			(317	)		—			(530	)
Cash and cash equivalents – beginning balance		1,075			—			614			—			1,689
Cash and cash equivalents – ending balance	$	862		$	—		$	297		$	—		$	1,159

47

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Six Months Ended June 30, 2008

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(223	)	$	134		$	(1,541	)	$	(270	)	$	(1,900	)
Cash flows – financing activities:
Issuances of long-term borrowings/securities:
Long-term debt		—			—			1,004			—			1,004
Common stock		34			—			—			—			34
Retirements/repurchases of long-term borrowings/securities:
Long-term debt		(200	)		(1	)		(404	)		—			(605	)
Common stock		(1	)		—			—			—			(1	)
Change in short-term borrowings		—			—			3,015			—			3,015
Cash dividends paid		—			(135	)		(135	)		270			—
Change in advances – affiliates		356			2			—			(358	)		—
Other, net		—			—			16			—			16
Cash provided by (used in) financing activities		189			(134	)		3,496			(88	)		3,463
Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(1,564	)		—			(1,564	)
Proceeds from sale of environmental allowances and credits		—			—			28			—			28
Purchases of environmental allowances and credits		—			—			(17	)		—			(17	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			475			—			475
Investments in nuclear decommissioning trust fund securities		—			—			(482	)		—			(482	)
Change in advances – affiliates		—			—			(358	)		358			—
Other, net		2			—			(96	)		—			(94	)
Cash provided by (used in) investing activities		2			—			(2,014	)		358			(1,654	)
Net change in cash and cash equivalents		(32	)		—			(59	)		—			(91	)
Cash and cash equivalents – beginning balance		32			—			249			—			281
Cash and cash equivalents – ending balance	$	—		$	—		$	190		$	—		$	190

48

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at June 30, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	862		$	—		$	297	$	—		$	1,159
Investment posted with counterparty		400			—			—		—			400
Restricted cash		—			—			43		—			43
Advances to affiliates		390			4			—		(394	)		—
Trade accounts receivable – net		16			—			1,153		—			1,169
Income taxes receivable		—			2			61		(63	)		—
Accounts receivable from affiliates		—			—			5		(5	)		—
Notes receivable from affiliates		115			—			1,082		(1,197	)		—
Inventories		—			—			453		—			453
Commodity and other derivative contractual assets		62			—			3,136		—			3,198
Accumulated deferred income taxes		—			6			175		(59	)		122
Margin deposits related to commodity positions		—			—			345		—			345
Other current assets		2			—			165		—			167
Total current assets		1,847			12			6,915		(1,718	)		7,056
Restricted cash		—			—			1,150		—			1,150
Investments		4,468			3,410			581		(7,812	)		647
Property, plant and equipment – net		—			—			29,929		—			29,929
Notes receivable from affiliates		13			—			2,255		(2,268	)		—
Goodwill		—			—			14,316		—			14,316
Intangible assets – net		—			—			2,980		—			2,980
Regulatory assets – net		—			—			1,810		—			1,810
Commodity and other derivative contractual assets		—			—			1,219		—			1,219
Accumulated deferred income taxes		722			51			—		(773	)		—
Unamortized debt issuance costs and other noncurrent assets		116			100			786		(100	)		902
Total assets	$	7,166		$	3,573		$	61,941	$	(12,671	)	$	60,009
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,442	$	—		$	1,442
Advances from affiliates		—			—			394		(394	)		—
Long-term debt due currently		3			8			314		—			325
Trade accounts payable		4			—			926		—			930
Accounts payable to affiliates		5			—			—		(5	)		—
Notes payable to affiliates		1,026			20			151		(1,197	)		—
Commodity and other derivative contractual liabilities		94			—			3,073		—			3,167
Margin deposits related to commodity positions		—			—			528		—			528
Accumulated deferred income taxes		59			—			—		(59	)		—
Accrued interest		116			90			395		(89	)		512
Other current liabilities		105			—			540		(63	)		582
Total current liabilities		1,412			118			7,763		(1,807	)		7,486
Accumulated deferred income taxes		—			—			6,852		(721	)		6,131
Investment tax credits		—			—			40		—			40
Commodity and other derivative contractual liabilities		—			—			1,358		—			1,358
Notes or other liabilities due affiliates		2,019			—			249		(2,268	)		—
Long-term debt, less amounts due currently		6,517			4,746			34,793		(4,650	)		41,406
Other noncurrent liabilities and deferred credits		411			2			4,970		—			5,383
Total liabilities		10,359			4,866			56,025		(9,446	)		61,804
EFH Corp. shareholders’ equity		(3,193	)		(1,293	)		4,518		(3,225	)		(3,193	)
Noncontrolling interests in subsidiaries		—			—			1,398		—			1,398
Total equity		(3,193	)		(1,345	)		5,916		(3,225	)		(1,795	)
Total liabilities and equity	$	7,166		$	3,573		$	61,941	$	(12,671	)	$	60,009

49

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2008

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,075		$	—		$	614	$	—		$	1,689
Investments held in money market fund		—			—			142		—			142
Restricted cash		—			—			55		—			55
Advances to affiliates		403			7			—		(410	)		—
Trade accounts receivable – net		3			—			1,216		—			1,219
Income taxes receivable		—			—			128		(86	)		42
Accounts receivable from affiliates		—			—			3		(3	)		—
Notes receivable from affiliates		—			—			633		(633	)		—
Inventories		—			—			426		—			426
Commodity and other derivative contractual assets		143			—			2,391		—			2,534
Accumulated deferred income taxes		—			—			80		(36	)		44
Margin deposits related to commodity positions		—			—			439		—			439
Other current assets		6			—			159		—			165
Total current assets		1,630			7			6,286		(1,168	)		6,755
Restricted cash		—			—			1,267		—			1,267
Investments		3,899			2,793			579		(6,626	)		645
Property, plant and equipment – net		—			—			29,522		—			29,522
Notes receivable from affiliates		12			—			2,273		(2,285	)		—
Goodwill		—			—			14,386		—			14,386
Intangible assets – net		—			—			2,993		—			2,993
Regulatory assets – net		—			—			1,892		—			1,892
Commodity and other derivative contractual assets		—			—			962		—			962
Accumulated deferred income taxes		575			6			—		(581	)		—
Unamortized debt issuance costs and other noncurrent assets		130			111			711		(111	)		841
Total assets	$	6,246		$	2,917		$	60,871	$	(10,771	)	$	59,263
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,237	$	—		$	1,237
Advances from affiliates		—			—			410		(410	)		—
Long-term debt due currently		3			8			374		—			385
Trade accounts payable		8			—			1,135		—			1,143
Accounts payable to affiliates		—			3			—		(3	)		—
Notes payable to affiliates		585			13			35		(633	)		—
Commodity and other derivative contractual liabilities		178			—			2,730		—			2,908
Margin deposits related to commodity positions		—			—			525		—			525
Accumulated deferred income taxes		36			—			—		(36	)		—
Accrued interest		110			87			413		(86	)		524
Other current liabilities		111			—			587		(86	)		612
Total current liabilities		1,031			111			7,446		(1,254	)		7,334
Accumulated deferred income taxes		—			—			6,507		(581	)		5,926
Investment tax credits		—			—			42		—			42
Commodity and other derivative contractual liabilities		—			—			2,095		—			2,095
Notes or other liabilities due affiliates		2,019			—			266		(2,285	)		—
Long-term debt, less amounts due currently		6,340			4,597			34,401		(4,500	)		40,838
Other noncurrent liabilities and deferred credits		388			1			4,817		(1	)		5,205
Total liabilities		9,778			4,709			55,574		(8,621	)		61,440
EFH Corp. shareholders’ equity		(3,532	)		(1,792	)		3,942		(2,150	)		(3,532	)
Noncontrolling interests in subsidiaries		—			—			1,355		—			1,355
Total equity		(3,532	)		(1,792	)		5,297		(2,150	)		(2,177	)
Total liabilities and equity	$	6,246		$	2,917		$	60,871	$	(10,771	)	$	59,263

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Holdings Corp.:

We have reviewed the accompanying condensed consolidated balance sheet of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of June 30, 2009, and the related condensed statements of consolidated income (loss) and comprehensive income (loss) for the three-month and six-month periods ended June 30, 2009 and 2008, and of cash flows for the six-month periods ended June 30, 2009 and 2008. These interim financial statements are the responsibility of EFH 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 Energy Future Holdings Corp. and subsidiaries as of December 31, 2008, and the related statements of consolidated income (loss), comprehensive income (loss), cash flows, and shareholders’ equity for the year then ended (not presented herein); and in our report dated March 2, 2009 (May 20, 2009 as to the effects of the retrospective adoption of SFAS 160) (which report includes an explanatory paragraph related to EFH Corp. completing its merger with Texas Energy Future Merger Sub Corp and becoming a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007, EFH Corp.’s adoption of SFAS 160, the provisions of FASB Staff Position No. FIN 39-1 and reclassification of results of its commodity hedging and trading activities on a retrospective basis), 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, 2008 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 3, 2009

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

The following discussion and analysis of our financial condition and results of operations for the three and six months ended June 30, 2009 and 2008 should be read in conjunction with our consolidated financial statements and the notes to those statements.

All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwise indicated.

BUSINESS

We are a Dallas-based holding company conducting operations principally through our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to further separate Oncor from our other businesses. See Note 1 to Financial Statements for a description of the material features of these “ring-fencing” measures and Note 6 to Financial Statements for discussion of noncontrolling interests sold by Oncor.

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The segment also includes equipment salvage and resale activities related to the cancellation of the development of eight new coal-fueled generation units in 2007; such activities were not material for the periods presented in this Quarterly Report. The Regulated Delivery segment is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary.

See Note 12 to Financial Statements for further information regarding reportable business segments.

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Significant Activities and Events

Long-Term Hedging Program— TCEH has 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, the company has entered into market transactions involving natural gas-related financial instruments, and as of June 30, 2009, has effectively sold forward approximately 1.8 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 230,000 GWh at an assumed 8.0 market heat rate) over the next five years at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.99 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 68% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning July 1, 2009 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which are expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the NYMEX Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for the second half of 2009 period.

Beginning in the second quarter of 2008, the company entered into related put and call transactions (referred to as collars), primarily for year 2014 of the program, that effectively hedge natural gas prices within a range. These transactions represented approximately 5% of the positions in the long-term hedging program at June 30, 2009, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. Financial instruments, including collars, are expected to be employed in future hedging activity under the long-term hedging program.

The following table summarizes the natural gas hedges in the long-term hedging program as of June 30, 2009:

	Measure	Balance 2009 (a)	2010	2011	2012	2013	2014	Total
Natural gas hedge volumes (b)	mm MMBtu	~112	~341	~496	~492	~300	~94	~1,835
Weighted average hedge price (c)	$/MMBtu	~7.99	~7.80	~7.56	~7.36	~7.19	~7.80	—
Weighted average market price (d)	$/MMBtu	~4.39	~6.06	~6.89	~7.16	~7.30	~7.43	—

(a) Balance of 2009 is from July 1, 2009 through December 31, 2009

(b) Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e. delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 94 million MMBtu in 2014.

(c) Weighted average hedge prices are based on sales prices of forward natural gas sales positions in the long-term hedging program based on NYMEX Henry Hub prices. Where collars are reflected, sales price represents the collar floor price.

(d) Based on NYMEX Henry Hub prices.

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Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of June 30, 2009, a $1.00/MMBtu change in natural gas prices across the five-year hedged period would result in the recognition of up to approximately $1.8 billion in pretax unrealized mark-to-market gains or losses.

The reported unrealized mark-to-market net loss related to the long-term hedging program for the three months ended June 30, 2009 totaled $492 million due to an increase in forward prices of natural gas. The reported unrealized net gain for the six months ended June 30, 2009 totaled $665 million due to a net decrease in the forward prices of natural gas. Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost. The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $1.537 billion and $871 million at June 30, 2009 and December 31, 2008, respectively. These values can change materially as market conditions change.

As of June 30, 2009, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility – see discussion below under “Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

The following sensitivity table provides estimates of the potential impact (in $millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of June 30, 2009, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

	Balance 2009 (a)		2010		2011		2012		2013
$1.00/MMBtu change in gas price (b)	$	~9	$	~65	$	~60	$	~115	$	~295
0.1/MWh/MMBtu change in market heat rate (c)	$	~1	$	~25	$	~50	$	~60	$	~60
$1.00/gallon change in diesel fuel price	$	—	$	—	$	—	$	—	$	~50
$10.00/pound change in uranium/nuclear fuel	$	—	$	—	$	—	$	~4	$	~1

(a) Balance of 2009 is from August 1, 2009 through December 31, 2009.

(b) Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas being on the margin 75% to 90% of the time (i.e. when coal is forecast to be on the margin, no natural gas position is assumed to be generated).

(c) Based on Houston Ship Channel natural gas prices as of June 30, 2009.

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TCEH Interest Rate Swap Transactions— As of June 30, 2009, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $17.55 billion principal amount of its senior secured debt maturing from 2009 to 2014. None of these swaps were entered into in 2009. Taking into consideration these swap transactions, approximately 7% of our total long-term debt portfolio at June 30, 2009 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce fixed borrowing costs, related to an aggregate of $17.4 billion principal amount of senior secured debt, including swaps related to $6.45 billion principal amount of debt that were entered into in January through June 2009. In July 2009, TCEH entered into additional interest rate basis swap transactions related to an aggregate $3.1 billion principal amount of senior secured debt. We may enter into additional interest rate hedges from time to time. Unrealized mark-to-market net gains related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $460 million and $665 million for the three and six month periods ended June 30, 2009, respectively. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.3 billion at June 30, 2009, of which $294 million (pre-tax) was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 4 to Financial Statements regarding various interest rate swap transactions.

Texas Generation Facilities Development—TCEH is developing three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in the state of Texas with a total estimated capacity of approximately 2,200 MW. Air permits for construction of all three units have been obtained and considerable progress has been made on the construction of the units. See discussion immediately below regarding the status of the Sandow unit. Oak Grove’s two units are expected to commence commercial operation in late 2009 and mid 2010, respectively. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $2.9 billion was spent as of June 30, 2009. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.5 billion upon completion of the units, and the balance was $4.1 billion as of June 30, 2009. See discussion in Note 5 to Financial Statements under “Litigation Related to Generation Facilities” regarding pending litigation related to the Oak Grove units.

In early July 2009, the Sandow unit synchronized to the ERCOT power grid and produced power for sale to third parties. Despite the challenges from several unforeseen weather events (e.g. Hurricanes Ike and Dolly in 2008) and, more recently, equipment malfunctions that the project has experienced during commissioning and start-up activities, the project’s cost remains on budget, and the expected commercial operation date is Fall 2009. See Note 5 to Financial Statements regarding potential penalties that could be incurred under a federal consent decree if the unit, operating at full capacity, does not meet certain emission rate limits on a sustained basis by August 31, 2009.

Nuclear Generation Development—In September 2008, TCEH filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross) capacity, at its existing Comanche Peak nuclear generation site. In connection with the filing of the application, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. A subsidiary of TCEH owns an 88% interest in the joint venture, and a subsidiary of MHI owns a 12% interest.

In March 2009, the NRC announced an official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by December 2011, and it is expected that a license would be issued approximately one year later.

While TCEH was not one of the initial four applicants selected to receive DOE loan guarantees, it continues to update its DOE loan guarantee application for financing the proposed units.

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Idling of Natural Gas-Fueled Units — In February 2009, we notified ERCOT of plans to retire 11 of our natural gas-fueled units, totaling 2,229 MW of capacity (2,341 MW installed nameplate capacity), in May 2009, and mothball (idle) an additional four units, totaling 1,596 MW of capacity (1,675 MW of installed nameplate capacity), in September 2009. In May 2009, we entered into a reliability-must-run (RMR) agreement for the remainder of 2009 with ERCOT for the operation of one unit originally planned to be retired with 115 MW of capacity (115 MW of installed nameplate capacity). We are also negotiating an RMR agreement with ERCOT for one of the units planned to be mothballed with 515 MW of capacity (540 MW of installed nameplate capacity); if executed, the RMR agreement is expected to begin in September or October 2009. The other units were retired in May 2009 or are scheduled to be mothballed in September 2009 as originally planned. An impairment charge of $229 million related to the carrying value of these units was recorded in the fourth quarter of 2008.

Global Climate Change–Federal Legislation— A number of pieces of legislation dealing with greenhouse gas (GHG) emissions have been proposed recently in the US Congress, including the Waxman-Markey bill, known as the American Clean Energy and Security Act of 2009 (Waxman-Markey). This proposed legislation is not law, but in June 2009, the bill was passed by the US House of Representatives and sent to the US Senate for consideration. President Obama has also expressed support for Waxman-Markey. As currently proposed, Waxman-Markey takes several approaches to address GHG emissions, including establishing renewable energy and energy efficiency standards, establishing performance standards for coal-fueled electricity generation units, and creating an economy-wide cap-and-trade program. The renewable energy and energy efficiency standards would require retail electricity suppliers to meet 6% of their load with renewable energy sources by 2012, increasing to 20% of their load by 2020, some of which could be met by energy efficiency measures. The performance standards for coal-fueled electricity generation units would require a 65% reduction in CO₂ emissions for subject generation units initially permitted after January 1, 2020, and a 50% reduction in CO₂ emissions for subject electricity generation units initially permitted between January 1, 2009 and January 1, 2020 once certain technology deployment criteria are met but no later than January 1, 2025. The cap-and-trade program would require emissions from capped sources, including coal-fueled electricity generation units, to be reduced 3% below 2005 levels by 2012, 17% by 2020, 42% by 2030 and 83% by 2050. The version of Waxman-Markey passed by the US House of Representatives included provisions that allocated a large percentage of the emissions allowances at no charge to various groups that would be impacted by such a cap-and-trade program, including certain merchant coal-fueled generation units. Waxman-Markey remains subject to deliberation and modifications in the US Senate, thereby precluding an estimate of the cost of compliance; however, if Waxman-Markey or similar legislation were to be adopted, our costs of compliance with the law could be material.

In April 2007, the US Supreme Court issued a decision in the case ofMassachusetts v. US Environmental Protection Agency holding that CO₂ and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the federal Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative, provide a reasonable explanation why GHG emissions should not be regulated. In April 2009, the EPA issued a proposed determination finding that six GHGs in the atmosphere were pollutants under the Clean Air Act, the combination of the six GHGs formed air pollution, that this air pollution, through the mechanics of climate change, endangers public health and welfare, and that the emission of four of these GHGs by motor vehicles contributes to this air pollution and thereby the threat of climate change. Although this “endangerment finding” is in draft form and applies only to GHG emissions from motor vehicle engines, some of the GHGs that are the subject of the proposed endangerment finding are produced by the combustion of fossil fuels by other sources as well, including fossil-fueled electricity generation units. The public comment period for the proposed endangerment finding ended in June 2009. The EPA must now decide whether to issue a final endangerment finding, and whether it will proceed with the rulemaking process to promulgate regulations related to the finding. If such regulations are adopted, costs of compliance with such regulations could be material.

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Oncor Technology Initiatives— Oncor continues to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. As of June 30, 2009, Oncor has installed approximately 240 thousand advanced digital meters, including approximately 200 thousand in the six months ended June 30, 2009. Cumulative capital expenditures for the deployment of the advanced meter system totaled $108 million as of June 30, 2009. In July 2009, Oncor’s advanced metering system completed its first 15-minute interval, billing-quality electricity consumption data reporting to the Texas market. The data, which makes it possible to support innovative new programs and pricing options, represented information technology integration of over 200,000 advanced meters.

In July 2009, Oncor applied to the US Department of Energy for approximately $317 million in stimulus funds to advance its modernized grid initiatives. The funds are available through the American Recovery and Reinvestment Act of 2009. Oncor expects to account for funds received, if any, as contributions in aid of construction, reducing the amount capitalized as property, plant and equipment. In its applications, Oncor requested:

• $200 million to lower the cost for its advanced metering system initiative,

• More than $58 million for telecommunications and network investments to support the modernized grid initiatives, and

• More than $58 million for distribution automation to improve service and reliability.

Oncor Matters with the PUCT —See discussion of these matters, including the awarded construction of $1.3 billion of transmission lines and a rate case with the PUCT, below under “Regulation and Rates.”

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RESULTS OF OPERATIONS

Consolidated Financial Results — Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

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

Operating revenues decreased $609 million, or 21%, to $2.342 billion in 2009.

• Operating revenues in the Competitive Electric segment decreased $622 million, or 24%, to $1.945 billion.

• Operating revenues in the Regulated Delivery segment increased $27 million, or 4%, to $653 million.

• Net intercompany sales eliminations increased $14 million reflecting higher sales by Oncor to REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees decreased $716 million, or 51%, to $700 million in 2009. See discussion below in the analysis of Competitive Electric segment results of operations.

Net gain (loss) from commodity hedging and trading activities totaled $248 million in net losses in 2009 compared to $4.727 billion in net losses in 2008. Results in 2009 included unrealized mark-to-market net losses totaling $300 million, driven by the effect of an increase in forward market prices of natural gas on positions in the long-term hedging program. See discussion above under “Long-Term Hedging Program” and below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $5 million, or 1%, to $395 million in 2009.

• Operating costs in the Competitive Electric segment decreased $10 million, or 5%, to $174 million.

• Operating costs in the Regulated Delivery segment increased $13 million, or 6%, to $221 million.

Depreciation and amortization increased $33 million, or 8%, to $423 million in 2009.

• Depreciation and amortization in the Competitive Electric segment increased $21 million, or 8%, to $283 million.

• Depreciation and amortization in the Regulated Delivery segment increased $11 million, or 9%, to $132 million.

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SG&A expenses increased $23 million, or 9%, to $270 million in 2009.

• SG&A expenses in the Competitive Electric segment increased $21 million, or 12%, to $192 million.

• SG&A expenses in the Regulated Delivery segment increased $1 million, or 2%, to $44 million.

• Corporate and Other SG&A expenses increased $1 million, or 3%, to $34 million.

Other income totaled $13 million in 2009 and $15 million in 2008, including $10 million and $11 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. Other deductions totaled $7 million in 2009 and $26 million in 2008. See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges decreased $400 million to $431 million in 2009 reflecting a $460 million unrealized mark-to-market net gain related to interest rate swaps, which was partially offset by $44 million in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008. The change in interest expense also reflected $34 million in higher average rates, offset by $10 million in lower average borrowings and $8 million in increased capitalized interest. See Note 13 to Financial Statements.

Income tax benefit totaled $48 million in 2009 compared to an income tax benefit of $1.803 billion in 2008. The effective rates on losses were 25.7% and 35.1% in 2009 and 2008, respectively. The decrease in the benefit rate reflects higher interest accrued for uncertain tax positions on a significantly lower loss in 2009 compared to 2008.

Net loss decreased $3.192 billion to $139 million in 2009.

• Results in the Competitive Electric segment increased $3.179 billion to a net loss of $78 million.

• Earnings in the Regulated Delivery segment decreased $3 million to $82 million.

Corporate and Other net expenses totaled $143 million in 2009 and $159 million in 2008. The amounts in 2009 and 2008 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The decrease of $16 million reflects:

• $8 million in interest income related to a collateral funding transaction with counterparties to certain interest rate swap agreements (see Note 4 to Financial Statements), and

• a $7 million increase in income tax benefit reflecting timing of recognition of state income tax expense, partially offset by an increase in interest accrued for uncertain tax positions.

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Consolidated Financial Results — Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

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

Operating revenues decreased $824 million, or 16%, to $4.481 billion in 2009.

• Operating revenues in the Competitive Electric segment decreased $839 million, or 18%, to $3.711 billion.

• Operating revenues in the Regulated Delivery segment increased $25 million, or 2%, to $1.266 billion.

• Net intercompany sales eliminations increased $10 million, reflecting higher sales by Oncor to REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees decreased $936 million, or 42%, to $1.301 billion in 2009. See discussion below in the analysis of Competitive Electric segment results of operations.

Net gain (loss) from commodity hedging and trading activities totaled $880 million in net gains in 2009 compared to $6.293 billion in net losses in 2008. Results in 2009 included unrealized mark-to-market net gains totaling $749 million, driven by the effect of a decrease in forward market prices of natural gas on positions in the long-term hedging program. See discussion above under “Long-Term Hedging Program” and below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $35 million, or 5%, to $783 million in 2009.

• Operating costs in the Competitive Electric segment increased $1 million, or less than 1%, to $343 million.

• Operating costs in the Regulated Delivery segment increased $34 million, or 8%, to $441 million.

Depreciation and amortization increased $45 million, or 6%, to $830 million in 2009.

• Depreciation and amortization in the Competitive Electric segment increased $28 million, or 5%, to $559 million.

• Depreciation and amortization in the Regulated Delivery segment increased $16 million, or 7%, to $258 million.

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SG&A expenses increased $52 million, or 11%, to $516 million in 2009.

• SG&A expenses in the Competitive Electric segment increased $38 million, or 12%, to $363 million.

• SG&A expenses in the Regulated Delivery segment increased $5 million, or 6%, to $88 million.

• Corporate and Other SG&A expenses increased $9 million, or 16%, to $65 million largely driven by $8 million in consulting expenses primarily associated with the transition of outsourced support services.

See Note 2 to Financial Statements for discussion of the $90 million additional impairment of goodwill.

Other income totaled $26 million in 2009 and $29 million in 2008, including $20 million and $22 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. Other deductions totaled $18 million in 2009 and $42 million in 2008. See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges decreased $578 million to $1.096 billion in 2009 reflecting a $665 million unrealized mark-to-market net gain related to interest rate swaps, which was partially offset by $84 million in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges. Increased interest expense of $19 million due to higher average borrowings and $11 million due to higher average interest rates was largely offset by a $27 million increase in capitalized interest. See Note 13 to Financial Statements.

Income tax expense totaled $285 million in 2009 compared to an income tax benefit of $2.463 billion in 2008. The effective rate on income in 2009 was 47.5% and the effective rate on a loss in 2008 was 34.9%. The increase in the rate reflects the non-deductible goodwill impairment in 2009 and a decrease in the lignite depletion deduction due to increased usage of purchased coal. In addition, higher interest accrued on uncertain tax positions increased the rate on income in 2009 and decreased the rate on a loss in 2008.

Results increased $4.915 billion to $315 million in net income in 2009.

• Results in the Competitive Electric segment increased $4.953 billion to $479 million.

• Earnings in the Regulated Delivery segment decreased $30 million to $140 million.

• Corporate and Other net expenses totaled $304 million in 2009 and $296 million in 2008. The amounts in 2009 and 2008 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The increase of $8 million reflected the $20 million goodwill impairment discussed above, partially offset by $9 million in interest income related to a collateral funding transaction with counterparties to certain interest rate swap agreements (see Note 4 to Financial Statements).

61

Competitive Electric Segment

Financial Results

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues	$	1,945		$	2,567		$	3,711		$	4,550
Fuel, purchased power costs and delivery fees		(957	)		(1,658	)		(1,800	)		(2,723	)
Net gain (loss) from commodity hedging and trading activities		(248	)		(4,727	)		880			(6,293	)
Operating costs		(174	)		(184	)		(343	)		(342	)
Depreciation and amortization		(283	)		(262	)		(559	)		(531	)
Selling, general and administrative expenses		(192	)		(171	)		(363	)		(325	)
Franchise and revenue-based taxes		(22	)		(24	)		(46	)		(49	)
Impairment of goodwill		—			—			(70	)		—
Other income		2			3			5			6
Other deductions		(5	)		(17	)		(16	)		(27	)
Interest income		12			15			19			26
Interest expense and related charges		(191	)		(599	)		(617	)		(1,219	)
Income (loss) before income taxes		(113	)		(5,057	)		801			(6,927	)
Income tax (expense) benefit		35			1,800			(322	)		2,453
Net income (loss)	$	(78	)	$	(3,257	)	$	479		$	(4,474	)

62

Competitive Electric Segment

Sales Volume and Customer Count Data

	Three Months Ended June 30,				% Change		Six Months Ended June 30,				% Change
	2009		2008				2009		2008
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential	7,084		6,941		2.1		12,964		13,055		(0.7	)
Small business (a)	1,908		1,867		2.2		3,629		3,561		1.9
Large business and other customers	3,551		3,574		(0.6	)	6,857		6,913		(0.8	)
Total retail electricity	12,543		12,382		1.3		23,450		23,529		(0.3	)
Wholesale electricity sales volumes	10,262		12,568		(18.3	)	20,053		23,058		(13.0	)
Net sales (purchases) of balancing electricity to/from ERCOT	(112	)	(1,236	)	—		(265	)	(1,480	)	—
Total sales volumes	22,693		23,714		(4.3	)	43,238		45,107		(4.1	)
Average volume (kWh) per retail customer (b):
Residential	3,688		3,700		(0.3	)	6,777		6,987		(3.0	)
Small business	6,891		6,877		0.2		13,126		13,011		0.9
Weather (service territory average) – percent of normal (c):
Cooling degree days	105.6	%	120.8	%	(12.6	)	110.6	%	123.8	%	(10.7	)
Heating degree days	112.9	%	90.9	%	24.2		89.3	%	93.9	%	(4.9	)
Customer counts:
Retail electricity customers (end of period and in thousands) (d):
Residential							1,911		1,880		1.6
Small business (a)							279		274		1.8
Large business and other customers							21		28		(25.0	)
Total retail electricity customers							2,211		2,182		1.3

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

(b) Calculated using average number of customers for the 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).

(d) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers. June 30, 2008 amounts reflect a reclassification of 19 thousand meters from residential to small business to conform to current presentation.

63

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Three Months Ended June 30,						% Change		Six Months Ended June 30,						% Change
	2009			2008					2009			2008
Operating revenues:
Retail electricity revenues:
Residential	$	984		$	937		5.0		$	1,776		$	1,708		4.0
Small business (a)		295			274		7.7			558			518		7.7
Large business and other customers		310			379		(18.2	)		625			695		(10.1	)
Total retail electricity revenues		1,589			1,590		(0.1	)		2,959			2,921		1.3
Wholesale electricity revenues (b)		314			1,037		(69.7	)		663			1,663		(60.1	)
Net sales (purchases) of balancing electricity to/from ERCOT		(22	)		(148	)	85.1			(45	)		(184	)	75.5
Amortization of intangibles (c)		1			(11	)	—			(10	)		(41	)	75.6
Other operating revenues		63			99		(36.4	)		144			191		(24.6	)
Total operating revenues	$	1,945		$	2,567		(24.2	)	$	3,711		$	4,550		(18.4	)
Commodity hedging and trading activities:
Unrealized net gains (losses) from changes in fair value	$	(265	)	$	(4,768	)	—		$	890		$	(6,305	)	—
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the current period		(35	)		(31	)	(12.9	)		(141	)		(88	)	(60.2	)
Realized net gains (losses) on settled positions		52			72		(27.8	)		131			100		31.0
Total gain (loss)	$	(248	)	$	(4,727	)	—		$	880		$	(6,293	)	—

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

(b) Upon settlement of physical derivative power sales and purchase contracts that are accounted for on a mark-to-market basis, wholesale electricity revenues and natural gas fuel and purchase power expense are reported at approximated market prices instead of the contract price, as required by accounting rules. As a result, physically settled contract amounts include a noncash component, which the company refers to as “unrealized.” For the three months ended June 30, 2009 and 2008, these amounts totaled $63 million in net losses and $79 million in net gains, respectively, reported in wholesale electricity revenues, and $43 million in net gains and $49 million in net losses, respectively, reported in natural gas fuel and purchased power expense. For the six months ended June 30, 2009 and 2008, these amounts totaled $123 million in net losses and $79 million in net gains, respectively, reported in wholesale electricity revenues, and $84 million in net gains and $49 million in net losses, respectively, reported in natural gas fuel and purchased power expense.

(c) Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting from purchase accounting.

64

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Three Months Ended June 30,						% Change		Six Months Ended June 30,						% Change
	2009			2008					2009			2008
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	29		$	21		38.1		$	58		$	44		31.8
Lignite/coal		147			158		(7.0	)		299			313		(4.5	)
Total baseload fuel		176			179		(1.7	)		357			357		—
Natural gas fuel and purchased power (a)		302			966		(68.7	)		521			1,371		(62.0	)
Amortization of intangibles (b)		70			77		(9.1	)		140			159		(11.9	)
Other costs		49			114		(57.0	)		107			210		(49.0	)
Fuel and purchased power costs		597			1,336		(55.3	)		1,125			2,097		(46.4	)
Delivery fees (c)		360			322		11.8			675			626		7.8
Total	$	957		$	1,658		(42.3	)	$	1,800		$	2,723		(33.9	)
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	5.68		$	4.69		21.1		$	5.62		$	4.65		20.9
Lignite/coal (d)		16.03			16.62		(3.5	)		16.47			16.09		2.4
Natural gas fuel and purchased power		39.31			93.78		(58.1	)		41.14			83.11		(50.5	)
Delivery fees per MWh	$	28.44		$	25.83		10.1		$	28.51		$	26.30		8.4
Production and purchased power volumes (GWh):
Nuclear		5,103			4,531		12.6			10,293			9,452		8.9
Lignite/coal		10,450			10,505		(0.5	)		20,705			21,457		(3.5	)
Total baseload generation		15,553			15,036		3.4			30,998			30,909		0.3
Natural gas-fueled generation		775			1,192		(35.0	)		1,033			1,718		(39.9	)
Purchased power		6,904			9,105		(24.2	)		11,633			14,775		(21.3	)
Total energy supply		23,232			25,333		(8.3	)		43,664			47,402		(7.9	)
Line loss and power imbalances		539			1,619		(66.7	)		426			2,295		(81.4	)
Net energy supply volumes		22,693			23,714		(4.3	)		43,238			45,107		(4.1	)
Baseload capacity factors (%):
Nuclear		101.8	%		90.3	%	12.7			103.2	%		94.2	%	9.6
Lignite/coal		82.0	%		82.1	%	(0.1	)		81.7	%		84.0	%	(2.7	)
Total baseload		87.6	%		84.4	%	3.8			87.8	%		86.9	%	1.0

(a) See note (b) on previous page.

(b) Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.

(c) Includes delivery fee charges from Oncor that are eliminated in consolidation.

(d) 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.

65

Competitive Electric Segment — Financial Results — Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

Operating revenues decreased $622 million, or 24%, to $1.945 billion in 2009.

Wholesale electricity revenues decreased $723 million, or 70%, as compared to 2008, when wholesale revenues increased 94%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 63% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove an 18% decrease in sales volumes. Realized gains in 2009 on hedging activities mitigated the effect of lower wholesale electricity prices (see discussion of results from commodity hedging and trading activities below).

Retail electricity revenues of $1.589 billion in 2009 represented a decline of $1 million from 2008 and reflected the following:

• Lower average pricing, principally in the contract business markets, contributed $22 million to the revenue decline. The change in average pricing reflected lower average contracted business rates driven by lower wholesale electricity prices, partially offset by higher average pricing in the residential and non-contract business markets resulting from advanced meter surcharges as well as changes in customer mix.

• A one percent increase in retail sales volumes increased revenues by $21 million. Volume increases of 2% in both the residential and small business markets reflected higher customer counts, while large business market volumes decreased 1% due to general economic conditions, somewhat offset by customer mix.

• Total retail electricity customer count at June 30, 2009 increased one percent from June 30, 2008 driven by a two percent increase in the residential and small business markets.

In July 2009, we announced retail residential price reductions of as much as 15% applicable to over 250,000 existing customers on month-to-month plans as well as reductions on offerings for new customers. The price reductions, which are effective in August 2009, reflect declines in wholesale electricity prices.

Bilateral electricity contracting activity includes hedging transactions that utilize contracts for physical delivery. Wholesale sales and purchases of electricity are reported gross in the income statement if the transactions are scheduled for physical delivery with ERCOT.

Wholesale balancing activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable and in 2009 reflected reduced volatility and congestion, in part due to actions taken by ERCOT.

Other operating revenues decreased $36 million, or 36%, to $63 million in 2009 due to the effect of lower natural gas prices and lower volumes on sales of natural gas to retail industrial customers.

The change in operating revenues also reflected a $12 million reduction in amortization of intangible assets arising in purchase accounting.

66

Fuel, purchased power costs and delivery fees decreased $701 million, or 42%, to $957 million in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages resulted in improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($150 million), the effect of lower natural gas prices and volumes on natural gas purchased for sale to retail industrial customers ($47 million) and lower amortization of intangible assets arising in purchase accounting ($7 million).

Overall baseload generation production increased 3% in 2009 reflecting a 13% increase in nuclear production, partially offset by a 1% decrease in lignite/coal-fueled production. The increase in nuclear production, which reflects a refueling outage in 2008, resulted in improved margin.

Net gain (loss) from commodity hedging and trading activities include realized and unrealized gains and losses associated with financial instruments used for commodity hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading and hedging purposes. A substantial majority of the commodity hedging activities are intended to mitigate the risk of commodity price movements on future revenues and involve natural gas positions entered into as part of the long-term hedging program. The results of these activities have been volatile because of the effects of movements in forward natural gas prices on unrealized mark-to-market valuations. Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the three months ended June 30, 2009 and 2008:

Three Months Ended June 30, 2009 —Unrealized mark-to-market net losses totaling $300 million included:

• $328 million in net losses related to hedge positions, which includes $272 million in net losses from changes in fair value, a $3 million day one loss related to a commodity hedging position (see Note 7 to Financial Statements) and $53 million in net losses that represent reversals of previously recorded fair values of positions settled in the period, and

• $28 million in net gains related to trading positions, which includes $10 million in net gains from changes in fair value and $18 million in net gains that represent reversals of previously recorded fair values of positions settled in the period.

Realized net gains totaling $52 million include:

• $64 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

• $12 million in net losses related to trading positions.

Three Months Ended June 30, 2008— Unrealized mark-to-market net losses totaling $4.799 billion include:

• $4.754 billion in net losses related to hedge positions, which includes $4.752 billion in net losses from changes in fair values and $2 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

• $39 million in “day one” losses related to large hedge positions (see Note 7 to Financial Statements), and

• $4 million in net losses related to trading positions, which includes $25 million in net gains from changes in fair value and $29 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.

67

Realized net gains totaling $72 million include:

• $44 million in net gains related to positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and

• $29 million in net gains related to trading positions.

Operating costs decreased $10 million, or 5%, to $174 million in 2009. The decrease reflected $13 million in 2008 maintenance costs incurred for a planned nuclear generation unit outage and a $4 million decrease in property taxes, partially offset by $5 million in operational readiness costs incurred in preparation for new lignite-fueled plant start-up and $2 million in higher maintenance costs incurred during lignite-fueled outages in 2009.

Depreciation and amortization increased $21 million, or 8%, to $283 million in 2009. The increase represents incremental amortization expense related to the intangible value of retail customer relationships ($10 million), increased lignite/coal-fueled plant depreciation and increased mining-related asset retirement obligations, partially offset by lower natural gas plant depreciation resulting from the natural gas plant impairment in late 2008.

SG&A expenses increased $21 million, or 12%, to $192 million in 2009. The increase reflected $11 million in higher transition costs associated with implementing a new customer information management system and insourcing call center operations, $7 million in higher retail bad debt expense and $1 million in costs related to the nuclear generation development joint venture.

Interest income decreased $3 million, or 20%, to $12 million in 2009 reflecting lower average loans to affiliates.

Interest expense and related charges decreased by $408 million, or 68%, to $191 million in 2009 reflecting a $460 million unrealized mark-to-market gain related to interest rate swaps, which was partially offset by $44 million in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008. The change in interest expense also reflected $31 million in higher average interest rates, partially offset by $16 million in lower average borrowings and $7 million in increased capitalized interest.

Income tax benefit totaled $35 million in 2009 compared to income tax benefit of $1.8 billion in 2008. The effective benefits rates were 31.0% in 2009 and 35.6% in 2008. The rate decrease reflects higher interest accrued for uncertain tax positions on a significantly lower loss in 2009.

Results improved $3.179 billion to net loss of $78 million in 2009, driven by the decrease in unrealized mark-to-market net losses related to commodity hedging activities and the unrealized net gains related to interest rate swaps.

68

Competitive Electric Segment — Financial Results — Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Operating revenues decreased $839 million, or 18%, to $3.711 billion in 2009.

Wholesale electricity revenues decreased $1.0 billion, or 60%, as compared to 2008 when revenues increased 69%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 54% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove a 13% decline in wholesale sales volumes. Realized gains in 2009 on hedging activities mitigated the effect of lower wholesale electricity prices (see discussion of results from commodity hedging and trading activities below).

A $38 million, or 1%, increase in retail electricity revenues reflected the following:

• Higher average pricing, principally in residential and non-contract business markets, contributed $48 million to the revenue increase. The change in average pricing reflected price increases due to higher contracted power supply costs and higher delivery fees resulting from advanced meter surcharges, as well as changes in customer mix.

• A slight decline in retail sales volumes reduced revenues by $10 million. Residential volumes declined 1% as the effect on usage of a decrease in cooling and heating degree days was partially offset by higher customer counts. Small business volumes increased 2% on higher customer counts, while large business market volumes decreased 1% due to general economic conditions, somewhat offset by customer mix.

Bilateral electricity contracting activity includes hedging transactions that utilize contracts for physical delivery. Wholesale sales and purchases of electricity are reported gross in the income statement if the transactions are scheduled for physical delivery with ERCOT.

Wholesale balancing activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable and in 2009 reflected reduced volatility and congestion, in part due to actions taken by ERCOT.

Other operating revenues decreased $47 million, or 25%, to $144 million in 2009 due to the effect of lower natural gas prices and volumes on sales of natural gas to retail industrial customers.

The change in operating revenues also reflected a $31 million reduction in amortization of intangible assets arising in purchase accounting.

Fuel, purchased power costs and delivery fees decreased $923 million, or 34%, to $1.8 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($189 million), the effect of lower natural gas prices on natural gas purchased for sale to retail industrial customers ($77 million) and lower amortization of intangible assets arising in purchase accounting ($19 million).

69

Overall baseload generation production increased slightly in 2009 reflecting a 9% increase in nuclear production, partially offset by a 4% decrease in lignite/coal-fueled production. The increase in nuclear production, which reflects a refueling outage in 2008, resulted in improved margin. The decrease in lignite/coal-fueled production reflected reductions during certain periods when power could be purchased in the wholesale market at prices below production costs, which was largely due to lower natural gas prices and higher wind generation availability, partially offset by lower maintenance and repair outages.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the six months ended June 30, 2009 and 2008:

Six Months Ended June 30, 2009 —Unrealized mark-to-market net gains totaling $749 million included:

• $754 million in net gains related to hedge positions, which includes $892 million in net gains from changes in fair value, a $3 million day one loss related to a commodity hedging position (see Note 7 to Financial Statements) and $135 million in net losses that represent reversals of previously recorded fair values of positions settled in the period, and

• $5 million in net losses related to trading positions, which includes $1 million in net gains from changes in fair value and $6 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.

Realized net gains totaling $131 million include:

• $137 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

• $6 million in net losses related to trading positions.

Six Months Ended June 30, 2008— Unrealized mark-to-market net losses totaling $6.393 billion include:

• $6.337 billion in net losses related to hedge positions, which includes $6.318 billion in net losses from changes in fair values and $19 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

• $58 million in “day one” losses related to large hedge positions (see Note 7 to Financial Statements), and

• $6 million in net gains related to trading positions, which includes $75 million in net gains from changes in fair value and $69 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.

Realized net gains totaling $100 million include:

• $29 million in net gains related to hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and

• $71 million in net gains related to trading positions.

Operating costs increased $1 million, or less than 1%, to $343 million in 2009. The increase reflected $10 million in higher maintenance costs incurred during planned and unplanned lignite-fueled plant outages in 2009, $9 million in operational readiness costs incurred in preparation for new lignite-fueled plant start-up and $4 million related to timing and scope of nuclear and natural gas-fueled plant base maintenance costs, partially offset by the effect of $22 million in 2008 maintenance costs incurred for a planned nuclear generation unit outage.

70

Depreciation and amortization increased $28 million, or 5%, to $559 million in 2009. The increase represents incremental amortization expense related to the intangible value of retail customer relationships ($18 million), increased lignite/coal-fueled plant depreciation and increased mining-related reclamation obligations depreciation, partially offset by lower natural gas plant depreciation resulting from the natural gas plant impairment in late 2008.

SG&A expenses increased $38 million, or 12%, to $363 million in 2009. The increase reflected $18 million in higher transition costs associated with the implementation of a new retail customer information management system and insourcing call center operations, $11 million in higher retail bad debt expense, $4 million in higher employee-related expenses in wholesale operations and $3 million in costs related to the nuclear generation development joint venture.

See Note 2 to Financial Statements for discussion of the additional impairment of goodwill of $70 million.

Other income totaled $5 million in 2009 and $6 million in 2008. Other deductions totaled $16 million in 2009 and $27 million in 2008. See Note 13 to Financial Statements for more details.

Interest income decreased $7 million, or 27%, to $19 million in 2009 reflecting lower average loans to affiliates.

Interest expense and related charges decreased by $602 million, or 49%, to $617 million in 2009 reflecting a $665 million unrealized mark-to-market net gain related to interest rate swaps, which was partially offset by $84 million in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges. The change in interest expense also reflected $27 million in increased capitalized interest and $6 million in lower average rates, partially offset by $12 million in higher average borrowings. Lower average interest rates reflected higher borrowings under credit facilities and the benefits of interest rate basis swaps.

Income tax expense totaled $322 million in 2009 compared to an income tax benefit of $2.453 billion in 2008. The effective rate was 40.2% on income in 2009 and 35.4% on a loss in 2008. The increase in the rate reflected the non-deductible goodwill impairment in 2009 and a decrease in the lignite depletion deduction due to increased usage of purchased coal. The rate increase also reflected higher interest accrued for uncertain tax positions on income in 2009 compared to a loss in 2008.

Results increased $4.953 billion to net income of $479 million in 2009, driven by unrealized mark-to-market net gains related to commodity hedging activities, compared to unrealized net losses in 2008, and unrealized mark-to-market net gains related to interest rate swaps, partially offset by a charge for the impairment of goodwill.

71

Regulated Delivery Segment

Financial Results

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues	$	653		$	626		$	1,266		$	1,241
Operating costs		(221	)		(208	)		(441	)		(407	)
Depreciation and amortization		(132	)		(121	)		(258	)		(242	)
Selling, general and administrative expenses		(44	)		(43	)		(88	)		(83	)
Franchise and revenue-based taxes		(58	)		(58	)		(118	)		(119	)
Other income		10			11			20			22
Other deductions		(1	)		(8	)		(4	)		(15	)
Interest income		10			11			19			22
Interest expense and related charges		(87	)		(73	)		(171	)		(149	)
Income before income taxes		130			137			225			270
Income tax expense (a)		(48	)		(52	)		(85	)		(100	)
Net income	$	82		$	85		$	140		$	170

(a) Effective with the sale of noncontrolling interests (see Note 6 to Financial Statements), Oncor is taxed as a partnership and thus not subject to income taxes; however, subsequent to the sale, Oncor reflects a “provision in lieu of income taxes,” and the results of segments are evaluated as if they were stand-alone entities filing income tax returns.

Operating Data

	Three Months Ended June 30,		% Change		Six Months Ended June 30,		% Change
	2009	2008			2009	2008
Operating statistics:
Electric energy billed volumes (GWh)	23,944	25,593	(6.4	)	48,171	51,248	(6.0	)
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)					80.2	85.3	(6.0	)
System Average Interruption Frequency Index (SAIFI) (nonstorm)					1.1	1.2	(8.3	)
Customer Average Interruption Duration Index (CAIDI) (nonstorm)					72.9	73.9	(1.4	)
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)					3,137	3,108	0.9

	Three Months Ended June 30,				% Change		Six Months Ended June 30,				% Change
	2009		2008				2009		2008
Operating revenues:
Electricity distribution revenues (b):
Affiliated (TCEH)	$	246	$	241	2.1		$	474	$	483	(1.9	)
Nonaffiliated		324		307	5.5			626		605	3.5
Total distribution revenues		570		548	4.0			1,100		1,088	1.1
Third-party transmission revenues		75		69	8.7			149		135	10.4
Other miscellaneous revenues		8		9	(11.1	)		17		18	(5.6	)
Total operating revenues	$	653	$	626	4.3		$	1,266	$	1,241	2.0

(a) SAIDI is the average number of minutes electric service is interrupted 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 twelve months ended June 30, 2009 and 2008 data.

(b) Includes transition charge revenue associated with the issuance of securitization bonds totaling $37 million and $34 million for the three months ended June 30, 2009 and 2008, respectively, and $69 million and $68 million for the six months ended June 30, 2009 and 2008, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

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Financial Results — Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

Operating revenues increased $27 million, or 4%, to $653 million in 2009. The increase reflected:

• $12 million from increased distribution tariffs to recover higher transmission costs;

• $5 million in higher transmission revenues primarily due to a rate increase to recover ongoing investment in the transmission system;

• an estimated $4 million impact of growth in points of delivery;

• $4 million in higher charges to REPs related to transition bonds (with a related increase in amortization of the related regulatory asset), and

• $4 million from a surcharge to recover advanced metering deployment costs and $2 million from a surcharge to recover additional energy efficiency costs, both of which became effective with the January 2009 billing cycle,

partially offset by an estimated $6 million in lower average consumption primarily due to the effects of milder weather and general economic conditions.

Operating costs increased $13 million, or 6%, to $221 million in 2009. The increase reflected $12 million in higher fees paid to other transmission entities and $2 million in costs related to programs designed to improve customer electricity demand efficiencies, both of which have related revenue increases.

Depreciation and amortization increased $11 million, or 9%, to $132 million in 2009. The increase reflected $7 million in higher depreciation due to ongoing investments in property, plant and equipment and $4 million in higher amortization of the regulatory assets associated with the securitization bonds (with a related increase in revenues).

SG&A expenses increased $1 million, or 2%, to $44 million in 2009. The increase reflected higher professional fees driven by outsourcing transitions and CREZ development and losses on certain benefit plan investments, largely offset by a $3 million one-time reversal of bad debt expense due to the PUCT’s finalization of the Certification of Retail Electric Providers rule in April 2009. Write-offs of uncollectible amounts owed by nonaffiliated REPs are deferred as a regulatory asset (see “Regulation and Rates”).

Other income totaled $10 million in 2009 and $11 million in 2008. The amounts reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. See “Oncor’s Regulatory Assets and Liabilities” in Note 13 to Financial Statements for additional information.

Other deductions totaled $1 million in 2009 and $8 million in 2008. The 2008 amount included costs totaling $7 million associated with the 2006 settlement with certain cities related to rates.

Interest income decreased $1 million, or 9%, to $10 million in 2009. The decline reflected a decrease in reimbursement of transition bond interest from TCEH reflecting lower remaining principal amounts of the bonds.

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Interest expense increased $14 million, or 19%, to $87 million in 2009. The increase reflected $8 million due to higher average interest rates, which was driven by refinancing of short-term borrowings with $1.5 billion of senior secured notes issued in September 2008. The majority of the proceeds of the September 2008 notes issuance was used to pay outstanding short-term borrowings under Oncor’s credit facility. The increase also reflected $5 million in higher average borrowings, reflecting ongoing capital investments.

Income tax expense totaled $48 million in 2009 compared to $52 million in 2008. The effective rate decreased to 36.9% in 2009 from 38.0% in 2008. The decreased rate was driven by the effect of investment gains and losses on certain employee benefit plans, which are excluded in determining taxable income.

Net income decreased $3 million, or 4%, to $82 million in 2009 driven by the effect of lower average consumption on revenues as well as increased interest expense.

Financial Results — Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Operating revenues increased $25 million, or 2%, to $1.266 billion in 2009. The increase reflected:

• $21 million from increased distribution tariffs to recover higher transmission costs;

• $15 million in higher transmission revenues primarily due to a rate increase to recover ongoing investment in the transmission system;

• an estimated $8 million impact of growth in points of delivery, and

• $6 million from a surcharge to recover advanced metering deployment costs and $5 million from a surcharge to recover additional energy efficiency costs, both of which became effective with the January 2009 billing cycle,

partially offset by an estimated $25 million in lower average consumption primarily due to the effects of milder weather and general economic conditions.

Operating costs increased $34 million, or 8%, to $441 million in 2009. The increase reflected $26 million in higher fees paid to other transmission entities and $5 million in costs related to programs designed to improve customer electricity demand efficiencies, both of which have related revenue increases. The increase also includes $3 million in labor costs to meet enhanced service terms and conditions

Depreciation and amortization increased $16 million, or 7%, to $258 million in 2009. The increase reflected higher depreciation due to ongoing investments in property, plant and equipment.

SG&A expenses increased $5 million, or 6%, to $88 million in 2009. The increase reflected $4 million in higher professional fees driven primarily by outsourcing transition and CREZ development and $3 million in losses on certain benefit plans, partially offset by a $3 million one-time reversal of bad debt expense due to the PUCT’s finalization of the Certification of Retail Electric Providers rule in April 2009.

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Other income totaled $20 million in 2009 and $22 million in 2008. The amounts reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. See “Oncor’s Regulatory Assets and Liabilities” in Note 13 to Financial Statements for additional information.

Other deductions totaled $4 million in 2009 and $15 million in 2008. The 2009 and 2008 amounts included costs totaling $1 million and $13 million, respectively, associated with the 2006 settlement with certain cities related to rates.

Interest income decreased $3 million, or 14%, to $19 million in 2009. The decline reflected a decrease in reimbursement of transition bond interest from TCEH reflecting lower remaining principal amounts of the bonds and lower investment gains on assets held for employee benefit plans.

Interest expense increased $22 million, or 15%, to $171 million in 2009. The increase reflected $12 million due to higher average interest rates, which was driven by refinancing of short-term borrowings with $1.5 billion of senior secured notes issued in September 2008. The majority of the proceeds of the September 2008 notes issuance was used to pay outstanding short-term borrowings under Oncor’s credit facility. The increase also included a $10 million effect of higher average borrowings, reflecting ongoing capital investments.

Income tax expense totaled $85 million in 2009 compared to $100 million in 2008. The effective rate increased to 37.8% in 2009 from 37.0% in 2008. The increased rate was driven by the effect of investment gains and losses on certain employee benefit plans, which are excluded in determining taxable income.

Net income decreased $30 million, or 18%, to $140 million in 2009 driven by the effect of lower average consumption on revenues as well as increased interest expense.

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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, 2009. The net change in these assets and liabilities totaling $709 million, excluding “other activity” as described below, represents the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 7 to Financial Statements). These positions represent both economic hedging and trading activities.

	Six Months Ended June 30, 2009
Commodity contract net asset (liability) at beginning of period	$	430
Settlements of positions (a)		(181	)
Unrealized mark-to-market valuations due to changes in fair value (b)		890
Other activity (c)		40
Commodity contract net asset (liability) at end of period (d)	$	1,179

(a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period).

(b) Primarily represents mark-to-market effects of positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”).

(c) This amount does not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration.

(d) Excludes $12 million net liability associated with positions accounted for as cash flow hedges, including amounts reported in accumulated other comprehensive income related to transactions that have been dedesignated as cash flow hedges. See Note 7 to Financial Statements for additional discussion of commodity contracts assets and liabilities.

In addition to the effect on net income 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 positions accounted for as cash flow hedges. These effects on net income, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are reflected in the balance sheet as changes in cash flow hedge and other derivative assets and liabilities (see Note 7 to Financial Statements). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts under SFAS 133 is summarized as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009		2008
Unrealized gains/(losses) related to contracts marked-to-market	$	(321	)	$	(4,767	)	$	709	$	(6,359	)
Ineffectiveness gains/losses related to cash flow hedges		1			(2	)		1		(4	)
Total unrealized gains (losses) related to commodity contracts	$	(320	)	$	(4,769	)	$	710	$	(6,363	)

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The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of June 30, 2009, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract asset at June 30, 2009
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(147	)	$	(84	)	$	(3	)	$	—		$	(234	)
Prices provided by other external sources		868			607			4			—			1,479
Prices based on models		(9	)		(24	)		71			(104	)		(66	)
Total	$	712		$	499		$	72		$	(104	)	$	1,179
Percentage of total fair value		61	%		42	%		6	%		(9	)%		100	%

The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available. Over-the-counter quotes for power in ERCOT (excluding the West zone) generally extend through 2014 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 that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 8 to Financial Statements for fair value disclosures required under SFAS 157 and for discussion of fair value measurements.

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FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows —Cash provided by operating activities for the six months ended June 30, 2009 totaled $504 million compared to cash used of $1.900 billion in the six months ended June 30, 2008. The increase in cash provided of $2.404 million reflected:

• a $2.101 billion favorable change in margin deposits primarily due to the effect of lower forward natural gas prices on positions in the long-term hedging program;

• a $238 million decrease in cash interest paid due to the payment of approximately $233 million of interest with new notes as discussed under “PIK Interest Election” below, and

• a $78 million decrease in cash income taxes paid,

partially offset by a $115 million prepayment of lease obligations funded with previously restricted cash as discussed in Note 4 to Financial Statements.

Cash provided by financing activities decreased $3.019 billion as summarized below and reflected lower borrowing to support margin deposits:

	Six Months Ended June 30,
	2009		2008
Net repayments, repurchases and issuances of borrowings	$	408	$	3,408
Net issuances of common stock		—		33
Net contributions from and distributions to noncontrolling interests		15		—
Other		21		22
Total provided by financing activities	$	444	$	3,463

Cash used in investing activities decreased $61 million as summarized below:

	Six Months Ended June 30,
	2009			2008
Capital expenditures, including nuclear fuel	$	(1,343	)	$	(1,564	)
Redemption of investment held in money market fund		142			—
Investment posted with counterparty (Note 4)		(400	)		—
Change in restricted cash		129			(142	)
Proceeds from sale of assets		1			46
Other		(7	)		6
Total used in investing activities	$	(1,478	)	$	(1,654	)

The decline in capital spending for the six months ended June 30, 2009 as compared to the six months ended June 30, 2008 primarily reflected a decrease in spending related to the construction of new generation facilities, which is nearing completion, partially offset by capital expenditures for advanced metering deployment.

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Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $299 million and $252 million for the six months ended June 30, 2009 and 2008, respectively. The differences represent amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and delivery fees, other income and interest expense and related charges. The differences also reflect the amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice. In addition, the differences reflect the amortization of losses on dedesignated cash flow hedges, which is reported in interest expense and related charges in the statement of income.

Debt Financing Activity—Activities related to short-term borrowings and long-term debt during the six months ended June 30, 2009 are as follows (all amounts presented are principal, repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

	Borrowings (a)		Repayments and Repurchases
TCEH	$	435	$	169
EFC Holdings		—		2
EFH Corp.		—		5
Oncor		—		52
Total long-term		435		228
TCEH		—		—
Oncor		205		—
Total short-term (b)		205		—
Total	$	640	$	228

(a) Excludes $150 million of EFH Corp. Toggle Notes and $98 million of TCEH Toggle Notes issued in May 2009 in payment of accrued interest as discussed below under “PIK Interest Election.”

(b) Short-term amounts represent net borrowings/repayments.

See Note 4 to Financial Statements for further detail of long-term debt and other financing arrangements.

We or our affiliates may from time to time purchase our outstanding debt securities for cash in open market purchases or privately negotiated transactions, or we may refinance existing debt securities. We will evaluate any such transactions in light of market prices of the securities, taking into account liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material.

In late July 2009 to take advantage of favorable market conditions, TCEH proposed amendments to the TCEH Senior Secured Facilities that, among other things, are intended to provide additional financial flexibility. If the amendments are approved by TCEH’s lenders, certain of the amendments would permit the extension of the maturity of individual loans under the TCEH Senior Secured Facilities. There is no assurance that TCEH will obtain the necessary consents from its lenders for the amendments or, if the amendments are approved (whether as initially proposed or otherwise), that TCEH will be successful in extending the maturities of loans under the TCEH Senior Secured Facilities or otherwise benefit from the additional financial flexibility expected to be provided by the amendments.

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Available Liquidity — The following table summarizes changes in available liquidity for the six months ended June 30, 2009.

	Available Liquidity
	June 30, 2009		December 31, 2008		Change
Cash and cash equivalents, excluding Oncor	$	1,123	$	1,564	$	(441	)
Investments held in money market fund		—		142		(142	)
TCEH Delayed Draw Term Loan Facility (a)		87		522		(435	)
TCEH Revolving Credit Facility (b)		1,726		1,767		(41	)
TCEH Letter of Credit Facility		467		490		(23	)
Total, excluding Oncor (c)	$	3,403	$	4,485	$	(1,082	)
Short-term investment (d)	$	465	$	—	$	465
Cash and cash equivalents – Oncor	$	36	$	125	$	(89	)
Oncor Revolving Credit Facility		1,336		1,508		(172	)
Total Oncor	$	1,372	$	1,633	$	(261	)

(a) In July 2009, this facility was fully drawn.

(b) As of June 30, 2009 and December 31, 2008, the TCEH Revolving Credit Facility includes $139 million and $144 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender.

(c) Pursuant to PUCT rules, TCEH is required to maintain available liquidity to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at June 30, 2009, the total availability under the TCEH credit facilities should be further reduced by $231 million. See “Regulation and Rates – Certification of REPs.”

(d) Includes $400 million cash investment and $65 million in letters of credit posted related to interest rate swaps. See Note 4 to Financial Statements.

Note: Available liquidity above does not include the amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from November 2009 through November 2012 could add approximately $1.6 billion of liquidity.

The $617 million decrease in available liquidity excluding Oncor, after taking into account the short-term investment, reflected continued capital investments, including the construction of the new generation facilities.

The decrease in available liquidity for Oncor of $261 million in the six months ended June 30, 2009 reflected ongoing capital investment in transmission and distribution infrastructure.

See Note 4 to Financial Statements for additional discussion of these credit facilities.

Pension and OPEB Plan Funding— Pension and OPEB plan funding is expected to total $78 million and $22 million, respectively, in 2009. Oncor is expected to fund approximately 80% of these amounts. We made pension and OPEB contributions of $36 million and $11 million, respectively, in the six months ended June 30, 2009.

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Long-Term Contractual Obligations and Commitments— Through July 2009, we entered into contractual obligations totaling approximately $308 million to purchase nuclear fuel in periods between 2010 and 2020, and we also entered into contractual obligations totaling approximately $153 million to purchase coal to fuel our generation plants in periods between 2010 and 2012.

PIK Interest Election — EFH Corp. and TCEH have the option every six months until November 2012 to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. We elected to do so for the May 2009 and November 2009 interest payments as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy and related lower electricity demand and the continuing uncertainty in the financial markets. We will evaluate use of the PIK feature at each election period, taking into account market conditions and other relevant factors at such time.

EFH Corp. made its May 2009 interest payment and will make its November 2009 interest payment by using the PIK feature of the EFH Corp. Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the EFH Corp. Toggle Notes by $150 million in May 2009 and will further increase the aggregate principal amount of the EFH Corp. Toggle Notes by $159 million in November 2009. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $141 million and will further increase liquidity as of November 1, 2009 by an amount equal to approximately $149 million, with such amounts constituting the amount of cash interest that otherwise would have been payable in May 2009 and November 2009, respectively, and will increase the expected annual cash interest expense by approximately $35 million, constituting the additional cash interest that will be payable with respect to the $309 million of additional toggle notes.

Similarly, TCEH made its May 2009 interest payment and will make it November 2009 interest payment by using the PIK feature of the TCEH Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the TCEH Toggle Notes by approximately $98.5 million in May 2009 and will further increase the aggregate principal amount of the TCEH Toggle Notes by approximately $104 million in November 2009. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $92 million and will further increase liquidity as of November 1, 2009 by an amount equal to approximately $97 million, with such amounts constituting the amount of cash interest that otherwise would have been payable in May 2009 and November 2009, respectively, and will increase the expected annual cash interest expense by approximately $21 million, constituting the additional cash interest that will be payable with respect to the $202.5 million of additional toggle notes.

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Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving credit facility, funds the cash collateral posting requirements for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of this facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the TCEH Commodity Collateral Posting Facility, at June 30, 2009, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. See Note 4 to Financial Statements for more information about this facility.

As of June 30, 2009, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $291 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $317 million posted as of December 31, 2008;

• $475 million in cash has been received from counterparties, net of $54 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $402 million received, net of $122 million in cash posted, as of December 31, 2008;

• $366 million in letters of credit have been posted with counterparties, as compared to $342 million posted as of December 31, 2008, and

• $35 million in letters of credit have been received from counterparties, as compared to $30 million received as of December 31, 2008.

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 variance 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 either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, 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 liquidity in the event that it was not restricted. As of June 30, 2009, restricted cash collateral was immaterial. See Note 13 to Financial Statements regarding restricted cash.

With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit margin requirements. As of June 30, 2009, approximately 0.7 billion MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped TCEH Commodity Collateral Posting Facility supports the collateral posting requirements related to these transactions.

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Income Tax Refunds/Payments — In February 2009, we received a refund totaling $98 million in income taxes and related interest related to IRS audits of 1993 and 1994 federal income tax returns. No material federal income tax payments or refunds are anticipated within the next twelve months. We made payments totaling approximately $48 million related to the Texas margin tax in May 2009, and expect to make an additional payment of approximately $4 million in the third quarter 2009.

Sale of Accounts Receivable — Certain TCEH subsidiaries 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, these subsidiaries (originators) sell retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH 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 $496 million and $416 million at June 30, 2009 and December 31, 2008, respectively. See Note 3 to Financial Statements for a more complete description of the program including the impact of the program on the financial statements for the periods presented and the contingencies that could result in a reduction of funding available under the program.

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Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of June 30, 2009, we were in compliance with all such maintenance covenants.

Covenants and Restrictions under Financing Arrangements— Each of the TCEH Senior Secured Facilities, indentures governing the TCEH Senior Notes and the EFH Corp. Senior Notes and agreements related to certain series of TCEH’s pollution control revenue bonds contains covenants that could have a material impact on the liquidity and operations of EFH Corp. and its subsidiaries. See the 2008 Form 10-K for additional discussion of the covenants contained in these financing arrangements.

Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Notes) for the twelve months ended June 30, 2009 totaled $4.7 billion for EFH Corp. See Exhibit 99(b) and 99(c) for a reconciliation of net income to Adjusted EBITDA for EFH Corp. and TCEH, respectively, for the six and twelve months ended June 30, 2009 and 2008.

The following table summarizes TCEH’s secured debt to adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp. and TCEH that are applicable under certain other covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes and the EFH Corp. Senior Notes as of June 30, 2009 and December 31, 2008 and the corresponding maintenance and other covenant threshold levels as of June 30, 2009:

	June 30, 2009	December 31, 2008	Threshold Level
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to adjusted EBITDA ratio	4.85 to 1.00	4.77 to 1.00	Must not exceed 7.25 to 1.00
Debt Incurrence Covenants:
EFH Corp. Senior Notes:
EFH Corp. fixed charge coverage ratio	1.6 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (a)	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (a)	1.6 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	7.1 to 1.0	6.9 to 1.0	Equal to or less than 7.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to adjusted EBITDA ratio	8.7 to 1.0	8.7 to 1.0	At least 6.5 to 1.0

(a) The EFH Corp. fixed charge coverage ratio for non-Sponsor Group payments includes the results of Oncor Holdings and its subsidiaries. The EFH Corp. fixed charge coverage ratio for Sponsor Group payments excludes the results of Oncor Holdings and its subsidiaries.

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Credit Ratings —The issuer credit ratings as of August 3, 2009 for EFH Corp. and its subsidiaries, except for Oncor, are B-, Caa1 and B by S&P, Moody’s and Fitch, respectively. The issuer credit ratings for Oncor are BBB+ and BBB- by S&P and Fitch, respectively.

Additionally, the rating agencies assign credit ratings on certain of our debt securities. The credit ratings assigned for these debt securities as of August 3, 2009 are presented below:

	S&P	Moody’s	Fitch
EFH Corp. (Senior Unsecured) (a)	B-	Caa2	B+
EFH Corp. (Unsecured)	CCC	Caa3	CCC
EFC Holdings (Senior Unsecured)	CCC	Caa3	CCC
TCEH (Senior Secured)	B+	B2	BB
TCEH (Senior Unsecured) (b)	CCC	Caa2	B
TCEH (Unsecured)	CCC	Caa3	CCC
Oncor (Senior Secured) (c)	BBB+	Baa1	BBB
Oncor (Senior Unsecured) (c)	BBB+	Baa1	BBB-

(a) EFH Corp. Cash-Pay Notes and EFH Corp. Toggle Notes

(b) TCEH Cash-Pay Notes and TCEH Toggle Notes

(c) All of Oncor’s long-term debt is secured by a first priority lien and is considered senior secured debt.

S&P has placed the ratings for EFH Corp. and its subsidiaries on “stable outlook.” In March 2009, Moody’s downgraded ratings for EFH Corp. and TCEH and confirmed the outlook for EFH Corp. and TCEH as negative, citing the current material degradation in economic factors combined with declining fundamentals associated with weaker commodity prices. In June 2009, Moody’s upgraded the long-term debt rating for Oncor’s senior secured debt by two notches from Baa3 to Baa1 citing, among other things, Oncor’s position as a rate-regulated electric transmission and distribution utility in Texas, reasonably supportive regulatory jurisdiction, solid financial credit metrics, adequate sources of near-term liquidity and the continued evidence of strong corporate independence from EFH Corp. Moody’s ratings outlook for Oncor remains stable. In August 2009, Moody’s downgraded the issuer ratings for EFH Corp. and its subsidiaries, except Oncor, one notch to Caa1 and downgraded the long-term debt ratings of EFH Corp., EFC Holdings and TCEH by one notch. Moody’s downgrade and continued negative outlook for EFH Corp., EFC Holdings and TCEH cited weak business fundamentals including high debt levels, including maturities in 2014, prospective long-term liquidity, financial and credit market prospects due primarily to our long-term hedging program, acceleration of environmental legislative initiatives that could threaten margins from coal-fired plants and the risk of incremental market intervention in Texas. The negative outlook also reflects their view that the capital structure is untenable and will likely prompt the company to pursue some form of restructuring activity.

In March 2009, Fitch downgraded certain ratings for EFH Corp., EFC Holdings and TCEH and changed the outlook for EFH Corp., EFC Holdings and TCEH from stable to negative, citing the effect of the economic slowdown in Texas and lower than anticipated market heat rates in ERCOT. Fitch’s ratings outlook for Oncor remains stable.

A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Ratings 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 and Credit Worthiness Effects on Liquidity — As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of June 30, 2009, counterparties to those contracts could have required TCEH to post up to an aggregate of $73 million in additional collateral. This amount largely represents the below market terms of these contracts as of June 30, 2009; thus, this amount will vary depending on the value of these contracts on any given day.

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 TCEH’s below investment grade credit rating, TCEH 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. As of June 30, 2009, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $26 million, with $14 million of this amount posted for the benefit of Oncor.

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The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of June 30, 2009, TCEH maintained availability under its credit facilities of approximately $231 million. See “Regulation and Rates – Certification of REPs.”

The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $600 million to $800 million. The actual amount (if required) could vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.

ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $49 million as of June 30, 2009 (which is subject to weekly adjustments based on settlement activity with ERCOT).

Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH is required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor if two or more of Oncor’s credit ratings are below investment grade.

Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 3 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

In the event that any or all of the additional collateral requirements discussed above are triggered, we believe we will have adequate liquidity to satisfy such requirements.

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 could or does result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.

A default by TCEH or any restricted subsidiary in respect of indebtedness, excluding indebtedness relating to the sale of receivables program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities such a default may cause the maturity of outstanding balances ($22.309 billion at June 30, 2009) under such facilities to be accelerated.

The indenture governing the TCEH Senior Notes contains a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of TCEH and any of its restricted subsidiaries in the aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Senior Notes.

Under the terms of a TCEH rail car lease, which had approximately $48 million in remaining lease payments as of June 30, 2009 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

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Under the terms of a TCEH rail car lease, which had approximately $55 million in remaining lease payments as of June 30, 2009 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements have been accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

The indenture governing the EFH Corp. Senior Notes contains a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. or any of its restricted subsidiaries in the aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Senior Notes.

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originators, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (a direct subsidiary of EFH Corp.), as collection agent, in the aggregate have a cross default threshold of $50,000. If any of the aforementioned defaults on indebtedness of the applicable threshold were to occur, the program could terminate.

We 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 we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.

Each of TCEH’s natural gas hedging agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge agreement with TCEH and require all outstanding obligations under such agreement to be settled.

In the event of a default by TCEH relating to indebtedness in an amount equal to or greater than $200 million that results in the acceleration of such debt, then each counterparty under TCEH’s interest rate swap agreements with an aggregate derivative liability of $1.26 billion at June 30, 2009 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

A default by Oncor 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 credit facility. Under this facility such a default may cause the maturity of outstanding balances ($542 million at June 30, 2009) under such facility to be accelerated.

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

Guarantees — See Note 5 to Financial Statements for details of guarantees.

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OFF–BALANCE SHEET ARRANGEMENTS

See discussion above under “Sale of Accounts Receivable” and in Note 3 to Financial Statements.

Also see Note 5 to Financial Statements regarding guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 5 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

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

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REGULATION AND RATES

Regulatory Investigations and Reviews

See Note 5 to Financial Statements.

Certification of REPs

In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule is considered a competition rule and thus is subject to judicial review as specified in PURA. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the rule, Oncor uncollectible amounts owed by REPs are deferred as a regulatory asset. Recovery of the regulatory asset will be considered in a future rate case. Accordingly, Oncor recognized an approximately $3 million one-time reversal of bad debt expense in the three months ended June 30, 2009 (reported in other income). Due to the commitments made to the PUCT in connection with the Merger, Oncor may not recover bad debt expense, or certain other costs and expenses, from rate payers in the event of a TXU Energy default or bankruptcy. Under the rule, REPs are required to amend their certifications, including the manner in which they meet financial requirements, by May 21, 2010. TXU Energy plans to file its amended certification no later than the first quarter 2010. Under the new financial requirements, which will be effective upon approval of the amended certification, as of June 30, 2009, the amount of additional available liquidity required to be maintained by TCEH related to payments to TDUs would have been reduced from $231 million to approximately $109 million.

Wholesale Market Design

In August 2003, the PUCT adopted a rule that, when implemented, will alter the wholesale market design in the ERCOT market. The rule requires ERCOT to:

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

• operate a voluntary day-ahead energy market;

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

• use nodal energy prices for resources;

• provide information for energy trading hubs by aggregating nodes;

• use zonal prices for loads, and

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

ERCOT currently has a zonal wholesale market structure consisting of four geographic zones. The proposed location-based congestion-management market is referred to as a “nodal” market because wholesale pricing would differ across the various nodes on the transmission grid. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. Pursuant to a request from the PUCT, ERCOT announced in November 2008 a preliminary schedule for the implementation of the nodal market by December 2010.

ERCOT imposes a surcharge on all Qualified Scheduling Entities in the ERCOT market (including subsidiaries of TCEH) for the purpose of financing 38% of ERCOT’s expected nodal implementation costs. In November 2008, ERCOT filed a request with the PUCT for approval of an interim increase in the nodal surcharge from $0.169 per MWh to $0.38 per MWh. In May 2009, the PUCT extended the existing nodal surcharge of $0.169 per MWh through September 30, 2009. At the current $0.169 per MWh nodal surcharge, the annual impact of the surcharge increase would be an estimated $12 to $13 million in expenses for 2009. At the direction of the PUCT, ERCOT submitted a request for approval of a permanent nodal surcharge, budget and schedule in March 2009. The proposed schedule continues to provide for implementation of a nodal market in December 2010.

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The PUCT is expected to consider ERCOT’s request in a contested case docket during the third quarter of 2009 to determine the nodal surcharge fee for the remainder of 2009 and 2010. We cannot predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results.

Oncor Matters with the PUCT

Rate Case — In June 2008, Oncor filed for a rate review with the PUCT (Docket No. 35717) and 204 cities, as required by the order approving the stipulation discussed in the 2008 Form 10-K. If approved as requested, this review would result in an aggregate annual rate increase of approximately $253 million (adjusted from $275 million as reflected in the initial filing), the majority of which relates to increased depreciation expense due to capital investments and recovery of costs that have been recorded as regulatory assets. A hearing on the merits concluded in February 2009. After evidentiary hearings on the rate review before the State Office of Administrative Hearings (SOAH), in June 2009, SOAH issued a Proposal for Decision (PFD). Oncor’s rate review filing and the PFD were considered by the PUCT at two open meetings in July 2009. The PUCT has not yet concluded its review of the case and is not obligated to accept all or any part of the PFD in its ruling.

The economic impact of the rate review could be significantly affected by the PUCT’s decisions on the following issues:

• the consolidated tax savings to EFH Corp. arising out of EFH Corp.’s ability to offset Oncor’s taxable income against losses from other investments;

• the recovery of Oncor’s investment in certain automated meters installed before final meter functionality requirements were promulgated by the PUCT, and

• Oncor’s return on equity, which the PFD proposed to set at 10.25%.

The PUCT directed the PUCT staff to calculate the range of revenue requirement increases, which would in any case be less than Oncor’s requested increase, based on a range of discussed resolutions and report the results prior to the next PUCT open meeting scheduled for August 13, 2009. Oncor expects the PUCT to issue an order setting forth its decision during the third quarter 2009. Oncor has no basis to predict the ultimate outcome of the PUCT rate review or to estimate related regulatory asset write-offs, if any.

Transmission Rates — In order to recover increases in its transmission costs, including fees paid to other transmission service providers, Oncor 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 2009, an application was filed to increase the TCRF, which was administratively approved in February 2009 and became effective in March 2009. This increase is expected to increase annualized revenues by $16 million. In July 2009, an application was filed to increase the TCRF, which is expected to be administratively approved in August 2009 and become effective September 1, 2009. If approved, this increase is expected to increase annualized revenues by approximately $14 million.

Competitive Renewable Energy Zones (CREZ) — In January 2009, the PUCT assigned approximately $1.3 billion of CREZ construction projects to Oncor. A written order reflecting the PUCT’s decision was entered in March 2009, and an order on rehearing was issued by the PUCT in May 2009. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT. For the six months ended June 30, 2009, CREZ-related capital expenditures totaled $39 million. It is expected that the necessary permitting actions and other requirements and all construction activities for the assigned construction projects will be completed by the end of 2013.

Application for 2010 Energy Efficiency Cost Recovery Factor — In May 2009, Oncor filed an application with the PUCT to request approval of an Energy Efficiency Cost Recovery Factor (EECRF) for 2010. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. The requested 2010 EECRF is $54 million, the same amount established for 2009, and would result in the same $0.92 per month charge for residential customers as proposed in Oncor’s pending rate case. As allowed by the rule, the 2010 EECRF is designed to recover the costs of the 2010 programs, the under-recovery of 2008 program costs, and a performance bonus based on 2008 results. Approval of the application as filed would result in an immediate recognition of $9 million in revenues, representing the performance bonus.

Summary

We cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly alter our basic financial position, results of operations or cash flows.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that we may experience a loss in value as a result of changes in market conditions affecting factors such as commodity prices and interest rates, that may be experienced in the ordinary course of business. Our exposure to market risk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interest rate risk related to indebtedness, as well as exchange traded, over-the-counter contracts and other contractual arrangements to manage commodity price risk as part of wholesale activities.

Risk Oversight

TCEH manages the commodity price, counterparty credit and commodity-related operational risk related to the unregulated energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate 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, transaction review and approval (including credit review), operational and market risk measurement, validation of transaction capture, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

We have a corporate risk management organization that is headed by the Chief Financial Officer, who also functions as the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in our businesses and their associated transactions.

Commodity Price Risk

TCEH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. The company, 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, TCEH enters 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 include hedging, the structuring of long-term contractual arrangements and proprietary trading. The company continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. The company strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

Long-Term Hedging Program— See “Significant Activities and Events” above for a description of the program, including potential effects on reported results.

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

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 June 30, 2009		Year Ended December 31, 2008
Month-end average Trading VaR:	$	2	$	6
Month-end high Trading VaR:	$	4	$	15
Month-end low Trading VaR:	$	2	$	2

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 June 30, 2009		Year Ended December 31, 2008
Month-end average MtM VaR:	$	1,054	$	2,290
Month-end high MtM VaR:	$	1,470	$	3,549
Month-end low MtM VaR:	$	725	$	1,087

Earnings at Risk (EaR)— This measurement estimates the potential reduction of pretax earnings for the periods 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). Transactions accounted for as cash flow hedges are also included for this measurement. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.

	Six Months Ended June 30, 2009		Year Ended December 31, 2008
Month-end average EaR:	$	1,037	$	2,300
Month-end high EaR:	$	1,450	$	3,916
Month-end low EaR:	$	722	$	1,069

The decreases in the risk measures (MtM VaR and EaR) above were primarily driven by lower natural gas prices in 2009.

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Interest Rate Risk

As of June 30, 2009, the potential reduction of annual pretax earnings due to a one percentage point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $29 million, taking into account the interest rate swaps discussed in Note 4 to Financial Statements.

Credit Risk

Credit Risk— Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating 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. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and 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 assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality 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 — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from commodity hedging and trading activities totaled $3.131 billion at June 30, 2009. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of June 30, 2009 include $974 million in accounts receivable from the retail sale of electricity to TCEH’s residential and business customers. Cash deposits held as collateral for these receivables totaled $103 million at June 30, 2009. 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, market or operational conditions and changes in the financial condition of large business customers.

Most of the remaining credit exposure is with TCEH’s 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, 2009, the exposure to credit risk from the wholesale customers and counterparties totaled $1.903 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $586 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.317 billion increased approximately $522 million in the six months ended June 30, 2009, reflecting the increase in derivative assets related to the long-term hedging program due to the decline in forward natural gas prices.

Of this $1.317 billion net exposure, 97% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a 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 a S&P equivalent rating. TCEH routinely monitors and manages credit exposure to these customers and counterparties on this basis.

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In addition, Oncor has exposure to credit risk from nonaffiliated parties totaling $254 million at June 30, 2009. This exposure consists almost entirely of noninvestment grade trade accounts receivable, of which $192 million represents trade accounts receivable from REPs. Oncor has a customer with subsidiaries that collectively represent 14% of the total exposure to nonaffiliated parties. No other nonaffiliated parties represent 10% or more of the total exposure.

The following table presents the distribution of credit exposure as of June 30, 2009, for wholesale counterparties. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from commodity hedging and trading activities after taking into consideration netting within each contract and any master netting contracts with counterparties. The amounts below do not include asset liens held as security for a portion of the net exposure.

									Net Exposure by Maturity
	Exposure Before Credit Collateral			Credit Collateral		Net Exposure			2 years or less		Between 2-5 years			Greater than 5 years		Total
Investment grade	$	1,857		$	585	$	1,272		$	1,103	$	169		$	—	$	1,272
Noninvestment grade		46			1		45			46		(1	)		—		45
Totals	$	1,903		$	586	$	1,317		$	1,149	$	168		$	—	$	1,317
Investment grade		98	%				97	%
Noninvestment grade		2	%				3	%

In addition to the exposures in the table above, TCEH has contracts classified as “normal” purchase or sale and non-derivative contractual commitments that are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material adverse impact on future results of operations, financial condition and cash flows.

TCEH does not anticipate any material adverse effect on its financial position or results of operations due to nonperformance by any wholesale customer or counterparty.

TCEH had credit exposure to two wholesale counterparties each having an exposure greater than 10% of the net $1.317 billion credit exposure. These two counterparties represented 48% and 34%, respectively, of the net exposure. Exposure to these counterparties is viewed to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.

With respect to credit risk related to the long-term hedging program, over 99% of the transaction volumes are with counterparties with an A credit rating or better. However, TCEH has current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through various ongoing risk management measures.

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain “forward-looking statements.” 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 we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our 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,” and “outlook”), are forward-looking statements. Although we believe that in making any such forward-looking statement our 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 under “Risk Factors” in the 2008 Form 10-K and the following important factors, among others, that could cause our actual results 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 PUCT, the RRC, the NRC, the EPA and the TCEQ, with respect to, among other things:

• allowed prices;

• allowed rates of return;

• industry, market and rate structure;

• purchased power and recovery of investments;

• operations of nuclear generating facilities;

• operations of mines;

• 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;

• legal and administrative proceedings and settlements;

• general industry trends;

• economic conditions, including the current recessionary environment;

• our ability to attract and retain profitable customers;

• our ability to profitably serve our customers;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices;

• changes in prices of transportation of natural gas, coal, crude oil and refined products;

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

• our ability to effectively hedge against changes in commodity prices, market heat rates and interest 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;

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• commercial bank market and capital market conditions and the potential impact of continued disruptions in US credit markets;

• competition for new energy development and other business opportunities;

• inability of various counterparties to meet their obligations with respect to our financial instruments;

• changes in technology used by and services offered by us;

• significant changes in our relationship with our 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 costs of providing employee benefits, including pension and OPEB benefits, and future funding requirements related thereto;

• changes in assumptions used to estimate future executive compensation payments;

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• our ability to implement cost reduction initiatives, and

• with respect to our lignite-fueled generation construction and development program, more specifically, our ability to fund such investments, changes in competitive market rules, unexpected judicial rulings, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, our contractors’ and our ability 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 our ability to manage the significant construction, commissioning and start-up program to a timely conclusion with limited cost overruns.

Any forward-looking statement speaks only as of the date on which it is made, and there is 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 us to predict all of them; nor can we 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.

INDUSTRY AND MARKET INFORMATION

The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT. We did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and we make no assurances that the predictions contained therein are accurate.

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Item 4. CONTROLS AND PROCEDURES.

An evaluation was performed under the supervision and with the participation of our 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 report. Based on the evaluation performed, our 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 report, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting, except as discussed below.

During the second quarter of 2009, we completed the implementation of a new SAP retail customer management system, including billing and accounts receivable. As with any material change in our internal control over financial reporting, the design of this application, along with the design of the internal controls included in our processes, were evaluated for effectiveness.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS.

Reference is made to the discussion in Note 5 to Financial Statements regarding legal proceedings.

Item 1A. RISK FACTORS.

There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the 2008 Form 10-K.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

In May 2009, the shareholders of EFH Corp., acting by written consent executed by shareholders holding approximately 99% of the outstanding shares of EFH Corp.’s common stock, no par value per share, approved the reduction of the stated capital of EFH Corp.’s common stock to an amount equal to $0.001 for each outstanding share of common stock.

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Item 6. EXHIBITS

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

Exhibits	Previously Filed With File Number	As Exhibit
(4)	Instruments Defining the Rights of Security Holders, Including Indentures.
	Energy Future Holdings Corp.
4(a)			–	Second Supplemental Indenture, dated as of August 3, 2009, to Indenture, dated as of October 31, 2007, relating to Energy Future Holdings Corp.’s 10.875% Senior Notes due 2017 and 11.25%/12.00% Senior Toggle Notes due 2017
	Texas Competitive Electric Holdings Company LLC
4(b)			–	Second Supplemental Indenture, dated as of August 3, 2009, to Indenture, dated as of October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016
(31)	Rule 13a – 14(a)/15d – 14 (a) Certifications.
31(a)			–	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			–	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32)	Section 1350 Certifications.
32(a)			–	Certification of John Young, principal executive officer of Energy Future Holdings 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 Paul M. Keglevic, principal financial officer of Energy Future Holdings 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(a)			–	Condensed Statements of Consolidated Income – Twelve Months Ended June 30, 2009.
99(b)			–	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2009 and 2008.
99(c)			–	TCEH Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2009 and 2008.

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SIGNATURE

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

Energy Future Holdings Corp.
By:	/s/ Stan Szlauderbach
Name:	Stan Szlauderbach
Title:	Senior Vice President and Controller
	(Principal Accounting Officer)

Date: August 3, 2009

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