Energy Future (TXU) 10-Q 2009 Q1 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 MARCH 31, 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 April 27, 2009, there were 1,666,630,298 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 Months Ended March 31, 2009 and 2008	1
	Condensed Statements of Consolidated Comprehensive Income (Loss) – Three Months Ended March 31, 2009 and 2008	2
	Condensed Statements of Consolidated Cash Flows – Three Months Ended March 31, 2009 and 2008	3
	Condensed Consolidated Balance Sheets – March 31, 2009 and December 31, 2008	4
	Notes to Condensed Consolidated Financial Statements	5
	Report of Independent Registered Public Accounting Firm	45
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	77
Item 4.	Controls and Procedures	83
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	83
Item 1A.	Risk Factors	83
Item 6.	Exhibits	84
SIGNATURE		86

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
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.
Capgemini	Capgemini Energy LP, a subsidiary of Cap Gemini North America Inc. that provides business support services to us
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 46R	FIN No. 46R (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”
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.
Merger Sub	Texas Energy Future Merger Sub Corp, a Texas corporation and a wholly-owned subsidiary of Texas Holdings that was merged into EFH Corp. on October 10, 2007

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 46R, 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 141 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 has oversight of lignite mining activity
S&P	Standard & Poor’s Ratings Services, a division of the McGraw Hill Companies Inc. (a credit rating agency)
SEC	US Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
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 141	SFAS No. 141, “Business Combinations”
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”
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 March 31,
	2009			2008
Operating revenues	$	2,139		$	2,354
Fuel, purchased power costs and delivery fees		(601	)		(821	)
Net gain (loss) from commodity hedging and trading activities		1,128			(1,567	)
Operating costs		(387	)		(357	)
Depreciation and amortization		(407	)		(395	)
Selling, general and administrative expenses		(246	)		(217	)
Franchise and revenue-based taxes		(85	)		(86	)
Impairment of goodwill (Note 2)		(90	)		—
Other income (Note 12)		13			14
Other deductions (Note 12)		(11	)		(16	)
Interest income		1			5
Interest expense and related charges (Note 12)		(667	)		(843	)
Income (loss) before income taxes		787			(1,929	)
Income tax (expense) benefit		(333	)		660
Net income (loss)		454			(1,269	)
Net income attributable to noncontrolling interests		(12	)		—
Net income (loss) attributable to EFH Corp.	$	442		$	(1,269	)

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 March 31,
	2009			2008
Net income (loss)	$	454		$	(1,269	)
Other comprehensive income (loss), net of tax effects:
Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of $9 and $219)		(17	)		(407	)
Derivative value net loss (gain) related to hedged transactions recognized during the period and reported in net income (net of tax benefit (expense) of $15 and $(1))		26			(3	)
Total effect of cash flow hedges		9			(410	)
Comprehensive income (loss)		463			(1,679	)
Comprehensive income attributable to noncontrolling interests		(12	)		—
Comprehensive income (loss) attributable to EFH Corp.	$	451		$	(1,679	)

See Notes to Financial Statements.

2

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(millions of dollars)

	Three Months Ended March 31,
	2009			2008
Cash flows – operating activities:
Net income (loss)	$	454		$	(1,269	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization		520			533
Deferred income tax expense (benefit)		295			(697	)
Impairment of goodwill (Note 2)		90			—
Unrealized net (gains) losses from mark-to-market valuations of commodity positions		(1,030	)		1,594
Unrealized net gains from mark-to-market valuations of interest rate swaps		(205	)		—
Bad debt expense		20			17
Stock-based incentive compensation expense		5			2
Other net		40			2
Changes in operating assets and liabilities:
Margin deposits – net		65			(597	)
Deferred advanced metering system revenues (Note 12)		19			—
Other operating assets and liabilities		317			255
Cash provided by (used in) operating activities		590			(160	)
Cash flows – financing activities:
Issuances of long-term borrowings/securities
Long-term borrowings (Note 4)		212			149
Common stock		—			28
Repayments of long-term borrowings (Note 4)		(152	)		(287	)
Increase in short-term borrowings (Note 4)		60			791
Contributions from noncontrolling interests		26			—
Distributions paid to noncontrolling interests		(7	)		—
Debt discount, financing and reacquisition expenses		(2	)		(3	)
Other		1			11
Cash provided by financing activities		138			689
Cash flows – investing activities:
Capital expenditures		(589	)		(710	)
Nuclear fuel purchases		(46	)		(58	)
Redemption of investment held in money market fund		142			—
Investment posted with counterparty (Note 4)		(400	)		—
Proceeds from sale of assets		—			25
Proceeds from sale of environmental allowances and credits		4			20
Purchases of environmental allowances and credits		(9	)		(12	)
Proceeds from sales of nuclear decommissioning trust fund securities		1,402			396
Investments in nuclear decommissioning trust fund securities		(1,406	)		(400	)
Cost to remove retired property		(11	)		(8	)
Other		31			23
Cash used in investing activities		(882	)		(724	)
Net change in cash and cash equivalents		(154	)		(195	)
Cash and cash equivalents – beginning balance		1,689			281
Cash and cash equivalents – ending balance	$	1,535		$	86

See Notes to Financial Statements.

3

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)

	March 31, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	1,535		$	1,689
Investment posted with counterparty (Note 4)		400			—
Investments held in money market fund		—			142
Restricted cash (Note 12)		53			55
Trade accounts receivable – net (Note 3)		892			1,219
Income taxes receivable – net		—			42
Inventories		424			426
Commodity and other derivative contractual assets (Note 7)		3,891			2,534
Accumulated deferred income taxes		287			44
Margin deposits related to commodity positions		465			439
Other current assets		151			165
Total current assets		8,098			6,755
Restricted cash (Note 12)		1,266			1,267
Investments		615			645
Property, plant and equipment – net		29,612			29,522
Goodwill (Note 2)		14,316			14,386
Intangible assets – net (Note 2)		3,009			2,993
Regulatory assets – net		1,879			1,892
Commodity and other derivative contractual assets (Note 7)		1,775			962
Other noncurrent assets, principally unamortized debt issuance costs		818			841
Total assets	$	61,388		$	59,263
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 4)	$	1,297		$	1,237
Long-term debt due currently (Note 4)		323			385
Trade accounts payable		794			1,143
Commodity and other derivative contractual liabilities (Note 7)		4,027			2,908
Margin deposits related to commodity positions		616			525
Accrued interest		858			524
Other current liabilities		509			612
Total current liabilities		8,424			7,334
Accumulated deferred income taxes		6,483			5,926
Investment tax credits		41			42
Commodity and other derivative contractual liabilities (Note 7)		1,936			2,095
Long-term debt, less amounts due currently (Note 4)		40,989			40,838
Other noncurrent liabilities and deferred credits (Note 12)		5,205			5,205
Total liabilities		63,078			61,440
Commitments and Contingencies (Note 5)
Equity (Note 6)
EFH Corp. shareholders’ equity		(3,076	)		(3,532	)
Noncontrolling interests in subsidiaries		1,386			1,355
Total equity		(1,690	)		(2,177	)
Total liabilities and equity	$	61,388		$	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 an approximate 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, the cash flows of the Oncor Ring-Fenced Entities and their results of operations are separate from those of the Texas Holdings Group. Oncor Holdings is consolidated with EFH Corp. as a variable interest entity under FIN 46R.

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 11 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 160 and 161 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.

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 and those created as part of the nuclear generation development joint venture formed in the first quarter of 2009 ($1.355 billion as of December 31, 2008) 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 does 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. 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. The principal effect of this rule is that we will disclose the fair value of our debt securities quarterly in addition to our annual disclosure.

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, the adoption of this FSP will 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 increases or decreases in Oncor’s regulatory asset or liability related to the decommissioning cost.

6

2. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Reported goodwill as of March 31, 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 $8.9 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.

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.

Identifiable Intangible Assets

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

	As of March 31, 2009						As of December 31, 2008
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	151	$	312	$	463	$	130	$	333
Favorable purchase and sales contracts		700		291		409		700		249		451
Capitalized in-service software		382		127		255		255		116		139
Environmental allowances and credits		987		142		845		994		121		873
Land easements and other		199		72		127		203		71		132
Total intangible assets subject to amortization	$	2,731	$	783		1,948	$	2,615	$	687		1,928
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization)						106						110
Total intangible assets					$	3,009					$	2,993

7

Amortization expense related to intangible assets consisted of:

	Income Statement Line	Segment	Three Months Ended March 31, 2009		Three Months Ended March 31, 2008
Retail customer relationship	Depreciation and amortization	Competitive Electric	$	21	$	13
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	Competitive Electric		42		59
Capitalized in-service software	Depreciation and amortization	All		11		11
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	Competitive Electric		21		26
Land easements and other	Depreciation and amortization	All		1		1
Total amortization expense			$	96	$	110

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	$	374
2010		241
2011		194
2012		150
2013		125

8

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 was $382 million at March 31, 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 March 31, 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 $270 million and $268 million at March 31, 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., that 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 March 31,
	2009			2008
Program fees	$	4		$	7
Program fees as a percentage of average funding (annualized)		3.7	%		7.0	%

The trade accounts receivable balance reported in the March 31, 2009 consolidated balance sheet includes $652 million face amount of retail accounts receivable sold and has been reduced by proceeds from the sale of undivided interests in those receivables totaling $382 million. Funding under the program decreased $34 million and $22 million for the three month periods ending March 31, 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.

9

Activities of TXU Receivables Company were as follows:

	Three Months Ended March 31,
	2009			2008
Cash collections on accounts receivable	$	1,440		$	1,456
Face amount of new receivables purchased		(1,408	)		(1,391	)
Discount from face amount of purchased receivables (to fund fees paid)		5			8
Program fees paid to funding entities		(4	)		(7	)
Servicing fees paid to EFH Corp. subsidiary for recordkeeping and collection services		(1	)		(1	)
Increase (decrease) in subordinated notes payable		2			(43	)
Operating cash flows used by originators under the program	$	34		$	22

The program 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.

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

	March 31, 2009			December 31, 2008
Gross wholesale and retail trade accounts receivable	$	1,336		$	1,705
Undivided interests in retail accounts receivable sold by TXU Receivables Company		(382	)		(416	)
Allowance for uncollectible accounts		(62	)		(70	)
Trade accounts receivable – reported in balance sheet	$	892		$	1,219

Gross trade accounts receivable at March 31, 2009 and December 31, 2008 included unbilled revenues of $390 million and $505 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Three Months Ended March 31,
	2009			2008
Allowance for uncollectible accounts receivable as of beginning of period	$	70		$	32
Increase for bad debt expense		20			17
Decrease for account write-offs		(29	)		(18	)
Other		1			2
Allowance for uncollectible accounts receivable as of end of period	$	62		$	33

10

4. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At March 31, 2009, we had outstanding short-term borrowings of $1.297 billion at a weighted average interest rate of 3.02%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $397 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 March 31, 2009 are presented below. The facilities are all senior secured facilities of the authorized borrower.

Authorized Borrowers and Facility	Maturity Date	At March 31, 2009
		Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Delayed Draw Term Loan Facility (a)	October 2014	$	4,100	$	—	$	3,774	$	310
TCEH Revolving Credit Facility (b)	October 2013		2,700		26		900		1,748
TCEH Letter of Credit Facility (c)	October 2014		1,250		—		1,250		—
Subtotal TCEH (d)		$	8,050	$	26	$	5,924	$	2,058
TCEH Commodity Collateral Posting Facility (e)	December 2012		Unlimited	$	—	$	—		Unlimited
Oncor Revolving Credit Facility (f)	October 2013	$	2,000	$	—	$	397	$	1,449

(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.

(b) Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $142 million of undrawn 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 March 31, 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, all of which were drawn at the closing of the Merger and are classified as long-term debt, have been retained as restricted cash. Letters of credit totaling $769 million issued as of March 31, 2009 are supported by the restricted cash, and the remaining letter of credit availability totals $481 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 March 31, 2009, the total availability under the TCEH credit facilities should be further reduced by $235 million.

(e) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 750 million MMBtu as of March 31, 2009. As of March 31, 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 $154 million of undrawn commitments from Lehman. All outstanding borrowings under this facility at March 31, 2009 bear interest at LIBOR plus 0.425% and a facility fee is payable (currently at a rate per annum equal to 0.150%) on the commitments under the facility.

11

Long-Term Debt

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

	March 31, 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
0.800% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
1.500% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.800% 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)		(157	)		(161	)
Senior Secured Facilities:
4.033% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)		16,203			16,244
4.001% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		3,774			3,562
3.935% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
0.439% 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		1,750			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		164			159
Unamortized fair value discount (d)		(6	)		(6	)
Total TCEH	$	29,573		$	29,470

12

	March 31, 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		52			53
1.970% 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		104			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		2,500			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)		(647	)		(661	)
Total EFH Corp.		6,453			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		39			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		856			879
Unamortized fair value discount related to transition bonds (d)		(8	)		(9	)
Total Oncor consolidated		5,182			5,204
Total EFH Corp. consolidated		41,312			41,223
Less amount due currently (k)		(323	)		(385	)
Total long-term debt	$	40,989		$	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 March 31, 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 March 31, 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 March 31, 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 March 31, 2009, excluding quarterly maintenance fee of approximately $11 million. See “Credit Facilities” above for more information.

(h) This financing is secured with a $115 million letter of credit.

(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.

(k) Includes $3 million at both March 31, 2009 and December 31, 2008 representing debt of EFH Corp., the parent entity.

13

Debt-Related Activity in 2009— Repayments of long-term debt in 2009 totaling $152 million represented principal payments at scheduled maturity dates as well as other repayments totaling $23 million, principally related to capitalized leases. Payments at scheduled maturity dates included $65 million of a TCEH promissory note, $41 million repaid under the TCEH Initial Term Loan Facility, and $23 million of Oncor transition bond principal payments.

Increases in long-term debt during 2009 totaling $212 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.

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. The companies elected to do so for the May 1, 2009 and November 1, 2009 interest payment dates as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy, including the effect of lower electricity demand, and the continuing uncertainty in the financial markets.

EFH Corp. will make its May 2009 and November 2009 interest payments by using the PIK feature of the EFH Corp. Toggle Notes. The elections will increase the interest rate on the toggle notes from 11.25% to 12.00% during the applicable interest periods and require EFH Corp. to issue an additional $150 million and $159 million principal amount of EFH Corp. Toggle Notes on May 1, 2009 and November 1, 2009, respectively. In addition, the elections will increase liquidity by an amount equal to approximately $141 million and $149 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009 and November 1, 2009, respectively, and 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 will make its May 2009 and November 2009 interest payments by using the PIK feature of the TCEH Toggle Notes. The elections will increase the interest rate on the TCEH Toggle Notes from 10.50% to 11.25% during the applicable interest periods and require TCEH to issue an additional approximately $98.5 million and $104 million principal amount of TCEH Toggle Notes on May 1, 2009 and November 1, 2009, respectively. In addition, the elections will increase liquidity by an amount equal to approximately $92 million and $97 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009 and November 1, 2009, respectively, and 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.

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 March 31, 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.

14

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 Co-Issuer’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes and collectively with the TCEH Cash-Pay Notes, the TCEH Senior 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 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.

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) 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.

15

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. Senior 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 the 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.

TCEH has entered into an interest rate swap transaction pursuant to which semiannual payment (settled quarterly) of the floating interest rates at LIBOR on an aggregate of $2.095 billion of senior secured term loans of TCEH were exchanged for floating interest rates at LIBOR plus 0.21% receivable monthly. TCEH has also entered into interest rate basis swap transactions pursuant to which quarterly payment of the floating interest rates at LIBOR on an aggregate of $10.95 billion of senior secured term loans of TCEH were exchanged for floating interest rates of LIBOR plus spreads ranging from 0.076% to 0.292% receivable monthly. In addition, in January and February 2009, TCEH entered into interest rate basis swap transactions 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%.

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 $205 million in the three months ended March 31, 2009. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.7 billion at March 31, 2009, of which $338 million (pre-tax) was reported in accumulated other comprehensive income.

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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 we elected to enter into as a cash management measure, EFH Corp. posted $400 million in cash and TCEH posted $50 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. At March 31, 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 $1.1 billion at March 31, 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 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 $397 million and $337 million at March 31, 2009 and December 31, 2008, respectively. The applicable rate on borrowings under this credit facility as of March 31, 2009 is 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, and substantial progress has been made on the construction of the units.

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 $2.9 billion as of March 31, 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 March 31, 2009 totaled $3.2 billion, which includes the carrying value of the project and up to approximately $260 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 intended to be utilized for these projects.

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. The TCEQ has filed the administrative record with the District Court. 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, has filed pleas to the jurisdiction that would, if granted, dismiss all but the administrative appeal. The District Court held a hearing on these matters in April 2009. We do not know when the District Court will rule on these requests. 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 its 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.

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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 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 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.

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 its financial position, results of operations or cash flows.

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Guarantees

As discussed below, we have entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions.

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 March 31, 2009, the aggregate maximum amount of residual values guaranteed was approximately $59 million with an estimated residual recovery of approximately $64 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.

Indebtedness guarantee —In 1990, EFC Holdings repurchased an electric co-op’s minority ownership interest in the Comanche Peak nuclear generation plant and guaranteed the co-op’s indebtedness to the US government for the facilities. The indebtedness is included in long-term debt reported in the consolidated balance sheet. EFC Holdings is making principal and interest payments to the co-op in an amount sufficient for the co-op to make payments on its indebtedness, but in the event that the co-op fails to make its payments on the indebtedness, EFC Holdings would then directly owe such payments to the US government. At March 31, 2009, the balance of the indebtedness was $107 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities.

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 March 31, 2009, TCEH had outstanding letters of credit under its credit facilities totaling $795 million as follows:

• $348 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;

• $115 million to support obligations under the lease agreement for an EFH Corp. office building;

• $50 million for collateral funding transactions with counterparties to interest rate swap agreements related to TCEH debt (see Note 4), and

• $74 million for miscellaneous credit support requirements.

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6. EQUITY

Dividend Restrictions

The indenture governing the EFH Corp. Senior Cash-Pay and Toggle 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, the consolidated leverage ratio of the company 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 the company would be insolvent.

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

Noncontrolling Interests

In November 2008, Oncor issued and sold additional 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. At the closing of the sale, Oncor also offered and indirectly sold additional equity interests to certain members of its management team. Accordingly, after giving effect to all equity issuances, Oncor’s ownership is 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 March 31, 2009 in the table below, $1.360 billion related to Oncor’s noncontrolling interests.

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. Of the noncontrolling interests balance at March 31, 2009 in the table below, $26 million related to MHI’s interests in the joint venture. This joint venture is consolidated with EFH Corp. as a variable interest entity under FIN 46R.

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Equity

The following table presents the changes to equity during the three months ended March 31, 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		—		—		442			—			12			454
Effects of EFH Corp. stock-based incentive compensation plans (Note 12)		—		5		—			—			—			5
Net effects of cash flow hedges		—		—		—			9			—			9
Distributions to noncontrolling interests		—		—		—			—			(7	)		(7	)
Investment by noncontrolling interests		—		—		—			—			26			26
Balance at March 31, 2009	$	—	$	8,050	$	(10,756	)	$	(370	)	$	1,386		$	(1,690	)

(a) Authorized shares totaled 2,000,000,000 as of March 31, 2009. Outstanding shares totaled 1,666,630,298 and 1,667,149,663 as of March 31, 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 as of March 31, 2009, has sold forward natural gas over the period from 2009 to 2014. These transactions have effectively hedged a majority of electricity price exposure related to expected baseload generation for the five-year period beginning 2009. Changes in the fair value of the instruments under the long-term hedging program are recorded 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 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.

The following table provides detail of commodity and other derivative contractual assets and liabilities as presented in the balance sheet at March 31, 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	$	3,765	$	118	$	4		$	—		$	4	$	3,891
Noncurrent assets		1,772		—		3			—			—		1,775
Current liabilities		1		—		3,363			663			—		4,027
Noncurrent liabilities		2		—		742			1,192			—		1,936
Net assets (liabilities)	$	5,534	$	118	$	(4,098	)	$	(1,855	)	$	4	$	(297	)

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Margin deposits related to these derivative instruments are reported separately in the balance sheet and totaled $210 million in net liabilities and $190 million in net liabilities at March 31, 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 months ended March 31, 2009:

Derivative	Income statement presentation	Amount
Commodity contracts	Net gain (loss) from commodity hedging and trading activities	$	1,155
Interest rate swaps	Interest expense and related charges (a)		45
	Net gain	$	1,200

(a) Includes unrealized mark-to-market net gains totaling $205 million, less amounts accrued or settled under interest rate swaps totaling $160 million.

The following table presents 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 months ended March 31, 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	$	(40	)
Commodity contracts:		(26	)	Fuel, purchased power costs and delivery fees		—
				Operating revenues		(1	)
Total	$	(26	)		$	(41	)

Note: There were no ineffectiveness gains or losses in the three months ended March 31, 2009.

Accumulated other comprehensive income related to cash flow hedges at March 31, 2009 totaled $229 million in net losses (after-tax), substantially all of which relates to interest rate swaps. We expect that $121 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of March 31, 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 March 31, 2009:

Derivative type	Notional Volume		Unit of Measure
Interest rate swaps:
Floating/fixed	$	19,250	Million US dollars
Basis	$	18,045	Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		3,662	Million MMBtu
Locational basis swaps		1,029	Million MMBtu
All other		1,340	Million MMBtu
Electricity		205,468	GWh
Coal		12	Million tons
Fuel oil		84	Million gallons

(a) Represents gross notional forward sales, purchases and options of fixed and basis transactions in the long-term hedging program. The net amount of these transactions is 1.9 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 March 31, 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 $1.524 billion. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $203 million as of March 31, 2009. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of March 31, 2009, the remaining related liquidity requirement would have totaled $51 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 March 31, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $2.292 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 $450 million as of March 31, 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 March 31, 2009, the remaining related liquidity requirement would have totaled $1.303 billion after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 12 of our 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 $3.816 billion at March 31, 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.

We also manage our counterparty credit exposure with respect to derivative and other assets.

8. FAIR VALUE MEASUREMENTS

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 March 31, 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	$	1,555	$	3,700	$	283	$	10	$	5,548
Interest rate swaps		—		118		—		—		118
Nuclear decommissioning trust (c)		100		273		—		—		373
Total assets	$	1,655	$	4,091	$	283	$	10	$	6,039
Liabilities:
Commodity-related contracts	$	1,903	$	1,834	$	361	$	10	$	4,108
Interest rate swaps		—		1,855		—		—		1,855
Total liabilities	$	1,903	$	3,689	$	361	$	10	$	5,963

(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) Our 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 (b)		109		276		—		385
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)    Our nuclear decommissioning trust investment is included in the Investments line on the balance sheet.

Commodity-related contracts consist primarily of natural gas and electricity 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 months ended March 31, 2009 and 2008:

	Three Months Ended March 31, 2009			Three Months Ended March 31, 2008
Balance at December 31, 2008 and December 31, 2007	$	(72	)	$	(173	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		16			(128	)
Included in other comprehensive income (loss)		(26	)		1
Purchases, sales, issuances and settlements (net) (b)		(16	)		15
Net transfers in and/or out of Level 3 (c)		20			13
Balance at March 31, 2009 and March 2008 (net liability)	$	(78	)	$	(272	)
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period	$	7		$	(117	)

(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 were 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.

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

Net pension and OPEB costs for the three months ended March 31, 2009 and 2008 are comprised of the following:

	Three Months Ended March 31,
	2009			2008
Components of net pension costs:
Service cost	$	9		$	9
Interest cost		39			37
Expected return on assets		(42	)		(44	)
Prior service cost		—			—
Net loss		2			—
Net pension costs		8			2
Components of net OPEB costs:
Service cost		3			2
Interest cost		15			15
Expected return on assets		(3	)		(5	)
Prior service cost		—			—
Net loss		3			4
Net OPEB costs		18			16
Net pension and OPEB costs		26			18
Less amounts deferred principally as a regulatory asset or property		(16	)		(11	)
Net amounts recognized as expense	$	10		$	7

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 required pension contributions of $18 million in the first quarter of 2009. We expect to make additional required contributions of $63 million to our pension plan in the remainder of 2009.

29

10. RELATED PARTY TRANSACTIONS

In the three months ended March 31, 2009, we accrued $9 million of an annual management fee of $36 million under terms of a Management Agreement with the Sponsor Group. 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 party to certain commodity and interest rate hedging transactions with us in the normal course of business.

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

30

11. 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 discontinued operations, 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 account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

	Three Months Ended March 31,
	2009			2008
Operating revenues:
Competitive Electric	$	1,766		$	1,983
Regulated Delivery		614			614
Corporate and Other		7			10
Eliminations		(248	)		(253	)
Consolidated	$	2,139		$	2,354
Affiliated revenues included in operating revenues:
Competitive Electric	$	2		$	2
Regulated Delivery		240			242
Corporate and Other		6			9
Eliminations		(248	)		(253	)
Consolidated	$	—		$	—
Net income (loss):
Competitive Electric	$	558		$	(1,217	)
Regulated Delivery		58			85
Corporate and Other		(162	)		(137	)
Consolidated	$	454		$	(1,269	)

31

12. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations

	Three Months Ended March 31,
	2009			2008
Operating revenues
Regulated	$	614		$	614
Unregulated		1,773			1,993
Intercompany sales eliminations – regulated		(240	)		(242	)
Intercompany sales eliminations – unregulated		(8	)		(11	)
Total operating revenues		2,139			2,354
Fuel, purchased power and delivery fees – unregulated (a)		(601	)		(821	)
Net gain (loss) from commodity hedging and trading activities – unregulated		1,128			(1,567	)
Operating costs – regulated		(221	)		(198	)
Operating costs – unregulated		(166	)		(159	)
Depreciation and amortization – regulated		(125	)		(120	)
Depreciation and amortization – unregulated		(282	)		(275	)
Selling, general and administrative expenses – regulated		(44	)		(42	)
Selling, general and administrative expenses – unregulated		(202	)		(175	)
Franchise and revenue-based taxes – regulated		(60	)		(61	)
Franchise and revenue-based taxes – unregulated		(25	)		(25	)
Impairment of goodwill		(90	)		—
Other income		13			14
Other deductions		(11	)		(16	)
Interest income		1			5
Interest expense and other charges		(667	)		(843	)
Income (loss) before income taxes	$	787		$	(1,929	)
(a)    Includes unregulated cost of fuel consumed of $284 million and $325 million for the three months ended March 31, 2009 and 2008, respectively. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

Stock-Based Compensation

Under the terms of the EFH Corp. 2007 Stock Incentive Plan, options to purchase 1.4 million and 7.5 million shares of our common stock were issued to certain management employees, directors and advisors in the three months ended March 31, 2009 and 2008, respectively. Vested awards must be exercised within 10 years of the grant date. The terms of substantially all of the options were fixed at grant date. Options to purchase 2.7 million shares (including 0.3 million that were vested) and 0.1 million were forfeited during the three-month periods ended March 31, 2009 and 2008, respectively.

In addition, zero and 0.6 million restricted shares of common stock were granted in the three months ended March 31, 2009 and 2008, respectively, and 0.1 million and zero shares of common stock were awarded as compensation in the three months ended March 31, 2009 and 2008, respectively, to management employees and directors. Of the restricted shares, 32,500 vested in both three-month periods ended March 31, 2009 and 2008.

Expenses recognized for options granted totaled $3.1 million and $2.5 million for the three months ended March 31, 2009 and 2008, respectively. Expenses recognized for share awards (restricted and unrestricted) totaled $2.5 million and $1.5 million for the three months ended March 31, 2009 and 2008, respectively.

32

Other Income and Deductions

	Three Months Ended March 31,
	2009		2008
Other income:
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting	$	10	$	11
Mineral rights royalty income		1		1
Other		2		2
Total other income	$	13	$	14
Other deductions:
Net charges related to cancelled development of generation facilities	$	1	$	5
Severance charges		5		—
Costs related to 2006 cities rate settlement		1		6
Other		4		5
Total other deductions	$	11	$	16

Interest Expense and Related Charges

	Three Months Ended March 31,
	2009			2008
Interest	$	873		$	871
Unrealized mark-to-market net gain on interest rate swaps		(205	)		—
Amortization of interest rate swap losses at dedesignation of hedge accounting		40			(1	)
Amortization of fair value debt discounts resulting from purchase accounting		19			18
Amortization of debt issuance costs and discounts		35			31
Capitalized interest, primarily related to generation facility and regulated utility asset construction		(95	)		(76	)
Total interest expense and related charges	$	667		$	843

Restricted Cash

	At March 31, 2009				At December 31, 2008
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 4)	$	—	$	1,250	$	—	$	1,250
Amounts related to margin deposits held		1		—		4		—
Amounts related to securitization (transition) bonds		52		16		51		17
Total restricted cash	$	53	$	1,266	$	55	$	1,267

33

Inventories by Major Category

	March 31, 2009		December 31, 2008
Materials and supplies	$	205	$	199
Fuel stock		186		162
Natural gas in storage		33		65
Total inventories	$	424	$	426

Investments

	March 31, 2009		December 31, 2008
Nuclear decommissioning trust	$	373	$	385
Assets related to employee benefit plans, including employee savings programs, net of distributions		193		210
Land		44		44
Miscellaneous other		5		6
Total investments	$	615	$	645

Property, Plant and Equipment

As of March 31, 2009 and December 31, 2008, property, plant and equipment of $29.6 billion and $29.5 billion, respectively, is stated net of accumulated depreciation and amortization of $5.9 billion and $5.6 billion, respectively.

Asset Retirement Obligations

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor’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 three months ended March 31, 2009:

Asset retirement liability at January 1, 2009	$	859
Additions:
Accretion		15
Reductions:
Payments, essentially all mining reclamation		(7	)
Asset retirement liability at March 31, 2009	$	867

34

Oncor’s Regulatory Assets and Liabilities

	March 31, 2009		December 31, 2008
Regulatory assets
Generation-related regulatory assets securitized by transition bonds	$	840	$	865
Employee retirement costs		661		659
Self-insurance reserve (primarily storm recovery costs)		213		214
Nuclear decommissioning cost under-recovery		151		127
Securities reacquisition costs		95		97
Recoverable deferred income taxes – net		77		77
Employee severance costs		20		20
Other		16		12
Total regulatory assets		2,073		2,071
Regulatory liabilities
Committed spending for demand-side management initiatives		93		96
Investment tax credit and protected excess deferred taxes		48		49
Over-collection of securitization (transition) bond revenues		23		28
Deferred advanced metering system revenues		19		—
Other regulatory liabilities		11		6
Total regulatory liabilities		194		179
Net regulatory assets	$	1,879	$	1,892

Regulatory assets that have been reviewed and approved by the PUCT and are not earning a return totaled $1.022 billion and $1.021 billion at March 31, 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 March 31, 2009,regulatory assets totaling $936 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 timing of the surcharges and the expenditures for advanced metering facilities, including an allowed return, as a regulatory asset or liability. As indicated in the table above, the regulatory liability at March 31, 2009 totaled $19 million.

Exit Liabilities

As part of purchase accounting, we accrued $54 million in costs expected to be incurred related to the termination and transition of outsourcing arrangements. In the three months ended March 31, 2009, we incurred $10 million of the exit liabilities and the remaining accrual is expected to be settled no later than June 30, 2011, the targeted date of completion of transition of outsourced activities back to us or to service providers.

35

Other Noncurrent Liabilities and Deferred Credits

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

	March 31, 2009		December 31, 2008
Uncertain tax positions (including accrued interest)	$	1,800	$	1,780
Retirement plan and other employee benefits		1,441		1,451
Asset retirement obligations		867		859
Unfavorable purchase and sales contracts		720		727
Liabilities related to subsidiary tax sharing agreement		298		299
Other		79		89
Total other noncurrent liabilities and deferred credits	$	5,205	$	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.

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $7 million in both three months ended March 31, 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 three months ended March 31, 2009 of $1 million reflected changes in temporary differences.

36

Supplemental Cash Flow Information

	Three Months Ended March 31,
	2009			2008
Cash payments (receipts) related to:
Interest paid	$	541		$	571
Capitalized interest		(95	)		(76	)
Interest paid (net of capitalized interest)		446			495
Income taxes		(97	)		(6	)
Noncash investing and financing activities:
Noncash construction expenditures (a)		123			184
Capital leases		10			4
(a)    Represents end-of-period accruals.

37

13. 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). 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 EFH Corp. Indenture 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 and cash flows of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the three months ended March 31, 2009 and 2008 and the condensed consolidating balance sheets as of March 31, 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 $4.5 billion EFH Corp. Notes to the Guarantors (see Notes 4 and 5).

EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $18 million and $57 million for the three months ended March 31, 2009 and 2008, respectively.

38

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Three Months Ended March 31, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,139		$	—		$	2,139
Fuel, purchased power costs and delivery fees		—			—			(601	)		—			(601	)
Net gain from commodity hedging and trading activities		—			—			1,128			—			1,128
Operating costs		—			—			(387	)		—			(387	)
Depreciation and amortization		—			—			(407	)		—			(407	)
Selling, general and administrative expenses		(28	)		—			(218	)		—			(246	)
Franchise and revenue-based taxes		—			—			(85	)		—			(85	)
Impairment of goodwill		—			—			(90	)		—			(90	)
Other income		—			—			13			—			13
Other deductions		—			—			(11	)		—			(11	)
Interest income		51			—			24			(74	)		1
Interest expense and related charges		(235	)		(141	)		(503	)		212			(667	)
Income (loss) before income taxes and equity earnings of subsidiaries		(212	)		(141	)		1,002			138			787
Income tax (expense) benefit		70			46			(403	)		(46	)		(333	)
Equity earnings of subsidiaries		584			622			—			(1,206	)		—
Net income (loss)		442			527			599			(1,114	)		454
Net income attributable to noncontrolling interests		—			—			(12	)		—			(12	)
Net income attributable to EFH Corp.	$	442		$	527		$	587		$	(1,114	)	$	442

39

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Three Months Ended March 31, 2008

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,354		$	—		$	2,354
Fuel, purchased power costs and delivery fees		—			—			(821	)		—			(821	)
Net loss from commodity hedging and trading activities		—			—			(1,567	)		—			(1,567	)
Operating costs		—			—			(357	)		—			(357	)
Depreciation and amortization		—			—			(395	)		—			(395	)
Selling, general and administrative expenses		(22	)		—			(195	)		—			(217	)
Franchise and revenue-based taxes		—						(86	)		—			(86	)
Other income		—			—			14			—			14
Other deductions		(2	)		—			(14	)		—			(16	)
Interest income		39			10			33			(77	)		5
Interest expense and related charges		(226	)		(135	)		(690	)		208			(843	)
Loss before income taxes and equity earnings of subsidiaries		(211	)		(125	)		(1,724	)		131			(1,929	)
Income tax benefit		69			42			593			(44	)		660
Equity earnings of subsidiaries		(1,127	)		(1,115	)		—			2,242			—
Net income (loss)	$	(1,269	)	$	(1,198	)	$	(1,131	)	$	2,329		$	(1,269	)

40

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Three Months Ended March 31, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities		(12	)		14			624			(36	)		590
Cash flows – financing activities:
Issuances of long-term borrowings		—			—			212			—			212
Retirements of long-term borrowings		—			(1	)		(151	)		—			(152	)
Change in short-term borrowings		—			—			60			—			60
Contributions from noncontrolling interests		—			—			26			—			26
Distributions paid to noncontrolling interests		—			—			(7	)		—			(7	)
Cash dividends paid		—			(18	)		(18	)		36			—
Change in advances – affiliates		—			—			(37	)		37			—
Other, net		—			—			(1	)		—			(1	)
Cash provided by (used in) financing activities		—			(19	)		84			73			138
Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(635	)		—			(635	)
Redemption of investment held in money market fund		—			—			142			—			142
Investment posted with counterparty		(400	)		—			—			—			(400	)
Proceeds from sale of environmental allowances and credits		—			—			4			—			4
Purchases of environmental allowances and credits		—			—			(9	)		—			(9	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			1,402			—			1,402
Investments in nuclear decommissioning trust fund securities		—			—			(1,406	)		—			(1,406	)
Change in advances – affiliates		32			5			—			(37	)		—
Other, net		—			—			20			—			20
Cash provided by (used in) investing activities		(368	)		5			(482	)		(37	)		(882	)
Net change in cash and cash equivalents		(380	)		—			226			—			(154	)
Cash and cash equivalents – beginning balance		1,075			—			614			—			1,689
Cash and cash equivalents – ending balance	$	695		$	—		$	840		$	—		$	1,535

41

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Three Months Ended March 31, 2008

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities		(40	)		54			(60	)		(114	)		(160	)
Cash flows – financing activities:
Issuances of long-term borrowings/securities:
Long-term debt		—			—			149			—			149
Common stock		28			—			—			—			28
Retirements/repurchases of long-term debt		(200	)		(1	)		(86	)		—			(287	)
Change in short-term borrowings		—			—			791			—			791
Cash dividends paid		—			(57	)		(57	)		114			—
Change in advances – affiliates		181			4			—			(185	)		—
Other, net		—			—			8			—			8
Cash provided by (used in) financing activities		9			(54	)		805			(71	)		689
Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(768	)		—			(768	)
Proceeds from sale of environmental allowances and credits		—			—			20			—			20
Purchases of environmental allowances and credits		—			—			(12	)		—			(12	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			396			—			396
Investments in nuclear decommissioning trust fund securities		—			—			(400	)		—			(400	)
Change in advances – affiliates		—			—			(185	)		185			—
Other, net		—			—			40			—			40
Cash provided by (used in) investing activities		—			—			(909	)		185			(724	)
Net change in cash and cash equivalents		(31	)		—			(164	)		—			(195	)
Cash and cash equivalents – beginning balance		32			—			249			—			281
Cash and cash equivalents – ending balance	$	1		$	—		$	85		$	—		$	86

42

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at March 31, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	695		$	—		$	840	$	—		$	1,535
Investment posted with counterparty		400			—			—		—			400
Restricted cash		—			—			53		—			53
Advances to affiliates		346			4			—		(350	)		—
Trade accounts receivable – net		10			—			882		—			892
Income taxes receivable		—			1			—		(1	)		—
Notes receivable from affiliates		—			—			636		(636	)		—
Inventories		—			—			424		—			424
Commodity and other derivative contractual assets		118			—			3,773		—			3,891
Accumulated deferred income taxes		72			8			207		—			287
Margin deposits related to commodity positions		—			—			465		—			465
Other current assets		6			—			145		—			151
Total current assets		1,647			13			7,425		(987	)		8,098
Restricted cash		—			—			1,266		—			1,266
Investments		4,476			3,408			550		(7,819	)		615
Property, plant and equipment – net		—			—			29,612		—			29,612
Notes receivable from affiliates		12			—			2,264		(2,276	)		—
Goodwill		—			—			14,316		—			14,316
Intangible assets – net		—			—			3,009		—			3,009
Regulatory assets – net		—			—			1,879		—			1,879
Commodity and other derivative contractual assets		—			—			1,775		—			1,775
Accumulated deferred income taxes		502			—			—		(502	)		—
Unamortized debt issuance costs and other noncurrent assets		129			105			689		(105	)		818
Total assets	$	6,766		$	3,526		$	62,785	$	(11,689	)	$	61,388
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,297	$	—		$	1,297
Advances from affiliates		—			—			350		(350	)		—
Long-term debt due currently		3			8			312		—			323
Trade accounts payable		6			—			788		—			794
Notes payable to affiliates		584			16			36		(636	)		—
Commodity and other derivative contractual liabilities		152			—			3,875		—			4,027
Margin deposits related to commodity positions		—			—			616		—			616
Accrued interest		284			221			572		(219	)		858
Other current liabilities		63			—			447		(1	)		509
Total current liabilities		1,092			245			8,293		(1,206	)		8,424
Accumulated deferred income taxes		—			1			6,984		(502	)		6,483
Investment tax credits		—			—			41		—			41
Commodity and other derivative contractual liabilities		—			—			1,936		—			1,936
Notes or other liabilities due affiliates		2,019			—			257		(2,276	)		—
Long-term debt, less amounts due currently		6,353			4,597			34,539		(4,500	)		40,989
Other noncurrent liabilities and deferred credits		378			2			4,825		—			5,205
Total liabilities		9,842			4,845			56,875		(8,484	)		63,078
EFH Corp. shareholders’ equity		(3,076	)		(1,319	)		4,524		(3,205	)		(3,076	)
Noncontrolling interests in subsidiaries		—			—			1,386		—			1,386
Total equity		(3,076	)		(1,319	)		5,910		(3,205	)		(1,690	)
Total liabilities and equity	$	6,766		$	3,526		$	62,785	$	(11,689	)	$	61,388

43

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

44

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 March 31, 2009, and the related condensed statements of consolidated income (loss), comprehensive income (loss) and cash flows for the three-month periods ended March 31, 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.

As discussed in Note 1 to the condensed consolidated financial statements, EFH Corp. adopted FASB Statement No. 160,Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS 160”) on a retrospective basis.

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 prior to retrospective adjustment for the adoption of SFAS 160 (not presented herein); and in our report dated March 2, 2009 (which report includes an explanatory paragraph related to (1) 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, (2) the retrospective adoption of FASB Staff Position No. 39-1 and (3) the retrospective reclassification of the results of EFH Corp.’s commodity hedging and trading activities), we expressed an unqualified opinion on those consolidated financial statements. We also audited the adjustments described in Note 1 that were applied to retrospectively adjust the December 31, 2008 consolidated balance sheet of Energy Future Holdings Corp. and subsidiaries (not presented herein). In our opinion, such adjustments are appropriate and have been properly applied to the previously issued consolidated balance sheet in deriving the accompanying retrospectively adjusted condensed consolidated balance sheet as of December 31, 2008.

/s/ Deloitte & Touche LLP

Dallas, Texas

April 30, 2009

45

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 months ended March 31, 2009 and 2008 should be read in conjunction with our audited 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 11 to Financial Statements for further information regarding reportable business segments.

46

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 March 31, 2009, has effectively sold forward approximately 1.9 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 240,000 GWh at an assumed 8.0 market heat rate) over the period from 2009 to 2014 at average annual sales prices ranging from $7.20 per MMBtu to $8.05 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 79% of the natural gas price exposure related to our expected baseload generation for the five-year period beginning in April 2009 (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. If market heat rates decline in the future, which would indicate a lessening of such correlation, 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 2009 period.

Beginning in the second quarter of 2008, the company entered into related put and call transactions (referred to as collars), primarily for outer years 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 March 31, 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. Both collars and, as has been the case, swap transactions are expected to be employed for 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 March 31, 2009:

	Measure	Balance 2009	2010	2011	2012	2013	2014	Total
Natural gas hedge volumes (a)	mm MMBtu	~146	~409	~496	~492	~300	~99	~1,942
Weighted average hedge price (b)	$/MMBtu	~8.05	~7.82	~7.56	~7.36	~7.19	~7.80	—
Weighted average market price (c)	$/MMBtu	~4.30	~5.93	~6.67	~6.96	~7.11	~7.18	—

(a) Where collars are reflected, the volumes are estimated based on the natural gas 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 100 million MMBtu.

(b) Where collars are reflected, sales price represents the collar floor price.

(c) Based on NYMEX Henry Hub prices.

47

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 March 31, 2009, a $1.00/MMBtu change in natural gas prices across the period from 2009 through 2014 would result in the recognition of up to approximately $1.9 billion in pretax unrealized mark-to-market gains or losses.

Reported unrealized mark-to-market net gains for the three months ended March 31, 2009 totaled approximately $1.1 billion, reflecting declines in 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 losses or gains related to positions in the long-term hedging program totaled a net gain of $2.0 billion and $871 million at March 31, 2009 and December 31, 2008, respectively. These values can change materially as market conditions change.

As of March 31, 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 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 our unhedged position and forward prices as of March 31, 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		2010		2011		2012		2013
$1.00/MMBtu change in gas price (a)	$	~3	$	~45	$	~60	$	~110	$	~285
0.1/MWh/MMBtu change in market heat rate (b)	$	~2	$	~35	$	~50	$	~60	$	~60
$1.00/gallon change in diesel fuel price	$	—	$	—	$	~30	$	~50	$	~50
$10.00/pound change in uranium/nuclear fuel	$	—	$	~10	$	~10	$	~20	$	~10

(a) 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).

(b) Based on Houston Ship Channel natural gas prices as of March 31, 2009.

TCEH Interest Rate Swap Transactions— As of March 31, 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 the first quarter of 2009. Taking into consideration these swap transactions, approximately 7% of our total long-term debt portfolio at March 31, 2009 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions on an aggregate of $18.045 billion of senior secured term loans, including $5 billion entered into in January and February 2009. 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 $205 million for the three months ended March 31, 2009. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.7 billion at March 31, 2009, of which $338 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.

48

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 substantial progress has been made on the construction of the units. The expected commercial operation dates of the units are as follows: Sandow in mid 2009 and Oak Grove’s two units 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 $2.8 billion was spent as of March 31, 2009. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $5.0 billion upon completion of the units, and the balance was $4.2 billion as of March 31, 2009. See discussion in Note 5 to Financial Statements under “Litigation Related to Generation Facilities” regarding pending litigation related to the Oak Grove units.

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.

The DOE continues to review TCEH’s loan guarantee application for financing the proposed units.

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. ERCOT has initiated negotiations with us to potentially continue for reliability purposes the operations of one unit, totaling 115 MW of capacity (115 MW of installed nameplate capacity) planned to be retired and one unit, totaling 515 MW of capacity (540 MW of installed nameplate capacity) planned to be mothballed. The other units are scheduled to be retired or mothballed.

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 March 31, 2009, Oncor has installed approximately 160 thousand advanced digital meters, including approximately 120 thousand in the three months ended March 31, 2009.

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

49

RESULTS OF OPERATIONS

Consolidated Financial Results — Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

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

Operating revenues decreased $215 million, or 9%, to $2.139 billion in 2009.

• Operating revenues in the Competitive Electric segment decreased $217 million, or 11%, to $1.766 billion.

• Operating revenues in the Regulated Delivery segment remained at $614 million.

• Net intercompany sales eliminations decreased $2 million, reflecting lower sales by Oncor to REP subsidiaries of TCEH, while Oncor’s sales to nonaffiliated REPs increased.

Fuel, purchased power costs and delivery fees decreased $220 million, or 27%, to $601 million. See discussion below in the analysis of Competitive Electric segment results of operations.

Results from commodity hedging and trading activities totaled $1.128 billion in net gains in 2009 compared to $1.567 billion in net losses in 2008. Results in 2009 included unrealized mark-to-market net gains totaling $1.049 billion, 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 $30 million, or 8%, to $387 million.

• Operating costs in the Competitive Electric segment increased $9 million, or 6%, to $168 million.

• Operating costs in the Regulated Delivery segment increased $23 million, or 12%, to $221 million.

Depreciation and amortization increased $12 million, or 3%, to $407 million.

• Depreciation and amortization in the Competitive Electric segment increased $7 million, or 3%, to $276 million.

• Depreciation and amortization in the Regulated Delivery segment increased $5 million, or 4%, to $125 million.

SG&A expenses increased $29 million, or 13%, to $246 million in 2009.

• SG&A expenses in the Competitive Electric segment increased $20 million, or 13%, to $173 million.

• SG&A expenses in the Regulated Delivery segment increased $2 million, or 5%, to $44 million.

• Corporate and Other SG&A expenses increased $7 million, or 32%, to $29 million driven by $4 million in consulting expenses primarily associated with the transition of outsourced services. The remaining increase reflects an intercompany elimination that is offset in revenues.

50

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

Other income totaled $13 million in 2009 and $14 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 $11 million in 2009 and $16 million in 2008. See Note 12 to Financial Statements for details of other income and deductions.

Interest expense and related charges decreased $176 million to $667 million in 2009 reflecting a $205 million unrealized mark-to-market net gain related to interest rate swaps. There was an increase of $29 million partially offsetting the effect of the unrealized mark-to-market net gain, which reflected a $41 million increase in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges, $29 million in higher average borrowings and a $5 million increase in amortization of debt issuance costs, partially offset by $27 million in lower average rates and $19 million in increased capitalized interest. Lower average interest rates reflected higher borrowings under TCEH credit facilities and the benefits of interest rate basis swaps.

Income tax expense totaled $333 million in 2009 compared to an income tax benefit of $660 million in 2008. The effective rate on income in 2009 was 42.3% and the effective rate on a loss in 2008 was 34.2%. The increase in the rate reflects the nondeductible goodwill impairment in 2009 and the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.

Net income increased $1.723 billion to $454 million in 2009.

• Results in the Competitive Electric segment increased $1.775 billion to $558 million.

• Earnings in the Regulated Delivery segment decreased $27 million to $58 million.

• Corporate and Other net expenses totaled $162 million in 2009 and $137 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 $25 million was driven by $20 million of the goodwill impairment discussed above.

51

Competitive Electric Segment

Financial Results

	Three Months Ended March 31,
	2009			2008
Operating revenues	$	1,766		$	1,983
Fuel, purchased power costs and delivery fees		(843	)		(1,064	)
Net gain (loss) from commodity hedging and trading activities		1,128			(1,567	)
Operating costs		(168	)		(159	)
Depreciation and amortization		(276	)		(269	)
Selling, general and administrative expenses		(173	)		(153	)
Franchise and revenue-based taxes		(25	)		(25	)
Impairment of goodwill		(70	)		—
Other income		3			3
Other deductions		(10	)		(10	)
Interest income		8			11
Interest expense and related charges		(425	)		(620	)
Income (loss) before income taxes		915			(1,870	)
Income tax (expense) benefit		(357	)		653
Net income (loss)	$	558		$	(1,217	)

52

Competitive Electric Segment

Sales Volume and Customer Count Data

	Three Months Ended March 31,
	2009		2008		Change %
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential	5,880		6,115		(3.8	)
Small business (a)	1,722		1,693		1.7
Large business and other customers	3,305		3,339		(1.0	)
Total retail electricity	10,907		11,147		(2.2	)
Wholesale electricity sales volumes	9,792		10,490		(6.7	)
Net sales (purchases) of balancing electricity to/from ERCOT	(153	)	(244	)	37.3
Total sales volumes	20,546		21,393		(4.0	)
Average volume (kWh) per retail customer (b):
Residential	3,059		3,281		(6.8	)
Small business	6,270		6,234		(0.6	)
Weather (service territory average) – percent of normal (c):
Heating degree days	87.7	%	94.3	%	(7.0	)
Customer counts:
Retail electricity customers (end of period and in thousands) (d):
Residential	1,930		1,871		3.2
Small business (a)	275		270		1.9
Large business and other customers	24		33		(27.3	)
Total retail electricity customers	2,229		2,174		2.5

(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. March 31, 2008 amounts reflect a reclassification of 18 thousand meters from residential to small business to conform to current presentation.

53

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Three Months Ended March 31,
	2009			2008			Change %
Operating revenues:
Retail electricity revenues:
Residential	$	793		$	771		2.9
Small business (a)		264			244		8.2
Large business and other customers		314			316		(0.6	)
Total retail electricity revenues		1,371			1,331		3.0
Wholesale electricity revenues (b)		348			625		(44.3	)
Net sales (purchases) of balancing electricity to/from ERCOT		(23	)		(35	)	34.3
Amortization of intangibles (c)		(11	)		(30	)	63.3
Other operating revenues		81			92		(12.0	)
Total operating revenues	$	1,766		$	1,983		(10.9	)
Commodity hedging and trading activities:
Unrealized net gains (losses) from changes in fair value (d)	$	1,155		$	(1,537	)	—
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the current period (d)		(106	)		(57	)	—
Realized net gains (losses) on settled positions		79			27		—
Total gain (loss)	$	1,128		$	(1,567	)	—

(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 we refer to as “unrealized.” For the three months ended March 31, 2009, these amounts totaled $60 million in net losses reported in wholesale electricity revenues and $41 million in net gains 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.

(d) 2008 amounts have been reclassified to include effects of changes in fair values of positions entered into and settled within the period.

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Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Three Months Ended March 31,
	2009			2008			Change %
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	29		$	23		26.1
Lignite/coal		153			155		(1.3	)
Total baseload fuel		182			178		2.2
Natural gas fuel and purchased power (a)		219			405		(45.9	)
Amortization of intangibles (b)		70			82		(14.6	)
Other costs		57			95		(40.0	)
Fuel and purchased power costs		528			760		(30.5	)
Delivery fees (c)		315			304		3.6
Total	$	843		$	1,064		(20.8	)
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	5.55		$	4.60		20.7
Lignite/coal (d)		16.93			15.58		8.7
Natural gas fuel and purchased power		43.94			65.38		(32.8	)
Delivery fees per MWh		28.59			26.82		6.6
Production and purchased power volumes (GWh):
Nuclear		5,190			4,921		5.5
Lignite/coal		10,255			10,952		(6.4	)
Total baseload generation		15,445			15,873		(2.7	)
Natural gas-fueled generation		258			526		(51.0	)
Purchased power		4,729			5,669		(16.6	)
Total energy supply		20,432			22,068		(7.4	)
Line loss and power imbalances		114			(675	)	—
Net energy supply volumes		20,546			21,393		(4.0	)
Baseload capacity factors (%):
Nuclear		104.6	%		98.1	%	6.6
Lignite/coal		81.4	%		86.1	%	(5.5	)
Total baseload		88.0	%		89.5	%	(1.7	)

(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.

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Competitive Electric Segment — Financial Results — Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

Operating revenues decreased $217 million, or 11%, to $1.766 billion in 2009.

Wholesale electricity revenues decreased $277 million, or 44%, as compared to 2008 when revenues increased 39%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 40% 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 and related volatility and a decline in congestion. 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 $40 million, or 3%, increase in retail electricity revenues reflected the following:

• A two percent decline in retail sales volumes reduced revenues by $29 million. Lower average volumes per residential customer reflected the seven percent decrease in heating degree days. Small business and large business volumes reflect decreases in general economic conditions, partially offset by usage attributable to new customers.

• Higher average pricing, principally in residential and non-contract business markets, contributed $68 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.

• Total retail electricity customer count at March 31, 2009 increased three percent from March 31, 2008 driven by a three percent increase in residential customers.

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.

Other operating revenues decreased $11 million, or 12%, to $81 million in 2009 due to the effect of lower natural gas prices on sales of natural gas to retail industrial customers.

The decrease in operating revenues was partially offset by a $19 million reduction in amortization of intangible assets arising in purchase accounting.

Fuel, purchased power costs and delivery fees decreased $221 million, or 21%, to $843 million in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand and related volatility and reduced congestion as discussed above regarding wholesale revenues. Other factors included lower average fuel costs due primarily to lower natural gas-fueled generation and lower related fuel costs ($25 million), the effect of lower natural gas prices on natural gas purchased for sale to retail industrial customers ($30 million) and lower amortization of intangible assets arising in purchase accounting ($12 million).

Overall baseload generation production decreased 3% in 2009 reflecting a 6% decrease in lignite/coal-fueled production, partially offset by a 5% increase in nuclear production. 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, as well as an increase in unplanned outages. The increase in nuclear production reflects a spring refueling outage in 2008 and no such outage in 2009.

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Results 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 results from commodity hedging and trading activities for the three months ended March 31, 2009 and 2008:

Three Months ended March 31, 2009 —Unrealized mark-to-market net gains totaling $1.049 billion included:

• $1.082 billion in net gains related to hedge positions, which includes $1.164 billion in net gains from changes in fair value and $82 million in net losses that represent reversals of previously recorded fair values of positions settled in the period, and

• $33 million in net losses related to trading positions, which includes $9 million in net losses from changes in fair value and $24 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.

Realized net gains totaling $79 million include:

• $73 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

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

Three Months Ended March 31, 2008— Unrealized mark-to-market net losses totaling $1.594 billion include:

• $1.582 billion in net losses related to hedge positions, which includes $1.565 billion in net losses from changes in fair values and $17 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

• $2 million in hedge ineffectiveness net losses related to unsettled positions accounted for as cash flow hedges;

• $9 million in net gains related to trading positions, which includes $49 million in net gains from changes in fair values and $40 million in net losses that represent reversals of previously recorded fair values of positions settled in the period, and

• $19 million in a “day one” loss related to a large hedge position (see Note 7 to Financial Statements).

Realized net gains totaling $27 million include:

• $15 million in net losses related to positions that hedged electricity revenues and fuel and purchased power costs recognized in the period, and

• $42 million in net gains related to trading positions.

Operating costs increased $9 million, or 6%, to $168 million in 2009. The increase reflected $10 million in higher maintenance costs incurred during planned and unplanned lignite-fueled plant outages in 2009, $4 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 $9 million in 2008 maintenance costs incurred for a planned nuclear generation unit outage.

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Depreciation and amortization increased $7 million, or 3%, to $276 million in 2009. The increase represents incremental amortization expense related to the intangible value of customer relationships.

SG&A expenses increased $20 million, or 13%, to $173 million in 2009. The increase reflected $5 million in higher costs associated with the transition to a new retail customer information management system, $5 million in higher retail bad debt expense, $5 million in higher costs related to consulting and employee-related expenses in generation and wholesale operations and $2 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.

Interest income decreased $3 million, or 27%, to $8 million in 2009 reflecting lower average loans to affiliates.

Interest expense and related charges decreased by $195 million, or 31%, to $425 million in 2009 reflecting a $205 million unrealized mark-to-market net gain related to interest rate swaps. There was an increase of $10 million partially offsetting the effect of the unrealized mark-to-market net gain, which reflected a $41 million increase in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges, $28 million in higher average borrowings and a $4 million increase in amortization of debt issuance costs, partially offset by $43 million in lower average rates and $20 million in increased capitalized interest. Lower average interest rates reflected higher borrowings under credit facilities and the benefits of interest rate basis swaps.

Income tax expense totaled $357 million in 2009 compared to an income tax benefit of $653 million in 2008. The effective rate was 39.0% on income in 2009 and 34.9% on a loss in 2008. The increase in the rate reflects the nondeductible goodwill impairment in 2009 and the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.

Results increased $1.775 billion to net income of $558 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.

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Regulated Delivery Segment

Financial Results

	Three Months Ended March 31,
	2009			2008
Operating revenues	$	614		$	614
Operating costs		(221	)		(198	)
Depreciation and amortization		(125	)		(120	)
Selling, general and administrative expenses		(44	)		(42	)
Franchise and revenue-based taxes		(60	)		(61	)
Other income		10			11
Other deductions		(2	)		(7	)
Interest income		9			12
Interest expense and related charges		(86	)		(76	)
Income before income taxes		95			133
Income tax expense (a)		(37	)		(48	)
Net income	$	58		$	85

(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 subject to income taxes.

Operating Data

	Three Months Ended March 31,				% Change
	2009		2008
Operating statistics:
Electric energy billed volumes (GWh)		24,227		25,655	(5.6	)
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)		81.5		85.2	(4.3	)
System Average Interruption Frequency Index (SAIFI) (nonstorm)		1.1		1.2	(8.3	)
Customer Average Interruption Duration Index (CAIDI) (nonstorm)		74.4		71.5	4.1
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)		3,128		3,101	0.9
	Three Months Ended March 31,				% Change
	2009		2008
Operating revenues:
Electricity distribution revenues (b):
Affiliated (TCEH)	$	229	$	242	(5.4	)
Nonaffiliated		302		297	1.7
Total distribution revenues		531		539	(1.5	)
Third-party transmission revenues		75		66	13.6
Other miscellaneous revenues		8		9	(11.1	)
Total operating revenues	$	614	$	614	—

(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 March 31, 2009 and 2008 data.

(b) Includes transition charge revenue associated with the issuance of securitization bonds totaling $31 million and $34 million for the three months ended March 31, 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 March 31, 2009 Compared to Three Months Ended March 31, 2008

Operating revenues totaled $614 million in both periods. Revenue in 2009 as compared to 2008 reflected:

• an estimated $21 million in lower average consumption primarily due to the effects of milder weather and general economic conditions, and

• $3 million in lower charges to REPs related to transition bonds (with a related decrease in amortization of the related regulatory asset),

offset by:

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

• $9 million in higher transmission revenues primarily due to a rate increase to recover ongoing investment in the transmission system;

• an estimated $3 million impact of growth in points of delivery, and

• $3 million from a surcharge to recover additional energy efficiency costs and $2 million from a surcharge to recover advanced metering deployment costs, both of which became effective with the January 2009 billing cycle.

Operating costs increased $23 million, or 12%, to $221 million in 2009. The increase reflected $14 million in higher fees paid to other transmission entities and $3 million in costs related to programs designed to improve customer electricity demand efficiencies, both of which have related revenue increases. The increase also reflects $5 million in increased labor and benefits costs and smartgrid services expenses.

Depreciation and amortization increased $5 million, or 4%, to $125 million in 2009. The increase reflected $9 million in higher depreciation due to ongoing investments in property, plant and equipment, partially offset by $3 million in lower amortization of the regulatory assets associated with the securitization bonds (with a related decrease in revenues).

SG&A expenses increased $2 million, or 5%, to $44 million in 2009. The increase reflected losses on certain benefit plan investments.

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 “Regulatory Assets and Liabilities” in Note 12 to Financial Statements for additional information.

Other deductions totaled $2 million in 2009 and $7 million in 2008. The 2008 amount included costs totaling $6 million associated with the 2006 settlement with certain cities related to rates.

Interest income decreased $3 million, or 25%, to $9 million in 2009. The decrease reflected lower earnings on assets held for employee benefit plans and a decrease in reimbursement of transition bond interest from TCEH reflecting lower remaining principal amounts of the bonds.

Interest expense increased $10 million, or 13%, to $86 million in 2009. The variance included a $5 million effect of higher average borrowings, reflecting the ongoing capital investment in the business, and an increase of $5 million due to higher average interest rates driven by decreased short-term borrowings due to the issuance of $1.5 billion of senior secured notes 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 agreement.

Income tax expense totaled $37 million in 2009 compared to $48 million in 2008. The effective rate increased to 38.9% in 2009 from 36.1% in 2008. The increased rate was primarily due to the non-deductibility of investment losses related to certain benefit plans.

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Net income decreased $27 million, or 32%, to $58 million in 2009 due to the effect of lower average consumption on revenues as well as increased operation and maintenance expense, depreciation and amortization and interest expense.

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

The table below summarizes the changes in commodity contract assets and liabilities for the three months ended March 31, 2009. The net change in these assets and liabilities, 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.

	Three Months Ended March 31, 2009
Commodity contract net asset (liability) at beginning of period	$	430
Settlements of positions (a)		(125	)
Unrealized mark-to-market valuations of unsettled positions (b)		1,155
Other activity (c)		(2	)
Commodity contract net asset (liability) at end of period (d)	$	1,458

(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 $18 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.

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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 March 31,
	2009		2008
Unrealized gains/(losses) related to contracts marked-to-market	$	1,030	$	(1,592	)
Ineffectiveness gains/(losses) related to cash flow hedges (a)		—		(2	)
Total unrealized gains (losses) related to commodity contracts	$	1,030	$	(1,594	)

(a) See Note 7 to Financial Statements.

Maturity Table — Following are the components of the net commodity contract asset at March 31, 2009:

	Amount
Net commodity contract asset	$	1,458
Net receipts of natural gas under physical gas exchange transactions		37
Amount of net asset arising from mark-to-market accounting	$	1,495

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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 March 31, 2009, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract asset at March 31, 2009
	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Source of fair value
Prices actively quoted	$	(247	)	$	(90	)	$	(4	)	$	—		$	(341	)
Prices provided by other external sources		812			901			189			—			1,902
Prices based on models		(6	)		(47	)		15			(28	)		(66	)
Total	$	559		$	764		$	200		$	(28	)	$	1,495
Percentage of total fair value		38	%		51	%		13	%		(2	)%		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 three months ended March 31, 2009 totaled $590 million compared to cash used of $160 million in 2008. The increase in cash provided of $750 million reflected:

• a $662 million favorable change in margin deposits primarily due to the effect of lower forward natural gas prices on positions in the long-term hedging program, and

• a $91 million decrease in cash income taxes paid.

Cash provided by financing activities decreased $551 million as summarized below:

	Three Months Ended March 31,
	2009		2008
Net repayments, repurchases and issuances of borrowings	$	118	$	650
Issuances of common stock		—		28
Net contributions and distributions of noncontrolling interests		19		—
Other		1		11
Total provided by financing activities	$	138	$	689

Cash used in investing activities increased $158 million as summarized below:

	Three Months Ended March 31,
	2009			2008
Capital expenditures, including nuclear fuel	$	(635	)	$	(768	)
Redemption of investment held in money market fund		142			—
Investment posted with counterparty		(400	)		—
Proceeds from sale of assets		—			25
Other		11			19
Total used in investing activities	$	(882	)	$	(724	)

The decline in capital spending for the three months ended March 31, 2009 as compared to the three months ended March 31, 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.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $113 million and $138 million for the three months ended March 31, 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.

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Debt Financing Activity—Activities related to short-term borrowings and long-term debt during the three months ended March 31, 2009 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases):

	Borrowings		Repayments and Repurchases
TCEH	$	212	$	123
EFC Holdings		—		1
EFH Corp.		—		5
Oncor		—		23
Total long-term		212		152
TCEH		—		—
Oncor		60		—
Total short-term (a)		60		—
Total	$	272	$	152

(a) 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, privately negotiated transactions or other transactions. 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.

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Available Liquidity — The following table summarizes changes in available liquidity for the three months ended March 31, 2009.

	Available Liquidity
	March 31, 2009		December 31, 2008		Change
Cash and cash equivalents, excluding Oncor	$	1,503	$	1,564	$	(61	)
Investments held in money market fund		—		142		(142	)
TCEH Delayed Draw Term Loan Facility		310		522		(212	)
TCEH Revolving Credit Facility (a)		1,748		1,767		(19	)
TCEH Letter of Credit Facility		481		490		(9	)
Total, excluding Oncor (b)	$	4,042	$	4,485	$	(443	)
Short-term investment (c)	$	450	$	—	$	450
Cash and cash equivalents – Oncor		32		125		(93	)
Oncor Revolving Credit Facility		1,449		1,508		(59	)
Total Oncor	$	1,481	$	1,633	$	(152	)

(a) As of March 31, 2009 and December 31, 2008, the TCEH Revolving Credit Facility includes $142 million and $144 million, respectively, of undrawn commitments from Lehman that is only available from the fronting banks and the swingline lender.

(b) 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 March 31, 2009, the total availability under the TCEH credit facilities should be further reduced by $235 million. As a result of REP certification rule changes that added market and consumer protections and amended requirements related to security held for payments to transmission and distribution utilities, this amount is expected to decline to approximately $110 million during the second quarter of 2009.

(c) Includes $400 million cash investment and $50 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 potential amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which totaled $479 million for the May and November 2009 payment dates and for the remaining payment dates from May 2010 through November 2012, could add approximately $1.4 billion of liquidity.

The decrease in available liquidity for Oncor of $152 million in the three months ended March 31, 2009 reflected ongoing capital investment in transmission and distribution infrastructure. As of March 31, 2009, availability under Oncor’s Revolving Credit Facility excluded $154 million of undrawn commitments from Lehman. In April 2009, a portion of that Lehman commitment was purchased by another entity unrelated to Lehman, effectively increasing availability by $32 million.

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 $81 million and $22 million, respectively, in 2009. Funding by Oncor represents approximately 76% of pension and 80% of the OPEB totals for 2009. We made pension and OPEB contributions of $18 million and $6 million, respectively, in the three months ended March 31, 2009.

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PIK Interest Election — EFH Corp. and TCEH have the option every six months until November 1, 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, including the effect of 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. will make its May 2009 and November 2009 interest payments by using the PIK feature of the EFH Corp. Toggle Notes. The elections will increase the interest rate on the toggle notes from 11.25% to 12.00% during the applicable interest periods and require us to issue an additional $150 million and $159 million principal amount of EFH Corp. Toggle Notes on May 1, 2009 and November 1, 2009, respectively. In addition, the elections will increase liquidity by an amount equal to approximately $141 million and $149 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009 and November 1, 2009, respectively, and 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 will make its May 2009 and November 2009 interest payments by using the PIK feature of the TCEH Toggle Notes. The elections will increase the interest rate on the TCEH Toggle Notes from 10.50% to 11.25% during the applicable interest periods and require issuance of an additional approximately $98.5 million and $104 million principal amount of TCEH Toggle Notes on May 1, 2009 and November 1, 2009, respectively. In addition, the elections will increase liquidity by an amount equal to approximately $92 million and $97 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009 and November 1, 2009, respectively, and 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 March 31, 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 March 31, 2009, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $402 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;

• $554 million in cash has been received from counterparties, net of $63 million in cash posted, for over-the-counter and other non-exchanged cleared transactions, as compared to $402 million received, net of $122 million in cash posted, as of December 31, 2008;

• $348 million in letters of credit have been posted with counterparties, as compared to $342 million posted as of December 31, 2008, and

• $36 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. On over-the-counter transactions, such counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of March 31, 2009, restricted cash collateral was immaterial. See Note 12 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 March 31, 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 expect to make payments totaling approximately $50 million related to the Texas margin tax in 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 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 $382 million and $416 million at March 31, 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 financial covenants that require maintenance of leverage ratios and/or contain a minimum net worth covenant. As of March 31, 2009, we were in compliance with all such 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 March 31, 2009 totaled $4.571 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 three and twelve months ended March 31, 2009 and 2008.

The following table summarizes various financial covenant ratios of EFH Corp. and TCEH as of March 31, 2009 and December 31, 2008 and the corresponding covenant threshold levels:

	March 31, 2009	December 31, 2008	Threshold Level
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to adjusted EBITDA ratio	4.65 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	1.5 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.3 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.3 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.3 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
Restricted Payments/Limitations on Investments:
EFH Corp. Senior Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (a)	1.3 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)	1.5 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	7.0 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	1.3 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	8.6 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 March 31, 2009 for EFH Corp. and its subsidiaries, except for Oncor, are B-, B3 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 March 31, 2009 are presented below:

	S&P	Moody’s	Fitch
EFH Corp. (Senior Unsecured) (a)	B-	Caa1	B+
EFH Corp. (Unsecured)	CCC	Caa2	CCC
EFC Holdings (Senior Unsecured)	CCC	Caa2	CCC
TCEH (Senior Secured)	B+	B1	BB
TCEH (Senior Unsecured) (b)	CCC	Caa1	B
TCEH (Unsecured)	CCC	Caa2	CCC
Oncor (Senior Secured) (c)	BBB+	Baa3	BBB
Oncor (Senior Unsecured) (c)	BBB+	Baa3	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. Moody’s ratings outlook for Oncor remains stable. 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 March 31, 2009, counterparties to those contracts could have required TCEH to post up to an aggregate of $18 million in additional collateral. This amount largely represents the below market terms of these contracts as of March 31, 2009; thus, this amount will vary depending on the value of these contracts on any given day.

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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 March 31, 2009, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $25 million, with $13 million of this amount posted for the benefit of Oncor.

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 March 31, 2009, TCEH maintained availability under its credit facilities of approximately $235 million. As a result of REP certification rule changes that added market and consumer protections and amended requirements related to security held for payments to transmission and distribution utilities, this amount is expected to decline to approximately $110 million during the second quarter 2009.

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 $34 million as of March 31, 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 ($22.127 billion at March 31, 2009) under such facilities to be accelerated.

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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 master equipment lease, which had approximately $49 million in remaining lease principal payments as of March 31, 2009, 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.

Under the terms of a TCEH rail car master lease, which had approximately $54 million in remaining lease payments as of March 31, 2009, if obligations of TCEH in the aggregate in excess of $200 million 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 where 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 $1.7 billion at March 31, 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 ($397 million at March 31, 2009) under such facility to be accelerated.

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

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

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

2009 Texas Legislative Session

The Texas Legislature convened in its regular biennial session in January 2009. The session will conclude June 1, 2009. We actively monitor and provide input regarding legislation that could impact our operations but cannot predict the outcome of the 2009 legislative process or its impact, if any, on our financial position, results of operations or cash flows.

Regulatory Investigations and Reviews

See Note 5 to Financial Statements.

Certification of REPs

In April 2009, the PUCT finalized a new rule relating to the Certification of Retail Electric Providers. The new rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the insolvency and other harmful conditions and activities of REPs. The new rule is considered a competition rule and thus is subject to judicial review as specified in PURA. The new rule, among other things, increases creditworthiness requirements and financial reporting for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the new rule, Oncor will defer uncollectible amounts owed by REPs as a regulatory asset. Recovery of the regulatory asset will be considered in a future rate case. Accordingly, Oncor will recognize an approximately $3 million one-time reduction of bad debt expense in the second quarter of 2009. Due to the commitments made in Oncor’s PUCT merger docket, Oncor would not be able to recover bad debt expense, or certain other costs and expenses, from ratepayers in the event of a TXU Energy default or bankruptcy. Also under the new rule, TCEH will no longer be required to maintain additional available liquidity related to payments to TDUs. See “Financial Condition – Liquidity and Capital Resources – Available Liquidity” above.

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.

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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 March 2009, the PUCT voted to extend the existing nodal surcharge of $0.169 per MWh until May 31, 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. The PUCT is expected to consider ERCOT’s request in a contested case docket during the summer of 2009. 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. Resolution of the proposed rate increase is expected to occur in the summer of 2009.

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 March 1, 2009. This increase is expected to increase annualized revenues by $16 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. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT. 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 2012.

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 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.

	Three Months Ended March 31, 2009		Year Ended December 31, 2008
Month-end average Trading VaR:	$	2	$	6
Month-end high Trading VaR:	$	3	$	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.

	Three Months Ended March 31, 2009		Year Ended December 31, 2008
Month-end average MtM VaR:	$	1,173	$	2,290
Month-end high MtM VaR:	$	1,470	$	3,549
Month-end low MtM VaR:	$	989	$	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.

	Three Months Ended March 31, 2009		Year Ended December 31, 2008
Month-end average EaR:	$	1,150	$	2,300
Month-end high EaR:	$	1,450	$	3,916
Month-end low EaR:	$	970	$	1,069

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

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Interest Rate Risk

As of March 31, 2009, the potential reduction of annual pretax earnings due to a one-point increase in interest rates totaled approximately $28 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 hedging and trading activities totaled $3.200 billion at March 31, 2009. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of March 31, 2009 include $652 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 March 31, 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 March 31, 2009, the exposure to credit risk from the wholesale customers and counterparties totaled $2.318 billion taking into account standardized master netting contracts and agreements described above but before taking into account $655 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.663 billion increased approximately $900 million in the three months ended March 31, 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 $1.663 billion net exposure, 96% 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 $230 million at March 31, 2009, of which $201 million represents trade accounts receivable principally from REPs. This exposure consists almost entirely of noninvestment grade trade accounts receivable. Oncor has a customer with subsidiaries who collectively represent 13% 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 March 31, 2009, for wholesale counterparties. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from 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.

	Exposure Before Credit Collateral			Credit Collateral		Net Exposure			Net Exposure by Maturity
									2 years or less		Between 2-5 years		Greater than 5 years		Total
Investment grade	$	2,197		$	607	$	1,590		$	1,196	$	378	$	16	$	1,590
Noninvestment grade		121			48		73			71		2		—		73
Totals	$	2,318		$	655	$	1,663		$	1,267	$	380	$	16	$	1,663
Investment grade		95	%				96	%
Noninvestment grade		5	%				4	%

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 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 $1.663 billion credit exposure. These two counterparties represented 45% and 38%, 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 98% 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;

• 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;

• commercial bank market and capital market conditions;

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• 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;

• economic conditions;

• 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 quarterly 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 quarterly 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 first quarter of 2009, we substantially 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 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.

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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.
Oncor Electric Delivery Company LLC
4(a)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(b)	—	Supplemental Indenture No. 2, dated May 15, 2008, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(b)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(c)	—	Supplemental Indenture No. 1, dated May 15, 2008, to Indenture and Deed of Trust, dated as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(c)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(a)	—	Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008, by Oncor Electric Delivery Company LLC, as Grantor, to and for the benefit of The Bank of New York, as Collateral Agent.
4(d)	333-100240 Form 10-K (2008) (filed March 2, 2009)	4(n)	—	First Amendment to Deed of Trust, dated as of March 2, 2009, by and between Oncor Electric Delivery Company LLC and The Bank of New York Mellon (formerly The Bank of New York) as Trustee and Collateral Agent.
(10)	Material Contracts.
Management Contracts; Compensatory Plans, Contracts and Arrangements
10(a)	333-157049 Form S-1 (filed January 30, 2009)	10(kk)	—	Severance and Release Agreement dated January 15, 2009, by and among Luminant Holding Company LLC, EFH Corp. and Michael McCall.
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.

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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 March 31, 2009.
99(b)		—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the three and twelve months ended March 31, 2009 and 2008.
99(c)		—	TCEH Consolidated Adjusted EBITDA reconciliation for the three and twelve months ended March 31, 2009 and 2008.

* Incorporated herein by reference.

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SIGNATURE

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

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

Date: April 30, 2009

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