Energy Future Holdings Corp /TX/ - FORM 10-Q

Attached files

file	filename
EX-32.(B) - SECTION 906 CERTIFICATION - PFO - Energy Future Holdings Corp /TX/	dex32b.htm
EX-99.(A) - CONDENSED STATEMENTS OF CONSOLIDATED INCOME - Energy Future Holdings Corp /TX/	dex99a.htm
EX-99.(B) - ENERGY FUTURE HOLDINGS CORP. CONSOLIDATED ADJUSTED EBITDA - Energy Future Holdings Corp /TX/	dex99b.htm
EX-32.(A) - SECTION 906 CERTIFICATION - PEO - Energy Future Holdings Corp /TX/	dex32a.htm
EX-31.(B) - SECTION 302 CERTIFICATION - PFO - Energy Future Holdings Corp /TX/	dex31b.htm
EX-99.(C) - TCEH CONSOLIDATED ADJUSTED EBITDA - Energy Future Holdings Corp /TX/	dex99c.htm
EX-31.(A) - SECTION 302 CERTIFICATION - PEO - Energy Future Holdings Corp /TX/	dex31a.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010

— 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 þ 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 þ 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 þ

As of April 30, 2010, there were 1,668,680,542 shares of common stock outstanding, stated value $0.001 per share, 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. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Condensed Statements of Consolidated Income – Three Months Ended March 31, 2010 and 2009	1

	Condensed Statements of Consolidated Comprehensive Income – Three Months Ended March 31, 2010 and 2009	2

	Condensed Statements of Consolidated Cash Flows – Three Months Ended March 31, 2010 and 2009	3

	Condensed Consolidated Balance Sheets – March 31, 2010 and December 31, 2009	4

	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	82

Item 4.	Controls and Procedures	88

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	88

Item 1A.	Risk Factors	88

Item 6.	Exhibits	89

SIGNATURE		91

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, or otherwise reflected in, their respective parent companies’ financial statements 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.

GLOSSARY

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


2009 Form 10-K		EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2009

Adjusted EBITDA		Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-Q (see reconciliation in Exhibit 99(b) and 99(c)) solely because of the important role that Adjusted EBITDA plays in respect of the certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.

Competitive Electric segment		Refers to the EFH Corp. business segment that consists principally of TCEH.

CREZ		Competitive Renewable Energy Zone

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.

EFH Corp. Senior Notes		Refers collectively to EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).

EFH Corp. Senior Secured Notes		Refers collectively to EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019 (EFH Corp. 9.75% Notes) and EFH Corp.’s 10.000% Senior Secured Notes due January 15, 2020 (EFH Corp. 10% Notes).

EFIH Finance		Refers to EFIH Finance Inc., a direct, wholly-owned subsidiary of Intermediate Holding, formed for the sole purpose of serving as co-issuer with Intermediate Holding of certain debt securities.

EFIH Notes		Refers to Intermediate Holding’s and EFIH Finance’s 9.75% Senior Secured Notes due October 15, 2019.

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

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

Fitch		Fitch Ratings, Ltd. (a credit rating agency)

GAAP		generally accepted accounting principles

GHG		greenhouse gas

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.

kWh		kilowatt-hours

Lehman		Refers to certain subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code in 2008.

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 and 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. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.

Merger		The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.

Merger Agreement		Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.

iii


MMBtu		million British thermal units

Moody’s		Moody’s Investors Services, Inc. (a credit rating agency)

MW		megawatts

MWh		megawatt-hours

NRC		US Nuclear Regulatory Commission

Oncor		Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.

Oncor Holdings		Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary 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 US GAAP, 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, which consists of the operations of Oncor.

REP		retail electric provider

RRC		Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas

S&P		Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)

SEC		US Securities and Exchange Commission

Securities Act		Securities Act of 1933, as amended


SG&A		selling, general and administrative

Sponsor Group		Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), 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 are engaged in electricity generation and wholesale and retail energy markets 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 Notes		Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 Series B (collectively, TCEH 10.25% Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).

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 6 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 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 limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries 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

PART I. FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Unaudited)

(millions of dollars)


	Three Months Ended March 31,
	2010			2009
Operating revenues	$	1,999		$	2,139
Fuel, purchased power costs and delivery fees		(1,047	)		(601	)
Net gain from commodity hedging and trading activities		1,213			1,128
Operating costs		(197	)		(387	)
Depreciation and amortization		(342	)		(407	)
Selling, general and administrative expenses		(187	)		(246	)
Franchise and revenue-based taxes		(22	)		(85	)
Impairment of goodwill		—			(90	)
Other income (Note 16)		33			13
Other deductions (Note 16)		(11	)		(11	)
Interest income		10			1
Interest expense and related charges (Note 16)		(954	)		(667	)


Income before income taxes and equity in earnings of unconsolidated subsidiaries		495			787

Income tax expense		(203	)		(333	)

Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2)		63			—


Net income		355			454

Net income attributable to noncontrolling interests		—			(12	)


Net income attributable to EFH Corp.	$	355		$	442

See Notes to Financial Statements.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

(millions of dollars)


	Three Months Ended March 31,
	2010		2009
Net income	$	355	$	454

Other comprehensive income, net of tax effects:

Reclassification of pension and other retirement benefit costs (net of tax expense of $2 and —)		4		—

Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of — and $9)		—		(17	)
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (net of tax benefit of $10 and $15)		19		26

Total effect of cash flow hedges		19		9


Total adjustments to net income		23		9


Comprehensive income		378		463

Comprehensive income attributable to noncontrolling interests		—		(12	)


Comprehensive income attributable to EFH Corp.	$	378	$	451

See Notes to Financial Statements.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(millions of dollars)


	Three Months Ended March 31,
	2010			2009
Cash flows – operating activities:
Net income	$	355		$	454
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		443			520
Deferred income tax expense – net		220			295
Impairment of goodwill		—			90
Unrealized net gains from mark-to-market valuations of commodity positions		(993	)		(1,030	)
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps		107			(205	)
Equity in earnings of unconsolidated subsidiaries		(63	)		—
Distributions of earnings from unconsolidated subsidiaries		30			—
Net gain on debt exchanges (Note 6)		(14	)		—
Bad debt expense (Note 5)		36			20
Stock-based incentive compensation expense		9			5
Losses on dedesignated cash flow hedges (interest rate swaps)		29			40
Other, net		(7	)		—
Changes in operating assets and liabilities:
Impact of accounts receivable sales program (Note 5)		(383	)		(34	)
Margin deposits – net		45			65
Deferred advanced metering system revenues		—			19
Other operating assets and liabilities		288			351

Cash provided by operating activities		102			590


Cash flows – financing activities:
Issuances of long-term debt (Note 6)		500			212
Repayments of long-term debt (Note 6)		(132	)		(152	)
Increase (decrease) in short-term borrowings (Note 6)		(700	)		60
Decrease in note payable to unconsolidated subsidiary		(9	)		—
Contributions from noncontrolling interests		6			26
Distributions paid to noncontrolling interests		—			(7	)
Net short-term borrowings under accounts receivable sales program (Note 5)		393			—
Debt discount, financing and reacquisition expenses		(10	)		(2	)
Other, net		9			1

Cash provided by financing activities		57			138


Cash flows – investing activities:
Capital expenditures		(328	)		(600	)
Nuclear fuel purchases		(44	)		(46	)
Money market fund redemptions		—			142
Investment redeemed/(posted) with derivative counterparty (Note 11)		400			(400	)
Proceeds from sale of environmental allowances and credits		3			4
Purchases of environmental allowances and credits		(5	)		(9	)
Proceeds from sales of nuclear decommissioning trust fund securities		564			1,402
Investments in nuclear decommissioning trust fund securities		(568	)		(1,406	)
Other, net		(13	)		31

Cash provided by (used in) investing activities		9			(882	)

Net change in cash and cash equivalents		168			(154	)
Effects of deconsolidation of Oncor Holdings		(29	)		—
Cash and cash equivalents – beginning balance		1,189			1,689

Cash and cash equivalents – ending balance	$	1,328		$	1,535

See Notes to Financial Statements.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)


	March 31, 2010			December 31, 2009 (see Note 2)
ASSETS
Current assets:
Cash and cash equivalents	$	1,328		$	1,189
Investment posted with counterparty (Note 11)		—			425
Restricted cash (Note 16)		17			48
Trade accounts receivable – net (2010 includes $784 in pledged amounts related to a variable interest entity (Notes 3 and 5))		1,158			1,260
Inventories		381			485
Commodity and other derivative contractual assets (Note 11)		3,752			2,391
Accumulated deferred income taxes		205			5
Margin deposits related to commodity positions		211			187
Other current assets		74			136

Total current assets		7,126			6,126

Restricted cash (Note 16)		1,135			1,149
Receivables from unconsolidated subsidiary (Note 14)		1,348			—
Investments in unconsolidated subsidiaries (Note 2)		5,489			44
Other investments (Note 16)		653			706
Property, plant and equipment – net (Note 16)		21,173			30,108
Goodwill (Note 4)		10,252			14,316
Intangible assets – net (Note 4)		2,568			2,876
Regulatory assets – net		—			1,959
Commodity and other derivative contractual assets (Note 11)		2,291			1,533
Other noncurrent assets, principally unamortized debt issuance costs		759			845

Total assets	$	52,794		$	59,662


LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (2010 includes $393 related to a variable interest entity (Notes 3 and 6))	$	646		$	1,569
Long-term debt due currently (Note 6)		250			417
Trade accounts payable		655			896
Net payables due to unconsolidated subsidiary (Note 14)		135			—
Commodity and other derivative contractual liabilities (Note 11)		3,530			2,392
Margin deposits related to commodity positions		589			520
Accrued interest		793			526
Other current liabilities		354			744

Total current liabilities		6,952			7,064

Accumulated deferred income taxes		5,198			6,131
Investment tax credits		—			37
Commodity and other derivative contractual liabilities (Note 11)		1,132			1,060
Notes or other liabilities due to unconsolidated subsidiary (Note 14)		208			—
Long-term debt, less amounts due currently (Note 6)		36,879			41,440
Other noncurrent liabilities and deferred credits (Note 16)		5,230			5,766

Total liabilities		55,599			61,498
Commitments and Contingencies (Note 7)

Equity (Note 8):
EFH Corp. shareholders’ equity		(2,859	)		(3,247	)
Noncontrolling interests in subsidiaries		54			1,411

Total equity		(2,805	)		(1,836	)

Total liabilities and equity	$	52,794		$	59,662

See Notes to Financial Statements.

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 with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, 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. See Note 3 regarding the deconsolidation of Oncor (and its majority owner, Oncor Holdings) as a result of amended consolidation accounting standards related to variable interest entities effective January 1, 2010.

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

Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the sale of a 19.75% equity interest in Oncor to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor’s board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or other obligations of any member of the Texas Holdings Group. Moreover, Oncor’s operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.

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 15 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 2009 Form 10-K with the exception of the prospective adoption of amended guidance regarding consolidation accounting standards related to variable interest entities that resulted in the deconsolidation of Oncor Holdings as discussed in Note 3 and amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 5. Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Notes 2 and 3). 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 2009 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.

Use of Estimates

Preparation of 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 June 2009, the FASB issued new guidance that requires reconsideration of consolidation conclusions for all variable interest entities and other entities with which we are involved. We adopted this new guidance as of January 1, 2010. See Note 3 for discussion of our evaluation of variable interest entities and the resulting deconsolidation of Oncor Holdings and its subsidiaries that resulted in our investment in Oncor Holdings and its subsidiaries being prospectively reported as an equity method investment. There were no other material effects on our financial statements as a result of the adoption of this new guidance. New disclosures are provided in Note 3.

In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets that eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. We adopted this new guidance as of January 1, 2010. Accordingly, the trade accounts receivable amounts under the accounts receivable securitization program discussed in Note 5 are prospectively reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable. This new guidance did not impact the covenant-related ratio calculations in our debt agreements.

2.	EQUITY METHOD INVESTMENTS

Investments in unconsolidated subsidiaries consisted of the following:


	March 31, 2010		December 31, 2009
Investment in Oncor Holdings (100% owned) (a)	$	5,438	$	—
Investment in natural gas gathering pipeline business (25% owned) (b)		51		44

Total investments in unconsolidated subsidiaries	$	5,489	$	44

(a)	Oncor Holdings was deconsolidated effective January 1, 2010 (see Notes 1 and 3).

(b)	A controlling interest in this previously consolidated subsidiary was sold in 2009.

Oncor Holdings

Effective January 1, 2010, we account for our investment in Oncor Holdings under the equity method (see Note 3). Prior to this date, Oncor Holdings was a consolidated subsidiary. Oncor Holdings owns approximately 80% of Oncor (an SEC filer), which is engaged in regulated electricity transmission and distribution operations in Texas. Condensed statements of consolidated income for the three months ended March 31, 2010 and 2009 of Oncor Holdings are presented below:


	Three Months Ended March 31,
	2010			2009
Operating revenues	$	703		$	614
Operation and maintenance expenses		(249	)		(224	)
Depreciation and amortization		(166	)		(126	)
Taxes other than income taxes		(94	)		(97	)
Other income		11			10
Other deductions		(2	)		(5	)
Interest income		10			9
Interest expense and related charges		(86	)		(86	)

Income before income taxes		127			95
Income tax expense		(48	)		(36	)


Net income		79			59
Net income attributable to noncontrolling interests		(16	)		(12	)

Net income attributable to Oncor Holdings	$	63		$	47

Assets and liabilities of Oncor Holdings at March 31, 2010 and December 31, 2009 are presented below:


	March 31, 2010		December 31, 2009
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	23	$	29
Restricted cash		55		47
Trade accounts receivable — net		254		243
Trade accounts and other receivables from affiliates		183		188
Inventories		92		92
Accumulated deferred income taxes		8		10
Other current assets		81		84

Total current assets		696		693
Restricted cash		14		14
Other investments		75		72
Property, plant and equipment — net		9,312		9,174
Goodwill		4,064		4,064
Note receivable due from TCEH		208		217
Regulatory assets — net		1,977		1,959
Other noncurrent assets		49		51

Total assets	$	16,395	$	16,244

LIABILITIES
Current liabilities:
Short-term borrowings	$	756	$	616
Long-term debt due currently		109		108
Trade accounts payable – nonaffiliates		145		129
Income taxes payable to EFH Corp.		48		5
Accrued interest		72		104
Other current liabilities		147		243

Total current liabilities		1,277		1,205
Accumulated deferred income taxes		1,392		1,369
Investment tax credits		36		37
Long-term debt, less amounts due currently		4,972		4,996
Other noncurrent liabilities and deferred credits		1,866		1,879

Total liabilities	$	9,543	$	9,486

3.	CONSOLIDATION OF VARIABLE INTEREST ENTITIES

We adopted amended accounting standards on January 1, 2010 that require consolidation of a variable interest entity (VIE) if we have the power to direct the significant activities of the VIE and the right or obligation to absorb profit and loss from the VIE. A VIE is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. As discussed below, our balance sheet includes assets and liabilities of VIEs that meet the consolidation standards and also reflects the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor.

Our variable interests consist of equity investments. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.

Consolidated VIEs

See discussion in Note 5 regarding the VIE related to our accounts receivable securitization program that continues to be consolidated under the amended accounting standards.

We also continue to consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at Comanche Peak using MHI’s US-Advanced Pressurized Water Reactor technology and to obtain a combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries of TCEH and MHI that hold 88% and 12% of the equity interests, respectively (see Note 8).

The carrying amounts and classifications of the assets and liabilities related to our consolidated VIEs as of March 31, 2010 are as follows:


March 31, 2010
Assets:			Liabilities:
Cash and cash equivalents	$	12	Short-term borrowings (a)	$	393
Accounts receivable (a)		784	Trade accounts payable		3

Property, plant and equipment		87
Other assets, including $1 of current assets		6

Total assets	$	889	Total liabilities	$	396

(a)	As a result of the January 1, 2010 adoption of new accounting guidance related to transfers of financial assets, the balance sheet at March 31, 2010 reflects $784 million of pledged accounts receivable and $393 million of short-term borrowings (see Note 5).

The amended accounting standards require identification in the balance sheet of assets of consolidated VIEs that can only be used to settle the obligations of the VIE, as well as liabilities of consolidated VIEs for which the creditors of the VIE do not have recourse to our general credit, both of which apply to all of our consolidated VIEs.

Non-Consolidated VIEs

The adoption of the amended accounting standards resulted in the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor, and the reporting of our investment in Oncor Holdings under the equity method on a prospective basis.

In reaching the conclusion to deconsolidate, we conducted an extensive analysis of Oncor Holdings’ underlying governing documents and management structure. Oncor Holdings’ unique governance structure was adopted in conjunction with the Merger, when the Sponsor Group, EFH Corp. and Oncor agreed to implement structural and operational measures to “ring-fence” (the Ring-Fencing Measures) Oncor Holdings and Oncor as discussed in Note 1. The Ring-Fencing Measures were designed to prevent, among other things, (i) increased borrowing costs at Oncor due to the attribution to Oncor of debt from our highly-leveraged unregulated operations, (ii) the activities of our unregulated operations following the Merger resulting in the deterioration of Oncor’s business, financial condition and/or investment in infrastructure, and (iii) Oncor becoming substantively consolidated into a bankruptcy proceeding involving any member of the Texas Holdings Group. The Ring-Fencing Measures effectively separated the daily operational and management control of Oncor Holdings and Oncor from EFH Corp. and its other subsidiaries. By implementing the Ring-Fencing Measures, Oncor maintained its investment grade credit rating following the Merger and reaffirmed Oncor’s independence from our unregulated businesses to the PUCT.

We determined the most significant activities affecting the economic performance of Oncor Holdings (and Oncor) are the operation, maintenance and growth of Oncor’s electric transmission and distribution assets and the preservation of its investment grade credit profile. The boards of directors of Oncor Holdings and Oncor have ultimate responsibility for the management of the day-to-day operations of their respective businesses, including the approval of Oncor’s capital expenditure and operating budgets and the timing and prosecution of Oncor’s rate cases. While the boards include members appointed by EFH Corp., a majority of the board members are independent in accordance with rules established by the New York Stock Exchange, and therefore, we concluded for purposes of applying the amended accounting standards that EFH Corp. does not have power to control the activities deemed most significant to Oncor Holdings’ (and Oncor’s) economic performance.

In assessing EFH Corp.’s ability to exercise control over Oncor Holdings and Oncor, we considered whether it could take actions to circumvent the purpose and intent of the Ring-Fencing Measures (including changing the composition of Oncor Holdings’ or Oncor’s board) in order to gain control over the day-to-day operations of either Oncor Holdings or Oncor. We also considered whether (i) EFH Corp. has the unilateral power to dissolve, liquidate or force into bankruptcy either Oncor Holdings or Oncor, (ii) EFH Corp. could unilaterally amend the ring-fencing protections contained in underlying governing documents of Oncor Holdings or Oncor, and (iii) EFH Corp. could control Oncor’s ability to pay distributions and thereby enhance its own cash flow. We concluded that, in each case, no such opportunity exists.

We account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, because we have the ability to exercise significant influence (as defined in accounting standards) over its activities.

The carrying value of our variable interest in VIEs that we do not consolidate totaled $5.489 billion at March 31, 2010, substantially all of which represents our investment in Oncor Holdings, and is reported as investments in unconsolidated subsidiaries in the balance sheet. Our maximum exposure to loss from these interests does not exceed our carrying value. See Note 2 for additional information about equity method investments including condensed income statement and balance sheet data for Oncor Holdings.

4.	GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Reported goodwill as of March 31, 2010 and December 31, 2009 totaled $10.2 billion and $14.3 billion, respectively, with $10.2 billion assigned to the Competitive Electric segment. The $4.1 billion assigned to the Regulated Delivery segment as of December 31, 2009 was prospectively deconsolidated with Oncor Holdings as of January 1, 2010 as a result of the adoption of new accounting guidance for consolidation as discussed in Note 1. None of this goodwill balance is being deducted for tax purposes.

Identifiable Intangible Assets

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


	As of March 31, 2010 (a)						As of December 31, 2009
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	235	$	228	$	463	$	215	$	248
Favorable purchase and sales contracts		700		388		312		700		374		326
Capitalized in-service software		256		71		185		490		167		323
Environmental allowances and credits		993		234		759		992		212		780
Land easements		—		—		—		188		72		116
Mining development costs		39		8		31		32		5		27

Total intangible assets subject to amortization	$	2,451	$	936		1,515	$	2,865	$	1,045		1,820

Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization)						98						101

Total intangible assets					$	2,568					$	2,876

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010.

Amortization expense related to intangible assets (including income statement line item) consisted of:


			Three Months Ended March 31,
Intangible Asset	Income Statement Line	Segment	2010		2009
Retail customer relationship	Depreciation and amortization	Competitive Electric	$	20	$	21
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	Competitive Electric		14		42
Capitalized in-service software	Depreciation and amortization	All (a)		8		11
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	Competitive Electric		22		21
Land easements	Depreciation and amortization	Regulated Delivery (a)		—		1
Mining development costs	Depreciation and amortization	Competitive Electric		2		—

Total amortization expense			$	66	$	96

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010.

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


Year	Amount
2010	$	248
2011		189
2012		147
2013		127
2014		113

5.	TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is an entity created for the special purpose of purchasing receivables from the originator 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 entities established for this purpose by the funding entities. In accordance with the amended transfers and servicing accounting standard as discussed in Note 1, the trade accounts receivable amounts under the program are reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable.

The maximum funding amount currently available under the accounts receivable securitization program is $700 million. Program funding totaled $393 million at March 31, 2010. Under the terms of the program, available funding was reduced by the total of $76 million of customer deposits held by the originator at March 31, 2010 because TCEH’s credit ratings were lower than
Ba3/BB-.

All new trade receivables under the program generated by the originator 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 a subordinated note payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The subordinated note issued by TXU Receivables Company is subordinated to the undivided interests of the funding entities in the purchased receivables. The balance of the subordinated note payable, which is eliminated in consolidation, totaled $391 million and $463 million at March 31, 2010 and December 31, 2009, respectively.

The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees consist primarily of interest costs on the underlying financing. Consistent with the change in balance sheet presentation of the funding discussed above, the program fees are currently reported as interest expense and related charges but were previously reported as losses on sale of receivables reported in SG&A expense. The discount also funds a servicing fee, which is reported as SG&A expense, paid by TXU Receivables Company to EFH Corporate Services Company (Service Co.), a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.

Program fee amounts were as follows:


	Three Months Ended March 31,
	2010			2009
Program fees	$	2		$	4
Program fees as a percentage of average funding (annualized)		2.2	%		3.7	%

Funding under the program increased $10 million and decreased $34 million for the three month periods ending March 31, 2010 and 2009, respectively.

Activities of TXU Receivables Company were as follows:


	Three Months Ended March 31,
	2010			2009
Cash collections on accounts receivable	$	1,541		$	1,440
Face amount of new receivables purchased		(1,479	)		(1,408	)
Discount from face amount of purchased receivables		3			5
Program fees paid to funding entities		(2	)		(4	)
Servicing fees paid to Service Co. for recordkeeping and collection services		(1	)		(1	)
Increase (decrease) in subordinated notes payable		(72	)		2

Financing/operating cash flows used by (provided to) originator under the program	$	(10	)	$	34

Changes in funding under the program have previously been reported as operating cash flows, and the amended accounting rule requires that the amount of funding under the program upon the January 1, 2010 adoption ($383 million) be reported as a use of operating cash flows and a source of financing cash flows. All changes in funding subsequent to adoption of the amended standard are reported as financing activities.

The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or Service Co. 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 Service Co., any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of March 31, 2010, there were no such events of termination.

Upon termination of the program, liquidity would be reduced 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.

Trade Accounts Receivable


	March 31, 2010 (a)			December 31, 2009
Wholesale and retail trade accounts receivable, including $784 in pledged retail receivables at March 31, 2010	$	1,232		$	1,726
Undivided interests in retail accounts receivable sold by TXU Receivables Company		—			(383	)
Allowance for uncollectible accounts		(74	)		(83	)

Trade accounts receivable — reported in balance sheet	$	1,158		$	1,260

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010.

Gross trade accounts receivable at March 31, 2010 and December 31, 2009 included unbilled revenues of $346 million and $546 million, respectively.

Allowance for Uncollectible Accounts Receivable


	Three Months Ended March 31,
	2010			2009
Allowance for uncollectible accounts receivable as of beginning of period	$	81		$	70
Increase for bad debt expense		36			20
Decrease for account write-offs		(43	)		(29	)
Other		—			1

Allowance for uncollectible accounts receivable as of end of period	$	74		$	62

6.	SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At March 31, 2010, outstanding short-term borrowings totaled $646 million, which included $253 million under TCEH credit facilities at a weighted average interest rate of 3.74%, excluding certain customary fees, and $393 million under the sale of receivables program discussed in Note 5.

At December 31, 2009, we had outstanding short-term borrowings of $1.569 billion at a weighted average interest rate of 2.50%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $953 million for TCEH and $616 million for Oncor.

Credit Facilities

Credit facilities with cash borrowing and/or letter of credit availability at March 31, 2010 are presented below. The facilities are all senior secured facilities of TCEH.


		At March 31, 2010
Authorized Borrowers and Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)	October 2013	$	2,700	$	—	$	253	$	2,421
TCEH Letter of Credit Facility (b)	October 2014		1,250		—		1,250		—

Subtotal TCEH		$	3,950	$	—	$	1,503	$	2,421

TCEH Commodity Collateral Posting Facility (c)	December 2012		Unlimited	$	—	$	—		Unlimited

(a)

Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $141 million of commitments from Lehman that are only available from the fronting banks and the swingline lender and excludes $26 million of requested cash draws that have not been funded by Lehman. All outstanding borrowings under this facility at March 31, 2010 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.

(b)

Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $701 million issued as of March 31, 2010 are supported by the restricted cash, and the remaining letter of credit availability totals $434 million.

(c)

Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 540 million MMBtu as of March 31, 2010. As of March 31, 2010, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.

Long-Term Debt

At March 31, 2010 and December 31, 2009, long-term debt consisted of the following:


	March 31, 2010			December 31, 2009
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
0.267% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.248% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.267% 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)		(143	)		(147	)
Senior Secured Facilities:
3.729% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)		16,038			16,079
3.729% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		4,065			4,075
3.748% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
0.231% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (g)		—			—
Other:
10.25% Fixed Senior Notes due November 1, 2015 (h)		2,944			2,944
10.25% Fixed Senior Notes due November 1, 2015, Series B (h)		1,913			1,913
10.50 / 11.25% Senior Toggle Notes due November 1, 2016 (i)		1,925			1,952
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		42			55
Capital lease obligations		86			153
Unamortized fair value discount (d)		(4	)		(4	)

Total TCEH	$	29,656		$	29,810


	March 31, 2010			December 31, 2009
EFC Holdings
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	51		$	51
8.254% Fixed Notes due in quarterly installments through December 31, 2021		49			50
1.049% 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)		(11	)		(11	)

Total EFC Holdings		98			99

EFH Corp. (parent entity)
10.875% Fixed Senior Notes due November 1, 2017		1,831			1,831
11.25 / 12.00% Senior Toggle Notes due November 1, 2017		2,777			2,797
9.75% Fixed Senior Secured Notes due October 15, 2019		115			115
10.000% Fixed Senior Secured Notes due January 15, 2020		534			—
5.550% Fixed Senior Notes Series P due November 15, 2014 (j)		983			983
6.500% Fixed Senior Notes Series Q due November 15, 2024 (j)		740			740
6.550% Fixed Senior Notes Series R due November 15, 2034 (j)		744			744
8.820% Building Financing due semiannually through February 11, 2022 (k)		71			75
Unamortized fair value premium related to Building Financing (d)		16			17
Capital lease obligations		6			—
Unamortized fair value discount (d)		(583	)		(599	)

Total EFH Corp.		7,234			6,703

Intermediate Holding
9.75% Fixed Senior Secured Notes due October 15, 2019		141			141
Oncor (l) (m)
6.375% Fixed Senior Notes due May 1, 2012		—			700
5.950% Fixed Senior Notes due September 1, 2013		—			650
6.375% Fixed Senior Notes due January 15, 2015		—			500
6.800% Fixed Senior Notes due September 1, 2018		—			550
7.000% Fixed Debentures due September 1, 2022		—			800
7.000% Fixed Senior Notes due May 1, 2032		—			500
7.250% Fixed Senior Notes due January 15, 2033		—			350
7.500% Fixed Senior Notes due September 1, 2038		—			300
Unamortized discount		—			(15	)

Total Oncor		—			4,335

Oncor Electric Delivery Transition Bond Company LLC (m) (n)
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		—			13
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		—			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		—			145
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		—			197
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		—			290

Total Oncor Electric Delivery Transition Bond Company LLC		—			775
Unamortized fair value discount related to transition bonds (d)		—			(6	)

Total Oncor consolidated		—			5,104


Total EFH Corp. consolidated		37,129			41,857
Less amount due currently		(250	)		(417	)

Total long-term debt	$	36,879		$	41,440

(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, 2010. 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, 2010. 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 $16.30 billion principal amount.

(f)	Interest rates in effect at March 31, 2010.

(g)	Interest rate in effect at March 31, 2010, excluding a quarterly maintenance fee of approximately $11 million. See “Credit Facilities” above for more information.

(h)	Amounts exclude $56 million and $87 million of the original and Series B notes, respectively, that are held by EFH Corp. and Intermediate Holding and eliminated in consolidation.

(i)	Amount excludes $27 million that is held by EFH Corp. and eliminated in consolidation.

(j)	Amounts exclude $9 million, $6 million and $3 million of the Series P, Series Q and Series R notes, respectively, that are held by Intermediate Holding and eliminated in consolidation.

(k)

This financing is secured and will be serviced with $115 million in restricted cash drawn in June 2009 by the beneficiary of a letter of credit. The issuer elected not to extend the expiration date of the letter of credit, and TCEH elected to allow the drawing in lieu of reissuing the letter of credit under the TCEH Revolving Credit Facility. The remaining $104 million of the prepayment (net of $11 million of debt service payments) is included in other current assets and other noncurrent assets on the balance sheet.

(l)	Secured with first priority lien.

(m)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

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

Debt-Related Activity in 2010 — Repayments of long-term debt in 2010 totaling $132 million represented principal payments at scheduled maturity dates as well as other repayments totaling $81 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $41 million repaid under the TCEH Initial Term Loan Facility and $10 million repaid under the TCEH Delayed Draw Term Loan Facility. See “2010 Debt Exchanges and Repurchases” below for $47 million principal amount of debt acquired in a debt exchange completed in March 2010.

EFH Corp. 10% Senior Secured Notes — In January 2010, EFH Corp. issued $500 million aggregate principal amount of 10.000% Senior Secured Notes due 2020 (the EFH Corp. 10% Notes). The notes will mature on January 15, 2020, and interest is payable in cash in arrears on January 15 and July 15 of each year at a fixed rate of 10.00% per annum with the first interest payment due on July 15, 2010.

The EFH Corp. 10% Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding. The guarantee from Intermediate Holding is secured by the pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries (the Collateral). The guarantee from EFC Holdings is not secured. The EFH Corp. 10% Notes are secured by the Collateral on a parity lien basis with the EFH Corp. 9.75% Senior Secured Notes and EFIH Notes.

The EFH Corp. 10% Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of EFH Corp. and are senior in right of payment to any future subordinated indebtedness of EFH Corp. These notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries.

The guarantees of the EFH Corp. 10% Notes are the general senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantee from Intermediate Holding is effectively senior to all unsecured indebtedness of Intermediate Holding to the extent of the value of the Collateral. The guarantee will be effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the Collateral to the extent of the value of the assets securing such indebtedness and will be structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.’s subsidiaries that are not guarantors.

The EFH Corp. 10% Notes and indenture governing such notes restrict EFH Corp. and its restricted subsidiaries’ ability to, among other things, make restricted payments, incur debt and issue preferred stock, incur liens, pay dividends, merge, consolidate or sell assets and engage in certain transactions with affiliates. These covenants are subject to a number of limitations and exceptions. These notes and indenture also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under these notes and the related indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payable immediately.

Before January 15, 2013, 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. 10% Notes from time to time at a redemption price of 110.000% of the aggregate principal amount of the notes, plus accrued and unpaid interest, if any. EFH Corp. may redeem the notes at any time prior to January 15, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after January 15, 2015, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control (as described in the indenture), EFH Corp. may be required to offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

The EFH Corp. 10% Notes were issued in a private placement and have not been registered under the Securities Act. EFH Corp. has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFH Corp. 10% Notes (except for provisions relating to the transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the EFH Corp. 10% Notes. EFH Corp. has agreed to use commercially reasonable efforts to cause the exchange offer to be completed or, if required under special circumstances, to have one or more shelf registration statements declared effective, within 360 days after the January 2010 issue date of the notes. If this obligation is not satisfied (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.

2010 Debt Exchanges and Repurchases — In a private exchange completed in March 2010, EFH Corp. issued an additional $34 million principal amount of EFH Corp. 10% Notes in exchange for $20 million principal amount of EFH Corp. Toggle Notes and $27 million principal amount of TCEH Toggle Notes resulting in a debt extinguishment gain of $14 million reported as other income. In private transactions completed in April 2010, EFH Corp. repurchased $5 million principal amount of EFH Corp. 10.875% Notes for cash of $3.64 million plus accrued interest, and also issued an additional $66 million principal amount of EFH Corp. 10% Notes in exchange for $75 million principal amount of EFH Corp. Toggle Notes and $17 million principal amount of TCEH Toggle Notes, resulting in debt extinguishment gains totaling $31 million.

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, 2010 is provided in the long-term debt table and in the discussion of short-term borrowings above and reflects LIBOR-based borrowings.

Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the TCEH Senior Secured Facilities.

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 future 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 Swap Transactions” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility (approximately $41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of December 2009, 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 — The indebtedness under TCEH’s and TCEH Finance’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 Series B (collectively, TCEH 10.25% Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum payable in cash. The indebtedness under the TCEH Toggle Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK Interest. For any interest period until November 2012, the 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 (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. TCEH elected to pay the PIK Interest for both interest payments in 2009, increasing the principal amount of the TCEH Toggle Notes. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.

The TCEH 10.25% and Toggle Notes (collectively, the TCEH Senior Notes) are fully and unconditionally guaranteed on a joint and several unsecured 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.

Before November 1, 2010, the issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of the TCEH 10.25% and 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 issuers may also redeem the TCEH Senior Notes at any time prior to November 1, 2011 and 2012, respectively, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. The issuers may redeem the TCEH Senior Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFC Holdings or TCEH, the issuers may be required to offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

EFH Corp. Senior Notes — The indebtedness under EFH Corp.’s 10.875% Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum payable in cash. The indebtedness under EFH Corp.’s Toggle Notes due November 1, 2017 bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. EFH Corp. elected to pay PIK Interest for both interest payments in 2009, increasing the principal amount of the EFH Corp. Toggle Notes. Once EFH Corp. makes a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. revokes the election.

The EFH Corp. 10.875% and Toggle Notes (collectively, the EFH Corp. Senior Notes) are fully and unconditionally guaranteed on a joint and several unsecured basis by EFC Holdings and Intermediate Holding.

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 its 10.875% and Toggle Notes from time to time at a redemption price of 110.875% and 111.250%, respectively, of their respective aggregate principal amounts, plus accrued and unpaid interest, if any. EFH Corp. may also redeem these 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 the applicable premium as defined in the indenture. EFH Corp. may also redeem these 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. Upon the occurrence of a change of 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.

EFH Corp. and Intermediate Holding Senior Secured Notes — The indebtedness under EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019 (the EFH Corp. 9.75% Notes) and Intermediate Holding’s and EFIH Finance’s 9.75% Senior Secured Notes due October 15, 2019 (the EFIH Notes) bear interest semiannually in arrears on April 15 and October 15 of each year at a fixed rate of 9.75% per annum payable in cash. The EFH Corp. 9.75% Notes and the EFH Corp. 10% Notes discussed above are collectively referred to as the EFH Corp. Senior Secured Notes.

The EFH Corp. Senior Secured Notes and EFIH Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding. The guarantee from Intermediate Holding is secured by the pledge of the Collateral. The guarantee from EFC Holdings is not secured. The EFIH Notes are secured by the Collateral on a parity lien basis with the EFH Corp. Senior Secured Notes.

Before October 15, 2012, the respective issuers may redeem the EFH Corp. 9.75% Notes and EFIH Notes, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of each series of the notes from time to time at a redemption price of 109.750% of the aggregate principal amount of such series of notes, plus accrued and unpaid interest, if any. The applicable issuer may also redeem each series of the notes at any time prior to October 15, 2014 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. The applicable issuer may redeem the EFH Corp. 9.75% Notes and EFIH Notes, in whole or in part, at any time on or after October 15, 2014, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control (as described in the indenture), the applicable issuer may be required to offer to repurchase each series of the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

TCEH Interest Rate Swap Transactions — As of March 31, 2010, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $16.30 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 2010 to 2014. No interest rate swap transactions were entered into in 2010.

As of March 31, 2010, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $13.75 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.2055%. Swaps related to an aggregate $2.5 billion principal amount of senior secured term loans of TCEH expired in the three months ended March 31, 2010. No interest rate basis swap transactions were entered into in 2010.

The interest rate swap counterparties are proportionately secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. 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 value changes totaled $107 million in net losses in the three months ended March 31, 2010 and $205 million in net gains in the three months ended March 31, 2009. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.320 billion at March 31, 2010, of which $165 million (pre-tax) was reported in accumulated other comprehensive income.

See Note 11 for discussion of collateral investments related to certain of these interest rate swaps.

7.	COMMITMENTS AND CONTINGENCIES

Guarantees

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

Disposed TXU Gas operations — In connection with the sale of TXU Gas 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 under these indemnities 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, 2010, the aggregate maximum amount of residual values guaranteed was approximately $13 million with an estimated residual recovery of approximately $13 million. These leased assets consist primarily of rail cars. The average life of the residual value guarantees under the lease portfolio is approximately six years.

See Note 6 above and Note 12 to Financial Statements in the 2009 Form 10-K for discussion of guarantees and security for certain of our indebtedness.

Letters of Credit

At March 31, 2010, TCEH had outstanding letters of credit under its credit facilities totaling $701 million as follows:

•

$304 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);

•

$84 million to support TCEH’s REP’s financial requirements with the PUCT, and

•

$105 million for miscellaneous credit support requirements.

Litigation Related to Generation Facilities

In September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. In December 2009, the Attorney General and Oak Grove Management Company LLC filed pleadings asking the court to dismiss the administrative appeal challenging the permit for want of prosecution by the plaintiffs. In January 2010, the court denied that request and set the case for a hearing on the merits in June 2010. In March 2010, the remaining two non-parties to the administrative hearing before the TCEQ and SOAH filed a notice of non-suit, thus ending their legal challenge. Therefore, only one plaintiff remains in the case. 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, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Energy Future Capital Holdings LLC as parties to the suit. The lawsuit makes various claims concerning the operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requests money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. 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 plaintiff’s claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation.

In February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. This notice is similar to the notice that Luminant received in July 2008 with respect to its Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

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. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.

Other Proceedings

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

8.	EQUITY

Dividend Restrictions

The indentures governing the EFH Corp. Senior Notes and Senior Secured Notes include 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 these indentures and/or after such distributions, on a pro forma basis, after giving effect to such payment, EFH Corp.’s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. In addition, the indenture governing the EFIH Notes generally restricts Intermediate Holding from making any cash distribution to EFH Corp. for the ultimate purpose of making a cash distribution to Texas Holdings unless at the time, and after giving effect to such distribution, Intermediate Holding’s consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indenture governing the EFIH Notes, the term “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA on a consolidated basis.

The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash 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, the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFC Holdings and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies for corporate overhead costs, SG&A expenses, taxes and principal and interest payments. In addition, those agreements contain certain investment and dividend baskets that would allow TCEH to make additional distributions and/or loans to its parent companies up to the amount of such baskets. At March 31, 2010, EFH Corp. notes payable to TCEH totaled $1.405 billion.

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

EFH Corp. did not declare or pay any cash dividends in 2010 or 2009.

Distributions from Oncor — Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

Noncontrolling Interests

Of the noncontrolling interests balance at December 31, 2009 in the table below, $1.363 billion related to Oncor. See Note 1 for discussion of the deconsolidation of Oncor in 2010. As of December 31, 2009 (and March 31, 2010), Oncor’s ownership was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.

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, CPNPC, to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary (see Note 3).

Equity

The following table presents the changes to equity during the three months ended March 31, 2010.


	EFH Corp. Shareholders’ Equity
	Common Stock (a)		Additional Paid-in Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total Equity
Balance at December 31, 2009	$	2	$	7,914	$	(10,854	)	$	(309	)	$	1,411		$	(1,836	)
Net income		—		—		355			—			—			355
Effects of EFH Corp. stock-based incentive compensation plans		—		10		—			—			—			10
Change in unrecognized gains related to pension and OPEB costs		—		—		—			4			—			4
Net effects of cash flow hedges		—		—		—			19			—			19
Effects of deconsolidation of Oncor Holdings		—		—		—			—			(1,363	)		(1,363	)
Investment by noncontrolling interests		—		—		—			—			6			6

Balance at March 31, 2010	$	2	$	7,924	$	(10,499	)	$	(286	)	$	54		$	(2,805	)

(a)	Authorized shares totaled 2,000,000,000 as of March 31, 2010. Outstanding shares totaled 1,668,630,992 and 1,668,065,133 as of March 31, 2010 and December 31, 2009, respectively.

9.	FAIR VALUE MEASUREMENTS

Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

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

•

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

•

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

•

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

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

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

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

With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required 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, 2010, 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 contracts	$	1,461	$	4,067	$	424	$	17	$	5,969
Interest rate swaps		—		74		—		—		74
Nuclear decommissioning trust – equity securities (c)		166		111		—		—		277
Nuclear decommissioning trust – debt securities (c)		—		218		—		—		218

Total assets	$	1,627	$	4,470	$	424	$	17	$	6,538


Liabilities:
Commodity contracts	$	1,668	$	1,287	$	268	$	17	$	3,240
Interest rate swaps		—		1,422		—		—		1,422

Total liabilities	$	1,668	$	2,709	$	268	$	17	$	4,662

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

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

(c)	The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 16.

At December 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 contracts	$	918	$	2,588	$	350	$	4	$	3,860
Interest rate swaps		—		64		—		—		64
Nuclear decommissioning trust – equity securities (c)		154		105		—		—		259
Nuclear decommissioning trust – debt securities (c)		—		216		—		—		216

Total assets	$	1,072	$	2,973	$	350	$	4	$	4,399


Liabilities:
Commodity contracts	$	1,077	$	796	$	269	$	4	$	2,146
Interest rate swaps		—		1,306		—		—		1,306

Total liabilities	$	1,077	$	2,102	$	269	$	4	$	3,452

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

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

(c)	The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 16.

Commodity contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales. See Note 11 for further discussion regarding the company’s use of derivative instruments.

Interest rate swaps include 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 effectively reduce the hedged borrowing costs. See Note 6 for discussion of interest rate swaps.

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

There were no significant transfers between the levels of the fair value hierarchy for the three months ended March 31, 2010.

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, 2010 and 2009:


	Three Months Ended March 31,
	2010		2009
Balance at beginning of period	$	81	$	(72	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		51		16
Included in other comprehensive income (loss)		—		(26	)
Purchases, sales, issuances and settlements (net) (b)		18		(16	)
Transfers into Level 3 (c)		—		—
Transfers out of Level 3 (c)		6		20

Balance at end of period	$	156	$	(78	)

Net change in unrealized gains (losses) included in net income relating to instruments held at end of period (d)	$	54	$	7

(a)	Substantially all changes in values of commodity contracts are reported in the income statement in net gain 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. For 2010, in accordance with new accounting guidance issued by the FASB in January 2010, transfers in and out occur at the end of each quarter, which is when the assessments are performed. Prior period transfers in were assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter.

(d)	Includes unrealized gains and losses of instruments held at the end of the period.

10.

FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments at March 31, 2010 and December 31, 2009 were as follows:


	March 31, 2010						December 31, 2009
	Carrying Amount			Fair Value (a)			Carrying Amount			Fair Value (a)
On balance sheet assets (liabilities):
Long-term debt (including current maturities) (b):
TCEH, EFH Corp., and other	$	(37,037	)	$	(29,138	)	$	(36,600	)	$	(29,115	)
Oncor (c)	$	—		$	—		$	(5,104	)	$	(5,644	)

Total	$	(37,037	)	$	(29,138	)	$	(41,704	)	$	(34,759	)

Off balance sheet assets (liabilities):
Financial guarantees	$	—		$	(6	)	$	—		$	(6	)

(a)	Fair value determined in accordance with accounting standards related to the determination of fair value.

(b)	Excludes capital leases.

(c)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

See Notes 9 and 11 for discussion of accounting for financial instruments that are derivatives.

11.

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 9 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 highly correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2014. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 6 for additional information about these and other interest rate swap agreements.

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

The following tables provide detail of commodity and other derivative contractual assets and liabilities, substantially all arising from mark-to-market accounting, as reported in the balance sheets at March 31, 2010 and December 31, 2009:


	Derivatives not under hedge accounting – March 31, 2010
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	3,668		$	72	$	12		$	—		$	3,752
Noncurrent assets		2,289			2		—			—			2,291
Current liabilities		(5	)		—		(2,803	)		(722	)		(3,530	)
Noncurrent liabilities		—			—		(432	)		(700	)		(1,132	)

Net assets (liabilities)	$	5,952		$	74	$	(3,223	)	$	(1,422	)	$	1,381


	Derivatives not under hedge accounting – December 31, 2009
	Derivative assets				Derivative liabilities
	Commodity contracts		Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	2,327	$	60	$	4		$	—		$	2,391
Noncurrent assets		1,529		4		—			—			1,533
Current liabilities		—		—		(1,705	)		(687	)		(2,392	)
Noncurrent liabilities		—		—		(441	)		(619	)		(1,060	)

Net assets (liabilities)	$	3,856	$	64	$	(2,142	)	$	(1,306	)	$	472

As of March 31, 2010 and December 31, 2009, there were no derivative positions accounted for as cash flow or fair value hedges.

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $380 million and $358 million in net liabilities at March 31, 2010 and December 31, 2009, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Reported amounts as 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.

In 2009, we 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, as of December 31, 2009, EFH Corp. (parent) had posted $400 million in cash and TCEH had posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. In accordance with the agreements, the counterparties returned the collateral, along with accrued interest, on March 31, 2010. As of December 31, 2009, the cash collateral was recorded as an investment and was presented in the balance sheet (including accrued interest) as a separate line item under current assets.

The following table presents the pre-tax effect of derivatives not under hedge accounting on net income, including realized and unrealized effects:


	Three Months Ended March 31,
Derivative (Income statement presentation)	2010			2009

Commodity contracts (Net gain from commodity hedging and trading activities)	$	1,203		$	1,155

Interest rate swaps (Interest expense and related charges)		(276	)		45

Net gain	$	927		$	1,200

The following tables present the pre-tax effect of derivative instruments previously accounted for as cash flow hedges on net income and other comprehensive income (OCI) for the three months ended March 31, 2010 and 2009:


Three Months Ended March 31, 2010
Derivative	Amount of gain (loss) recognized in OCI (effective portion)			Income statement presentation of loss reclassified from accumulated OCI into income (effective portion)	Amount

Interest rate swaps	$	—		Interest expense and related charges	$	(29	)

Commodity contracts		—		Fuel, purchased power costs and delivery fees		—

				Operating revenues		—

Total	$	—			$	(29	)


Three Months Ended March 31, 2009
Derivative	Amount of (loss) recognized in OCI (effective portion)			Income statement presentation of 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	)

There were no transactions designated as cash flow hedges during the three months ended March 31, 2010. There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the three months ended March 31, 2009.

Accumulated other comprehensive income related to cash flow hedges at March 31, 2010 and December 31, 2009 totaled $109 million and $128 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $46 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of March 31, 2010 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

Derivative Volumes — The following table presents the gross notional amounts of derivative volumes at March 31, 2010 and December 31, 2009:


	March 31, 2010		December 31, 2009		Unit of Measure
Derivative type	Notional Volume				Unit of Measure

Interest rate swaps:
Floating/fixed	$	18,000	$	18,000	Million US dollars
Basis	$	13,750	$	16,250	Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		3,182		3,402	Million MMBtu
Locational basis swaps		998		1,010	Million MMBtu
All other		1,582		1,433	Million MMBtu
Electricity		187,168		198,230	GWh
Coal		5		6	Million tons
Fuel oil		149		161	Million gallons

(a)

Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, is 1.5 billion MMBtu and 1.6 billion MMBtu as of March 31, 2010 and December 31, 2009, respectively.

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 credit ratings, substantially all of such collateral posting requirements are already effective.

As of March 31, 2010 and December 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 $914 million and $687 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $121 million and $152 million as of March 31, 2010 and December 31, 2009, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of March 31, 2010 and December 31, 2009, the remaining related liquidity requirement would have totaled $28 million and $20 million, respectively, after reduction for net accounts receivable and derivative assets under netting arrangements.

In addition, certain derivative agreements that are collateralized primarily 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, 2010 and December 31, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.904 billion and $1.482 billion, respectively, (before consideration of the amount of assets under the liens). There were no cash collateral and letters of credit posted with these counterparties to reduce the liquidity exposure as of March 31, 2010. The liquidity exposure associated with these liabilities was reduced by cash collateral and letters of credit posted with counterparties totaling $489 million as of December 31, 2009. 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, 2010 and December 31, 2009, the remaining related liquidity requirement would have totaled $973 million and $480 million, respectively, after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 12 to Financial Statements in the 2009 Form 10-K for a description of other obligations that are supported by asset liens.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.818 billion and $2.169 billion at March 31, 2010 and December 31, 2009, respectively. 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.

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.

Concentrations of Credit Risk

TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of March 31, 2010, total credit risk exposure to all counterparties related to derivative contracts totaled $6.1 billion. The net exposure to those counterparties totaled $2.2 billion after taking into effect master netting arrangements, setoff provisions and collateral. As of March 31, 2010, the credit risk exposure to the banking and financial sector represented 92% of the total credit risk exposure, a significant amount of which is related to the long-term hedging program. As of March 31, 2010, the largest net exposure to a single counterparty totaled $909 million. Exposure to the banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially all of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on our financial condition and results of operations.

The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies 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. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. 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. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

12.

PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) COSTS

Net pension and OPEB costs for the three months ended March 31, 2010 and 2009 are comprised of the following:


	Three Months Ended March 31,
	2010			2009
Components of net pension costs:
Service cost	$	11		$	9
Interest cost		39			39
Expected return on assets		(40	)		(42	)
Amortization of prior service cost		—			—
Amortization of net loss		13			2

Net pension costs		23			8

Components of net OPEB costs:
Service cost		3			3
Interest cost		15			15
Expected return on assets		(3	)		(3	)
Amortization of prior service cost		—			—
Amortization of net loss		5			3

Net OPEB costs		20			18

Total net pension and OPEB costs		43			26
Less amounts expensed by Oncor		(9	)		—
Less amounts deferred principally as a regulatory asset or property by Oncor		(22	)		(16	)

Amount recognized as expense by EFH Corp. and consolidated subsidiaries	$	12		$	10

The discount rate reflected in net pension and OPEB costs in 2010 is 5.90%. The expected rates of return on pension and OPEB plan assets reflected in the 2010 cost amounts are 8.0% and 7.6%, respectively.

We made cash contributions related to our pension and OPEB plans totaling $1 million and $6 million, respectively, in the first quarter of 2010, including $4 million contributed by Oncor. We expect to make additional contributions of $44 million and $18 million, respectively, in the remainder of 2010, including $55 million expected to be contributed by Oncor.

13.

EFFECT OF HEALTH CARE LEGISLATION

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act enacted in March 2010 reduces, effective in 2013, the amount of OPEB costs deductible for federal income tax purposes by the amount of the Medicare Part D subsidy we receive. Under income tax accounting rules, deferred tax assets related to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in the three months ended March 31, 2010, EFH Corp.’s and Oncor’s deferred tax assets were reduced by $50 million. Of this amount, $8 million was recorded as a charge to income tax expense and $42 million was recorded as a regulatory asset by Oncor (before gross-up for liability in lieu of deferred income taxes) as the additional income taxes are expected to be recoverable in Oncor’s future rates.

14.

RELATED PARTY TRANSACTIONS

The following represent the significant related-party transactions of EFH Corp.:

•

We incur an annual management fee under the terms of a management agreement with the Sponsor Group for which we accrued $9 million for both the three months ended March 31, 2010 and 2009. The fee is reported as SG&A expense.

•

In 2007, TCEH entered into the TCEH Senior Secured Facilities 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.

•

Goldman, Sachs & Co. (Goldman) acted as an initial purchaser in the issuance of $500 million principal amount of EFH Corp. 10% Notes in January 2010 as discussed in Note 6. Goldman received fees totaling $3 million for this transaction.

•

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

•

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

•

TCEH incurs electricity delivery fees charged by Oncor. These fees totaled $264 million for the three months ended March 31, 2010. The balance sheet at March 31, 2010 reflects amounts due currently to Oncor of $146 million (included in net payables due to unconsolidated subsidiary), primarily related to these electricity delivery fees.

•

Oncor’s bankruptcy-remote financing subsidiary has issued securitization bonds to recover generation-related regulatory assets through a transition surcharge to its customers. Oncor’s incremental income taxes related to the transition surcharges it collects are being reimbursed by TCEH. Therefore, the balance sheet reflects a noninterest bearing note payable to Oncor of $245 million ($37 million current portion included in net payables due to unconsolidated subsidiary) at March 31, 2010.

•

TCEH reimburses Oncor for interest expense on Oncor’s bankruptcy-remote financing subsidiary’s securitization bonds. This interest expense totaled $10 million for the three months ended March 31, 2010.

•

A subsidiary of EFH Corp. charges Oncor for financial and other administrative services at cost, which totaled $7 million for the three months ended March 31, 2010.

•

Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in other investments on the balance sheet, is funded by a delivery fee surcharge billed to REPs by Oncor and remitted to TCEH, with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported in noncurrent liabilities on the balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by us are offset by a net change in the intercompany receivable/payable with Oncor, which in turn results in a change in Oncor’s net regulatory asset/liability. At March 31, 2010, the excess of the decommissioning liability over the trust fund balance resulted in a receivable from Oncor totaling $76 million included in noncurrent receivables from unconsolidated subsidiary in the balance sheet.

•

TCEH had posted cash collateral of $4 million as of March 31, 2010 to Oncor related to interconnection agreements for the generation units being developed by TCEH. The collateral is reported in the balance sheet in other current assets.

•

We file a consolidated federal income tax return; however, Oncor Holdings’ federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if Oncor Holdings files its own income tax return. At March 31, 2010, the amount due from Oncor Holdings totals $48 million and reduces the amount reported as net payables due to unconsolidated subsidiary.

•

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 credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, as of March 31, 2010, TCEH had posted a letter of credit in the amount of $16 million for the benefit of Oncor.

•

EFH Corp. and Oncor are jointly and severally liable for the funding of the EFH Corp. pension plan and a portion of the OPEB plan obligations. EFH Corp. is liable for the majority of the OPEB plan obligations. Oncor has contractually agreed to reimburse EFH Corp. with respect to certain pension plan and OPEB liabilities. Accordingly, the balance sheet of EFH Corp. reflects such unfunded liabilities and a corresponding receivable from Oncor in the amount of $1.272 billion, classified as noncurrent, which represents the portion of the obligations recoverable by Oncor under regulatory rate-setting provisions and reported by Oncor in its balance sheet.

15.

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 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. See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings and, accordingly, the Regulated Delivery segment, effective as of January 1, 2010.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses and interest on EFH Corp. (parent entity), Intermediate Holding 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 2009 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,
	2010			2009
Operating revenues:
Competitive Electric	$	1,999		$	1,766
Regulated Delivery		—			614
Corporate and Other		—			7
Eliminations		—			(248	)

Consolidated	$	1,999		$	2,139


Affiliated revenues included in operating revenues:
Competitive Electric	$	—		$	2
Regulated Delivery		—			240
Corporate and Other		—			6
Eliminations		—			(248	)

Consolidated	$	—		$	—


Equity in earnings of unconsolidated subsidiaries (net of tax):
Regulated Delivery (net of minority interest of $16)	$	63		$	—


Net income (loss):
Competitive Electric	$	431		$	558
Regulated Delivery		63			58
Corporate and Other		(139	)		(162	)

Consolidated	$	355		$	454

16.

SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations


	Three Months Ended March 31,
	2010			2009
Operating revenues
Regulated	$	—		$	614
Unregulated		1,999			1,773
Intercompany sales eliminations – regulated		—			(240	)
Intercompany sales eliminations – unregulated		—			(8	)

Total operating revenues		1,999			2,139
Fuel, purchased power and delivery fees – unregulated (a)		(1,047	)		(601	)
Net gain from commodity hedging and trading activities – unregulated		1,213			1,128
Operating costs – regulated		—			(221	)
Operating costs – unregulated		(197	)		(166	)
Depreciation and amortization – regulated		—			(125	)
Depreciation and amortization – unregulated		(342	)		(282	)
Selling, general and administrative expenses – regulated		—			(44	)
Selling, general and administrative expenses – unregulated		(187	)		(202	)
Franchise and revenue-based taxes – regulated		—			(60	)
Franchise and revenue-based taxes – unregulated		(22	)		(25	)
Impairment of goodwill		—			(90	)
Other income		33			13
Other deductions		(11	)		(11	)
Interest income		10			1
Interest expense and other charges		(954	)		(667	)

Income before income taxes and equity in earnings of unconsolidated subsidiaries	$	495		$	787

(a)	Includes unregulated cost of fuel consumed of $355 million and $284 million for the three months ended March 31, 2010 and 2009, 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 (SIP), options to purchase 3.6 million and 1.4 million shares of our common stock were issued to certain management employees, directors and advisors in the three months ended March 31, 2010 and 2009, respectively. Of the options granted in the three months ended March 31, 2010, 1.6 million were granted in exchange for previously granted options. 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 0.7 million (including 0.6 million that were vested) and 2.7 million shares (including 0.3 million that were vested) were forfeited during the three months ended March 31, 2010 and 2009, respectively.

In addition, 0.2 million and 0.1 million shares of common stock were awarded as compensation in the three months ended March 31, 2010 and 2009, respectively, to management employees and directors. There were no restricted shares granted in the three months ended March 31, 2010 or March 31, 2009; of the restricted shares previously granted, 600,000 and 32,500 vested in the three months ended March 31, 2010 and 2009, respectively.

Expenses recognized for options granted totaled $7 million and $3 million for the three months ended March 31, 2010 and 2009, respectively. Pursuant to the 2007 SIP, a total of 1.8 million Performance-Based Options that were eligible to vest at the end of 2009 were declared vested by the Organization and Compensation Committee of EFH Corp.’s board of directors due to the extraordinary nature of economic conditions in 2009, despite the established 2009 EBITDA target not being met. Expenses for the three months ended March 31, 2010 included $3 million related to the vesting of these options. Expenses recognized for share awards (restricted and unrestricted) totaled $2 million and $3 million for the three months ended March 31, 2010 and 2009, respectively.

Other Income and Deductions


	Three Months Ended March 31,
	2010		2009
Other income:
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting	$	—	$	10
Debt extinguishment gain (Note 6)		14		—
Adjustment to gain on sale of partial interest in natural gas gathering pipeline business (a)		7		—
Sales tax refund		5		—
Mineral rights royalty income		—		1
Other		7		2

Total other income	$	33	$	13

Other deductions:
Net charges related to cancelled development of generation facilities	$	1	$	1
Severance charges		2		5
Ongoing pension and OPEB expense related to discontinued businesses		3		—
Other		5		5

Total other deductions	$	11	$	11

(a)	Adjustment arose as a result of completion of fair value determination related to the respective parties’ investment balance.

Interest Expense and Related Charges


	Three Months Ended March 31,
	2010			2009
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	797		$	873
Unrealized mark-to-market net (gain) loss on interest rate swaps		107			(205	)
Amortization of interest rate swap losses at dedesignation of hedge accounting		29			40
Amortization of fair value debt discounts resulting from purchase accounting		19			19
Amortization of debt issuance costs and discounts		33			35
Capitalized interest		(31	)		(95	)

Total interest expense and related charges	$	954		$	667

Restricted Cash


	At March 31, 2010				At December 31, 2009
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 6)	$	—	$	1,135	$	—	$	1,135
Amounts related to margin deposits held		17		—		1		—
Amounts related to securitization (transition) bonds		—		—		47		14

Total restricted cash	$	17	$	1,135	$	48	$	1,149

Inventories by Major Category


	March 31, 2010		December 31, 2009
Materials and supplies (a)	$	157	$	248
Fuel stock		198		204
Natural gas in storage		26		33

Total inventories	$	381	$	485

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

Investments


	March 31, 2010		December 31, 2009
Nuclear decommissioning trust	$	495	$	475
Assets related to employee benefit plans, including employee savings programs, net of distributions (a)		115		184
Land		41		43
Miscellaneous other		2		4

Total investments	$	653	$	706

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

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


	March 31, 2010
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	214	$	6	$	(2	)	$	218
Equity securities (c)		200		93		(16	)		277

Total	$	414	$	99	$	(18	)	$	495


	December 31, 2009
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	211	$	8	$	(3	)	$	216
Equity securities (c)		195		83		(19	)		259

Total	$	406	$	91	$	(22	)	$	475

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

(b)

The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.18% and 4.44% and an average maturity of 7.6 years and 7.8 years at March 31, 2010 and December 31, 2009, respectively.

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

Debt securities held at March 31, 2010 mature as follows: $85 million in one to five years, $34 million in five to ten years and $99 million after ten years.

Property, Plant and Equipment

As of March 31, 2010 and December 31, 2009, property, plant and equipment of $21.2 billion and $30.1 billion, respectively, is stated net of accumulated depreciation and amortization of $3.1 billion and $7.1 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 current liabilities and other noncurrent liabilities and deferred credits in the balance sheet, during the three months ended March 31, 2010:


Asset retirement liability at January 1, 2010	$	948
Additions:
Accretion		17
Reductions:
Payments, essentially all mining reclamation		(9	)

Asset retirement liability at March 31, 2010		956
Less amounts due currently		(48	)

Noncurrent asset retirement liability at March 31, 2010	$	908

Other Noncurrent Liabilities and Deferred Credits

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


	March 31, 2010		December 31, 2009
Uncertain tax positions (including accrued interest)	$	1,933	$	1,999
Retirement plan and other employee benefits		1,647		1,711
Asset retirement obligations		908		948
Unfavorable purchase and sales contracts		693		700
Liabilities related to subsidiary tax sharing agreement (a)		—		321
Other		49		87

Total other noncurrent liabilities and deferred credits	$	5,230	$	5,766

(a)	See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010.

We do not expect the total amount of liabilities recorded related to uncertain tax positions will 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 the three months ended March 31, 2010 and 2009. Favorable purchase and sales contracts are recorded as intangible assets (see Note 4).

The estimated amortization of unfavorable purchase and sales contracts for each of the five fiscal years from December 31, 2009 is as follows:


Year	Amount
2010	$	27
2011		27
2012		27
2013		26
2014		25

Supplemental Cash Flow Information


	Three Months Ended March 31,
	2010			2009
Cash payments (receipts) related to:
Interest paid (a)	$	427		$	541
Capitalized interest		(31	)		(95	)

Interest paid (net of capitalized interest) (a)		396			446
Income taxes		2			(97	)
Noncash investing and financing activities:
Noncash construction expenditures (b)		99			123
Debt exchange transaction (Note 6)		14			—
Capital leases		6			10

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

(b)	Represents end-of-period accruals.

17.

SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

In 2007, EFH Corp. issued $2.0 billion EFH Corp. 10.875% Notes and $2.5 billion EFH Corp. Toggle Notes (collectively, the EFH Corp. Senior Notes). In May 2009 and November 2009, EFH Corp. issued an additional $150 million and $159 million, respectively, of the EFH Corp. Toggle Notes. In November 2009, EFH Corp. issued $115 million EFH Corp. 9.75% Notes in exchange for certain outstanding debt securities. In January 2010, EFH Corp. issued $500 million EFH Corp. 10% Notes (collectively with the EFH Corp. 9.75% Notes, the EFH Corp. Senior Secured Notes). In March 2010, EFH Corp. issued an additional $34 million EFH Corp. 10% Notes in exchange for certain outstanding debt securities. The EFH Corp. Senior Notes and Senior Secured Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis except for Intermediate Holding’s guarantee of the EFH Corp. Senior Secured Notes, which is secured by a pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries as described in Note 6. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes and Senior Secured Notes. The guarantees by EFC Holdings and the guarantee of the EFH Corp. Senior Notes by Intermediate Holding 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 and Senior Secured Notes (collectively, the Non-Guarantors). The indentures governing the EFH Corp. Senior Notes and Senior Secured Notes contain certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 8.

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, 2010 and 2009 and the consolidating balance sheets as of March 31, 2010 and December 31, 2009 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 $4.608 billion and $4.63 billion principal amount of EFH Corp. Senior Notes and $149 million and $115 million principal amount of the EFH Corp. Senior Secured Notes to the Guarantors as of March 31, 2010 and December 31, 2009, respectively (see Note 6). Amounts pushed down reflect Merger-related debt and additional debt guaranteed by the Guarantors that was issued by EFH Corp. to refinance Merger-related or other debt existing at the time of the Merger.

EFH Corp. (Parent) received no dividends from its consolidated subsidiaries for the three months ended March 31, 2010 and $18 million for the three months ended March 31, 2009.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Three Months Ended March 31, 2010

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	1,999		$	—		$	1,999
Fuel, purchased power costs and delivery fees		—			—			(1,047	)		—			(1,047	)
Net gain from commodity hedging and trading activities		—			—			1,213			—			1,213
Operating costs		—			—			(197	)		—			(197	)
Depreciation and amortization		—			—			(342	)		—			(342	)
Selling, general and administrative expenses		(6	)		—			(181	)		—			(187	)
Franchise and revenue-based taxes		—			—			(22	)		—			(22	)
Other income		8			—			25			—			33
Other deductions		—			—			(11	)		—			(11	)
Interest income		58			1			43			(92	)		10
Interest expense and related charges		(262	)		(148	)		(776	)		232			(954	)

Income (loss) before income taxes and equity in earnings of subsidiaries		(202	)		(147	)		704			140			495

Income tax (expense) benefit		59			49			(261	)		(50	)		(203	)

Equity in earnings of consolidated subsidiaries		435			450			—			(885	)		—

Equity in earnings of unconsolidated subsidiaries (net of tax)		63			63			—			(63	)		63


Net income		355			415			443			(858	)		355

Net income attributable to noncontrolling interests		—			—			—			—			—

Net income attributable to EFH Corp.	$	355		$	415		$	443		$	(858	)	$	355

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		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

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Three Months Ended March 31, 2010

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-guarantors			Eliminations			Consolidated
Cash provided by operating activities	$	42		$	22		$	38		$	—		$	102


Cash flows – financing activities:
Issuances of long-term borrowings		500			—			—			—			500
Retirements of long-term borrowings		—			(1	)		(131	)		—			(132	)
Change in short-term borrowings		—			—			(700	)		—			(700	)
Net short-term borrowings under accounts receivable sales program		—			—			393			—			393
Contributions from noncontrolling interests		—			—			6			—			6
Change in advances – affiliates		(753	)		9			700			44			—
Other, net		(10	)		—			—			—			(10	)

Cash provided by (used in) financing activities		(263	)		8			268			44			57


Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(372	)		—			(372	)
Investment posted with derivative counterparty		400			—			—			—			400
Proceeds from sale of environmental allowances and credits		—			—			3			—			3
Purchases of environmental allowances and credits		—			—			(5	)		—			(5	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			564			—			564
Investments in nuclear decommissioning trust fund securities		—			—			(568	)		—			(568	)
Change in advances – affiliates		—			—			44			(44	)		—
Other, net		—			—			(13	)		—			(13	)

Cash provided by (used in) investing activities		400			—			(347	)		(44	)		9


Net change in cash and cash equivalents		179			30			(41	)		—			168
Effects of deconsolidation of Oncor Holdings		(29	)		—			—			—			(29	)
Cash and cash equivalents – beginning balance		1,059			—			130			—			1,189

Cash and cash equivalents – ending balance	$	1,209		$	30		$	89		$	—		$	1,328

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		—			—			(646	)		—			(646	)
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		—			—			31			—			31

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

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at March 31, 2010

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,209		$	30		$	89		$	—		$	1,328
Restricted cash		—			—			17			—			17
Advances to affiliates		—			—			245			(245	)		—
Trade accounts receivable – net		16			3			1,146			(7	)		1,158
Income taxes receivable		59			2			—			(61	)		—
Accounts receivable from affiliates		14			—			—			(14	)		—
Notes receivable from affiliates		844			—			1,442			(2,286	)		—
Inventories		—			—			381			—			381
Commodity and other derivative contractual assets		63			—			3,689			—			3,752
Accumulated deferred income taxes		82			—			123			—			205
Margin deposits related to commodity positions		—			—			211			—			211
Other current assets		5			—			69			—			74

Total current assets		2,292			35			7,412			(2,613	)		7,126

Restricted cash		—			—			1,135			—			1,135
Receivables from unconsolidated subsidiary		1,272			—			76			—			1,348
Investments in unconsolidated subsidiaries		—			5,438			51			—			5,489
Other investments		5,133			(1,289	)		584			(3,775	)		653
Property, plant and equipment – net		—			—			21,173			—			21,173
Notes receivable from affiliates		12			—			1,490			(1,502	)		—
Goodwill		—			—			10,252			—			10,252
Intangible assets – net		—			—			2,568			—			2,568
Commodity and other derivative contractual assets		—			—			2,291			—			2,291
Accumulated deferred income taxes		555			112			—			(667	)		—
Unamortized debt issuance costs and other noncurrent assets		115			94			641			(91	)		759

Total assets	$	9,379		$	4,390		$	47,673		$	(8,648	)	$	52,794


LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	646		$	—		$	646
Advances from affiliates		244			1			—			(245	)		—
Long-term debt due currently		—			8			242			—			250
Trade accounts payable		—			—			655			—			655
Payables to affiliates/unconsolidated subsidiary		1,405			29			1,001			(2,300	)		135
Commodity and other derivative contractual liabilities		92			—			3,438			—			3,530
Margin deposits related to commodity positions		—			—			589			—			589
Accrued interest		307			233			486			(233	)		793
Other current liabilities		6			—			407			(59	)		354

Total current liabilities		2,054			271			7,464			(2,837	)		6,952

Accumulated deferred income taxes		—			—			5,743			(545	)		5,198
Commodity and other derivative contractual liabilities		—			—			1,132			—			1,132
Notes or other liabilities due affiliates/unconsolidated subsidiary		1,282			—			428			(1,502	)		208
Long-term debt, less amounts due currently		7,154			4,988			29,678			(4,941	)		36,879
Other noncurrent liabilities and deferred credits		1,748			3			3,479			—			5,230

Total liabilities		12,238			5,262			47,924			(9,825	)		55,599

EFH Corp. shareholders’ equity		(2,859	)		(872	)		(305	)		1,177			(2,859	)
Noncontrolling interests in subsidiaries		—			—			54			—			54

Total equity		(2,859	)		(872	)		(251	)		1,177			(2,805	)

Total liabilities and equity	$	9,379		$	4,390		$	47,673		$	(8,648	)	$	52,794

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2009

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,059		$	—		$	130	$	—		$	1,189
Investment posted with counterparty		425			—			—		—			425
Restricted cash		—			—			48		—			48
Advances to affiliates		471			5			—		(476	)		—
Trade accounts receivable – net		8			2			1,253		(3	)		1,260
Income taxes receivable		23			2			—		(25	)		—
Accounts receivable from affiliates		—			—			22		(22	)		—
Notes receivable from affiliates		114			—			1,469		(1,583	)		—
Inventories		—			—			485		—			485
Commodity and other derivative contractual assets		52			—			2,339		—			2,391
Accumulated deferred income taxes		—			3			11		(9	)		5
Margin deposits related to commodity positions		—			—			187		—			187
Other current assets		2			—			134		—			136

Total current assets		2,154			12			6,078		(2,118	)		6,126

Restricted cash		—			—			1,149		—			1,149
Investments in unconsolidated subsidiaries		—			—			44		—			44
Other investments		4,586			3,634			638		(8,152	)		706
Property, plant and equipment – net		—			—			30,108		—			30,108
Notes receivable from affiliates		12			—			2,236		(2,248	)		—
Goodwill		—			—			14,316		—			14,316
Intangible assets – net		—			—			2,876		—			2,876
Regulatory assets - net		—			—			1,959		—			1,959
Commodity and other derivative contractual assets		—			—			1,533		—			1,533
Accumulated deferred income taxes		647			111			—		(758	)		—
Unamortized debt issuance costs and other noncurrent assets		108			99			733		(95	)		845

Total assets	$	7,507		$	3,856		$	61,670	$	(13,371	)	$	59,662


LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,569	$	—		$	1,569
Advances from affiliates		—			—			476		(476	)		—
Long-term debt due currently		—			8			409		—			417
Trade accounts payable		4			—			892		—			896
Accounts payable to affiliates		16			6			—		(22	)		—
Notes payable to affiliates		1,406			27			150		(1,583	)		—
Commodity and other derivative contractual liabilities		82			—			2,310		—			2,392
Margin deposits related to commodity positions		—			—			520		—			520
Accumulated deferred income taxes		9			—			—		(9	)		—
Accrued interest		119			93			408		(94	)		526
Other current liabilities		7			—			761		(24	)		744

Total current liabilities		1,643			134			7,495		(2,208	)		7,064

Accumulated deferred income taxes		—			—			6,764		(633	)		6,131
Investment tax credits		—			—			37		—			37
Commodity and other derivative contractual liabilities		—			—			1,060		—			1,060
Notes or other liabilities due affiliates		2,019			—			229		(2,248	)		—
Long-term debt, less amounts due currently		6,626			4,975			34,740		(4,901	)		41,440
Other noncurrent liabilities and deferred credits		466			3			5,297		—			5,766

Total liabilities		10,754			5,112			55,622		(9,990	)		61,498

EFH Corp. shareholders’ equity		(3,247	)		(1,256	)		4,637		(3,381	)		(3,247	)
Noncontrolling interests in subsidiaries		—			—			1,411		—			1,411

Total equity		(3,247	)		(1,256	)		6,048		(3,381	)		(1,836	)

Total liabilities and equity	$	7,507		$	3,856		$	61,670	$	(13,371	)	$	59,662

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, 2010 and 2009 should be read in conjunction with our consolidated financial statements and the notes to those statements.

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

BUSINESS

We are a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, 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 enhance the credit quality of Oncor. See Notes 1 and 3 to Financial Statements for a description of the material features of these “ring-fencing” measures and for a discussion of the deconsolidation of Oncor (and its majority owner, Oncor Holdings) in 2010 as the result of a change in accounting principles.

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 Regulated Delivery segment is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Notes 1 and 3 to Financial Statements for discussion of the deconsolidation of Oncor Holdings and, accordingly, Oncor and the Regulated Delivery segment, in 2010.

See Note 15 to Financial Statements for further information regarding reportable business segments.

Significant Activities and Events

Natural Gas Prices and 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, 2010, has effectively sold forward approximately 1.5 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 188,000 GWh at an assumed 8.0 market heat rate) for the period from April 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.80 per MMBtu to $7.19 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 67% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning April 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the New York Mercantile Exchange (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 2010.

The company has entered into related put and call transactions (referred to as collars), primarily for year 2014 of the program, that effectively hedge natural gas prices within a range. These transactions represented approximately 7% of the positions in the long-term hedging program at March 31, 2010, 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. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.

The following table summarizes the natural gas hedges in the long-term hedging program as of March 31, 2010:

Measure

Balance
2010 (a)

2011

2012

2013

2014

Total

Natural gas hedge volumes (b)

mm MMBtu

~181

~424

~487

~300

~99

~1,491

Weighted average hedge price (c)

$/MMBtu

~7.71

~7.56

~7.36

~7.19

~7.80

—

Weighted average market price (d)

$/MMBtu

~4.27

~5.34

~5.79

~6.07

~6.36

—

(a)	Balance of 2010 is from April 1, 2010 through December 31, 2010.

(b)	Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 99 million MMBtu in 2014.

(c)

Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price.

(d)	Based on NYMEX Henry Hub prices.

Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of 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, 2010, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.5 billion in pretax unrealized mark-to-market gains or losses.

The reported unrealized mark-to-market net gain related to the long-term hedging program for the three months ended March 31, 2010 totaled $1.057 billion. This amount reflects a $1.3 billion net gain due to the effect of lower forward prices of natural gas on the value of positions in the program, which was partially offset by net losses of $243 million representing reversals of previously recorded unrealized gains on positions that settled in the period. The reported unrealized mark-to-market net gain related to the long-term hedging program for the three months ended March 31, 2009 totaled $1.158 billion reflecting declines in forward prices of natural gas in 2009. Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost. The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $3.035 billion and $1.978 billion at March 31, 2010 and December 31, 2009, respectively. These values can change materially as market conditions change.

The significant cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program reflects declining forward market natural gas prices. As previously disclosed, forward natural gas prices have generally trended downward since mid-2008 as shown in the table of forward NYMEX Henry Hub natural gas prices below. While the long-term hedging program is designed to mitigate the effect on earnings of lower wholesale power prices, due to the lower natural gas prices, these market conditions are challenging to the long-term profitability of our generation assets. Specifically, this downward trend in natural gas prices and the correlated trend in ERCOT power prices could have a material adverse impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. Additionally, a continued decline in forward natural gas prices will limit our ability to hedge our wholesale power revenues at reasonable price levels to support our interest payments and debt maturities.


	Forward Market Prices for Calendar Year ($/MMBtu) (a)
Date	2010 (b)		2011		2012		2013		2014
June 30, 2008	$	11.24	$	10.78	$	10.74	$	10.90	$	11.12
September 30, 2008	$	8.58	$	8.54	$	8.41	$	8.30	$	8.30
December 31, 2008	$	7.13	$	7.31	$	7.23	$	7.15	$	7.15
March 31, 2009	$	5.93	$	6.67	$	6.96	$	7.11	$	7.18
June 30, 2009	$	6.06	$	6.89	$	7.16	$	7.30	$	7.43
September 30, 2009	$	6.21	$	6.87	$	7.00	$	7.06	$	7.17
December 31, 2009	$	5.79	$	6.34	$	6.53	$	6.67	$	6.84
March 31, 2010	$	4.27	$	5.34	$	5.79	$	6.07	$	6.36

(a)	Based on NYMEX Henry Hub prices.

(b)	For March 31, 2010, natural gas prices for 2010 represent the average of forward prices for April through December.

As of March 31, 2010, 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 “Financial Condition – Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of March 31, 2010, 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 2010 (a)

2011

2012

2013

2014

$1.00/MMBtu change in gas price (b)

~13

~45

~85

~300

~505

0.1/MMBtu/MWh change in market heat rate (c)

~35

~50

~55

$1.00/gallon change in diesel fuel price

~50

~55

(a)	Balance of 2010 is from May 1, 2010 through December 31, 2010.

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

(c)	Based on Houston Ship Channel natural gas prices as of March 31, 2010.

Debt Issuances, Exchanges and Repurchases — See Note 6 to Financial Statements for discussion of the issuance of additional notes in January 2010, a debt exchange transaction in March 2010 and a debt repurchase and exchange transactions in April 2010.

TCEH Interest Rate Swap Transactions — As of March 31, 2010, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.30 billion principal amount of its senior secured debt maturing from 2010 to 2014. All of these swaps were entered into prior to January 1, 2010. Taking into consideration these swap transactions, approximately 11% of our total long-term debt portfolio at March 31, 2010 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions (all prior to January 1, 2010), which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $13.75 billion principal amount of senior secured debt. We may enter into additional interest rate hedges from time to time. Unrealized mark-to-market net gains and losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $107 million in net losses for the three months ended March 31, 2010 and $205 million in net gains for the three months ended March 31, 2009. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.320 billion and $1.212 billion at March 31, 2010 and December 31, 2009, respectively, of which $165 million and $194 million (both pre-tax), respectively, 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 6 to Financial Statements regarding various interest rate swap transactions.

Texas Generation Facilities Development — TCEH is nearing completion of a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. Construction of the Sandow and first Oak Grove units was completed in 2009, and we began depreciating those units and recognizing revenues and fuel costs for accounting purposes in the fourth quarter 2009. The second Oak Grove unit, which is in the commissioning and start-up phase, synchronized to the grid in January 2010 and is expected to achieve substantial completion (as defined in the EPC Agreement for the unit) in mid-2010. 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 $3.16 billion was spent as of March 31, 2010. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.8 billion upon completion of the units, and the balance was $4.7 billion as of March 31, 2010. See discussion in Note 7 to Financial Statements regarding contingencies related to these units.

Idling of Natural Gas-Fueled Units — In February 2010, we notified ERCOT of plans to mothball (idle) four of our natural gas-fueled units, totaling 1,856 MW of capacity (1,933 MW installed nameplate capacity), in September 2010. In April 2010, ERCOT affirmed that the units may be mothballed. As discussed in the 2009 Form 10-K, in 2009 we retired 10 units, totaling 2,114 MW of capacity (2,226 MW installed nameplate capacity), mothballed three units, totaling 1,081 MW capacity (1,135 MW installed nameplate capacity) and entered into RMR agreements for two units, totaling 630 MW capacity (655 MW installed nameplate capacity).

Global Climate Change — In March 2010, the EPA finalized its rules to reduce GHG emissions from certain motor vehicles. Thus, for the first time, GHG emissions are air contaminants regulated under the Clean Air Act. In April 2010, the EPA finalized an interpretive rule that affirms that once GHG emissions are air contaminants regulated under the Clean Air Act, major sources of GHG emissions – including fossil-fuel fired electricity generating units – will need to address GHG emissions in air permits for new sources and to satisfy the control technology requirements of the Clean Air Act’s New Source Review (NSR) program with respect to GHG emissions if they undergo a major modification that is subject to the NSR program. This rule clarifies that the NSR requirements first apply to stationary sources in January 2011, when 2012 model vehicles must comply with the motor vehicle GHG emissions reduction requirements. The EPA has also indicated that its proposed “tailoring rule” (which seeks to define the threshold of GHG emissions for determining applicability of the Clean Air Act’s permitting programs and NSR program at levels greater than the emission thresholds currently contained in the Clean Air Act) will be finalized by May 2010. In addition, in September 2009, the EPA issued a final rule requiring the reporting by March 2011 of calendar year 2010 GHG emissions from specified large GHG emissions sources in the US (such reporting rule applies to our lignite/coal- and natural gas-fueled generation facilities). Our costs of complying with any future EPA limitations on GHG emissions could be material.

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. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits.

As of March 31, 2010, Oncor has installed approximately 845 thousand advanced digital meters, including approximately 185 thousand during the three months ended March 31, 2010. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $236 million as of March 31, 2010.

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

RESULTS OF OPERATIONS

Pro Forma Consolidated Financial Results

The following pro forma results for the three months ended March 31, 2009 are presented to provide for a meaningful comparison, along with the analyses on the following pages, of consolidated operating results in consideration of the prospective deconsolidation of Oncor Holdings in 2010 as discussed in Notes 1 and 3 to Financial Statements.


	Three Months			Three Months Ended March 31, 2009
	Ended March 31, 2010			As Reported			Pro Forma Adjustments (a)			Pro Forma
	(millions of dollars)
Operating revenues	$	1,999		$	2,139		$	(372	)	$	1,767
Fuel, purchased power costs and delivery fees		(1,047	)		(601	)		(242	)		(843	)
Net gain from commodity hedging and trading activities		1,213			1,128			—			1,128
Operating costs		(197	)		(387	)		219			(168	)
Depreciation and amortization		(342	)		(407	)		126			(281	)
Selling, general and administrative expenses		(187	)		(246	)		45			(201	)
Franchise and revenue-based taxes		(22	)		(85	)		60			(25	)
Impairment of goodwill		—			(90	)		—			(90	)
Other income		33			13			(10	)		3
Other deductions		(11	)		(11	)		2			(9	)
Interest income		10			1			1			2
Interest expense and related charges		(954	)		(667	)		75			(592	)

Income before income taxes and equity in earnings of unconsolidated subsidiaries		495			787			(96	)		691
Income tax expense		(203	)		(333	)		37			(296	)
Equity in earnings of unconsolidated subsidiaries (net of tax)		63			—			47			47

Net income		355			454			(12	)		442
Net income attributable to noncontrolling interests		—			(12	)		12			—

Net income attributable to EFH Corp.	$	355		$	442		$	—		$	442

(a)	All pro forma adjustments relate to Oncor Holdings and result in the presentation of the investment in Oncor Holdings under the equity method of accounting for the three months ended March 31, 2009.

Consolidated Financial Results — Three Months Ended March 31, 2010 Compared to Pro Forma Three Months Ended March 31, 2009

Reference is made to comparisons of results of the Competitive Electric segment following the discussion of consolidated results, discussion of Regulated Delivery segment results below in the discussion of consolidated net income and discussion of the deconsolidation of Oncor Holdings and, accordingly, Oncor and the Regulated Delivery segment in Notes 1 and 3 to Financial Statements. As the result of deconsolidation, the results of Oncor Holdings, Oncor, and the Regulated Delivery segment in 2010 are reflected on a prospective basis in the statement of income as equity in earnings of unconsolidated subsidiary (net of tax) instead of separately as revenues and expenses as they are shown for periods prior to January 1, 2010. The business segment comparisons provide additional detail and quantification of items affecting financial results.

See comparison of results of the Competitive Electric segment for discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gains from commodity hedging and trading activities, operating costs; depreciation and amortization, and franchise and revenue-based taxes.

SG&A expenses decreased $14 million, or 7%, to $187 million in 2010.

•

SG&A expenses in the Competitive Electric segment increased $10 million, or 6%, to $183 million.

•

Corporate and Other SG&A expenses decreased $24 million, or 86%, to $4 million. The decline primarily reflected $11 million in costs allocated to the competitive operations effective 2010 (primarily fees paid to the Sponsor Group), $8 million in lower transition costs associated with outsourced support services and $2 million in lower compensation-related expense.

The $90 million impairment of goodwill recorded in 2009 largely related to the Competitive Electric segment and resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008 as discussed in Note 3 to Financial Statements in the 2009 Form 10-K.

See Note 16 to Financial Statements for details of other income and deductions.

Interest income increased $8 million to $10 million in 2010 primarily driven by interest on $465 million in collateral under a funding arrangement described in Note 11 to Financial Statements.

Interest expense and related charges increased $362 million, or 61%, to $954 million in 2010 reflecting a $107 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $205 million net gain in 2009 and a $63 million decrease in capitalized interest due to completion of certain new generation facility construction activities, partially offset by $11 million in decreased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges. See Note 16 to Financial Statements.

Income tax expense totaled $203 million in 2010 compared to $296 million in 2009. The effective rate was 41.0% and 42.8% in 2010 and 2009, respectively. The decrease in the rate reflects the impact of the nondeductible goodwill impairment of $90 million in 2009, which increased the rate 4.9 percentage points in 2009, partially offset by the effect of the $8 million deferred tax charge in 2010 related to the Patient Protection and Affordable Care Act (see Note 13 to Financial Statements).

Equity in earnings of unconsolidated subsidiaries (net of tax) totaled $63 million in 2010 compared to $47 million in 2009. The increase of $16 million, or 34%, reflected a $20 million increase in Oncor’s net income, partially offset by a $4 million increase in minority interest holders’ equity in Oncor’s earnings. The $20 million, or 36%, increase in Oncor’s net income was driven by higher revenues that reflected higher average consumption, primarily due to colder than normal weather in 2010 and warmer than normal weather in 2009. Higher tariffs were largely offset by increased expenses.

Net income attributable to EFH Corp. decreased $87 million to $355 million in 2010.

•

Net income in the Competitive Electric segment decreased $127 million to $431 million.

•

Earnings from the Regulated Delivery segment increased $16 million to $63 million as discussed above.

•

Corporate and Other net expenses (after-tax) totaled $139 million in 2010 and $163 million in 2009. The amounts in 2010 and 2009 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The decrease of $24 million reflected a $20 million goodwill impairment charge in 2009, $16 million in lower SG&A expense as discussed above and a $9 million debt extinguishment gain, partially offset by a $16 million increase in interest expense driven by higher borrowings and an $8 million deferred tax charge due to the implementation of the Patient Protection and Affordable Care Act.

Non-GAAP Earnings Measures

In communications with investors, we use a non-GAAP earnings measure that reflects adjustments to earnings reported in accordance with US GAAP in order to review underlying operating performance. These adjusting items, which are generally noncash, consist of unrealized mark-to-market gains and losses, impairment charges, debt extinguishment gains and other charges, credits or gains that are unusual or nonrecurring; all such items and related amounts are disclosed in our annual report on Form 10-K and quarterly reports on Form 10-Q. Our communications with investors also reference “adjusted EBITDA,” which is a non-GAAP measure used in calculation of ratios in covenants of certain of our debt securities (see “Financial Covenants, Credit Rating Provisions and Cross Default Provisions” below).

Competitive Electric Segment

Financial Results


	Three Months Ended March 31,
	2010			2009

Operating revenues	$	1,999		$	1,766
Fuel, purchased power costs and delivery fees		(1,047	)		(843	)
Net gain from commodity hedging and trading activities		1,213			1,128
Operating costs		(197	)		(168	)
Depreciation and amortization		(337	)		(276	)
Selling, general and administrative expenses		(183	)		(173	)
Franchise and revenue-based taxes		(22	)		(25	)
Impairment of goodwill		—			(70	)
Other income		14			3
Other deductions		(6	)		(10	)
Interest income		22			8
Interest expense and related charges		(777	)		(425	)


Income before income taxes		679			915

Income tax expense		(248	)		(357	)


Net income	$	431		$	558

Competitive Electric Segment

Sales Volume and Customer Count Data


	Three Months Ended March 31,
	2010		2009		% Change
Sales volumes:

Retail electricity sales volumes – (GWh):
Residential	6,719		5,880		14.3
Small business (a)	1,982		1,722		15.1
Large business and other customers	3,519		3,305		6.5

Total retail electricity	12,220		10,907		12.0
Wholesale electricity sales volumes	12,363		9,792		26.3
Net sales (purchases) of balancing electricity to/from ERCOT	(655	)	(153	)	—

Total sales volumes	23,928		20,546		16.5


Average volume (kWh) per residential customer (b)	3,621		3,059		18.4

Weather (North Texas average) – percent of normal (c):

Heating degree days	135.8	%	90.6	%	49.9

Customer counts:

Retail electricity customers (end of period and in thousands) (d):
Residential	1,849		1,930		(4.2	)
Small business (a)	250		275		(9.1	)
Large business and other customers	22		24		(8.3	)

Total retail electricity customers	2,121		2,229		(4.8	)

(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). Normal is defined as the average over a 10-year period.

(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.

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities


	Three Months Ended March 31,
	2010			2009			% Change
Operating revenues:

Retail electricity revenues:
Residential	$	870		$	793		9.7
Small business (a)		267			264		1.1
Large business and other customers		284			314		(9.6	)

Total retail electricity revenues		1,421			1,371		3.6
Wholesale electricity revenues (b)		545			348		56.6
Net sales (purchases) of balancing electricity to/from ERCOT		(42	)		(23	)	(82.6	)
Amortization of intangibles (c)		(1	)		(11	)	90.9
Other operating revenues		76			81		(6.2	)

Total operating revenues	$	1,999		$	1,766		13.2


Net gain from commodity hedging and trading activities:

Unrealized net gains from changes in fair value	$	1,203		$	1,155		4.2
Unrealized net losses representing reversals of previously recognized fair values of positions settled in the current period		(225	)		(106	)	—
Realized net gains on settled positions		235			79		—

Total gain	$	1,213		$	1,128		7.5

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

(b)

Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which the company considers “unrealized.” These amounts are as follows:


	Three Months Ended March 31,
	2010			2009
Reported in revenues	$	(18	)	$	(60	)
Reported in fuel and purchased power costs		33			41

Net gain (loss)	$	15		$	(19	)

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

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data


	Three Months Ended March 31,
	2010			2009			% Change
Fuel, purchased power costs and delivery fees ($ millions):

Nuclear fuel	$	38		$	37	(f)	2.7
Lignite/coal		223			153		45.8

Total baseload fuel		261			190		37.4
Natural gas fuel and purchased power (a)		324			219		47.9
Amortization of intangibles (b)		42			62	(f)	(32.3	)
Other costs		65			57		14.0

Fuel and purchased power costs		692			528		31.1
Delivery fees (c)		355			315		12.7

Total	$	1,047		$	843		24.2


Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:

Nuclear fuel	$	7.56		$	7.17	(f)	5.4
Lignite/coal (d)		20.02			16.93		18.3
Natural gas fuel and purchased power		48.83			43.94		11.1

Delivery fees per MWh	$	28.99		$	28.59		1.4

Production and purchased power volumes (GWh):

Nuclear		5,013			5,190		(3.4	)
Lignite/coal		12,818			10,255		25.0

Total baseload generation		17,831			15,445		15.4
Natural gas-fueled generation		372			258		44.2
Purchased power		6,256			4,729		32.3

Total energy supply		24,459			20,432		19.7
Less line loss and power imbalances (e)		531			(114	)	—

Net energy supply volumes		23,928			20,546		16.5


Baseload capacity factors:

Nuclear		100.9	%		104.6	%	(3.5	)
Lignite/coal		82.1	%		81.4	%	0.9
Total baseload		86.7	%		88.0	%	(1.5	)

(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.

(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.

(e)	Includes physical purchases and sales, the financial results of which are reported in commodity hedging and trading activities in the income statement.

(f)	Reflects reclassification to correct amortization.

Competitive Electric Segment – Financial Results — Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Operating revenues increased $233 million, or 13%, to $1.999 billion in 2010.

Wholesale electricity revenues increased $197 million, or 57%, to $545 million in 2010 as compared to 2009 when revenues decreased 44%. A 26% increase in wholesale electricity sales volumes, reflecting production from the new generation units, increased revenues by $107 million. A 9% increase in average wholesale electricity prices, reflecting higher natural gas prices and market heat rates, increased revenues by $48 million. The balance of the revenue increase reflected a decrease in unrealized losses related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

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.

Comparisons of wholesale balancing activity, reported net, are generally not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable.

Retail electricity revenues increased $50 million or 4%, to $1.421 billion and reflected the following:

•

A 12 percent increase in sales volumes increased revenues by $165 million reflecting increases in both the residential and business markets. Higher average consumption resulted in a 14 percent increase in residential sales volumes, reflecting colder than normal weather in 2010 and warmer than normal weather in 2009, partially offset by a decline in residential customer counts. A nine percent increase in business markets sales volumes reflected a change in customer mix, the impact of colder weather and improved economic activity.

•

Lower average pricing decreased revenues by $115 million driven by the contract business market and also reflecting lower residential pricing. Lower average pricing in the business markets reflected competitive activity and the change in customer mix referred to above. A four percent decline in average residential pricing reflected price reductions that became effective in August 2009 for month-to-month customers, lower average price offerings for new customers and a change in customer mix.

•

Total retail electricity customer counts at March 31, 2010 decreased five percent from March 31, 2009 reflecting a nine percent decline in business markets and a four percent decline in residential markets driven by competitive activity.

The change in operating revenues also reflected a $10 million decrease in amortization of intangible assets arising from purchase accounting reflecting expiration of retail sales contracts.

Fuel, purchased power costs and delivery fees increased $204 million, or 24%, to $1.047 billion in 2010. Higher purchased power costs contributed $75 million to the increase and reflected increased volumes, driven by higher retail sales, and the effect of higher natural gas prices and market heat rates as discussed above regarding wholesale revenues. Other factors contributing to the increase included $40 million in higher delivery fees, reflecting increased retail sales volumes and tariffs, $38 million in lignite fuel costs related to production from the new generation units at Oak Grove and Sandow, $32 million in higher lignite/coal costs at existing plants, reflecting higher purchased coal transportation costs, $30 million in higher fuel costs for natural gas-fueled generation driven by higher prices and volumes and $17 million from the effect of higher natural gas prices and volumes on natural gas purchased for sale to industrial customers. These increases were partially offset by $20 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting.

Overall baseload generation production increased 15% in 2010 reflecting a 25% increase in lignite/coal-fueled production, partially offset by a three percent decrease in nuclear production. The increase in lignite/coal-fueled production was driven by the production in 2010 from the new generation units and also reflected 12% fewer planned and unplanned outage days at existing lignite/coal-fueled generation units. The decrease in nuclear production was due to an unplanned transformer outage in January 2010.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the three months ended March 31, 2010 and 2009, which totaled $1.213 billion and $1.128 billion, respectively:

Three Months Ended March 31, 2010 — Unrealized mark-to-market net gains totaling $978 million included:

•

$963 million in net gains related to hedge positions, which includes $1.175 billion in net gains from changes in fair value and $212 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

•

$15 million in net gains related to trading positions, which includes $28 million in net gains from changes in fair value and $13 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $235 million included:

•

$209 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

•

$26 million in net gains related to trading positions.

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 net gains on 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 net gains on positions settled in the period.

Realized net gains totaling $79 million included:

•

$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.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $15 million in net gains in 2010 and $19 million in net losses in 2009.

Operating costs increased $29 million, or 17%, to $197 million in 2010. The increase reflected $20 million in operating costs related to the new generation units. The increase also reflects $8 million in outage-related costs at the Comanche Peak nuclear-fueled plant reflecting the transformer failure and timing of maintenance activities.

Depreciation and amortization increased $61 million, or 22%, to $337 million in 2010. The increase reflected $35 million in incremental expense related to the new generation units and associated mining operations. The balance of the increase was driven by equipment additions and accelerated depreciation expense related to pending equipment retirements.

SG&A expenses increased $10 million, or 6%, to $183 million in 2010. The increase reflected $15 million in increased bad debt expense in the retail operations primarily associated with residential customers, reflecting higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions. The increase also reflected $11 million in new costs allocated from corporate, principally fees paid to the Sponsor Group. These increases were partially offset by $7 million in lower outsourced costs and expenses related to the retail customer information management system implemented in 2009, $7 million in lower employee compensation-related pay expense and $4 million related to accounts receivable securitization program fees that are reported as interest expense and related charges in 2010 (see Note 5 to Financial Statements).

The $70 million impairment of goodwill recorded in 2009 resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008 as discussed in Note 3 to Financial Statements in the 2009 Form 10-K.

Other income totaled $14 million in 2010 and $3 million in 2009. Other income in 2010 includes a $7 million gain associated with the sale of a partial interest in a business (see Note 16) and a $5 million refund of sales taxes related to prior years.

Interest income increased $14 million to $22 million in 2010 reflecting higher notes receivable balances from affiliates.

Interest expense and related charges increased by $352 million, or 83%, to $777 million in 2010 reflecting a $107 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $205 million net gain in 2009 and a $63 million decrease in capitalized interest due to completion of certain new generation facility construction activities, partially offset by $12 million in lower average rates and $11 million in decreased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges.

Income tax expense totaled $248 million in 2010 compared to $357 million in 2009. The effective rate was 36.5% and 39.0% in 2010 and 2009, respectively. The decrease in the effective rate reflects the impacts of the nondeductible goodwill impairment of $70 million in 2009, which increased the effective rate by 2.8 percentage points in 2009.

Net income for the segment decreased $127 million in 2010 to $431 million reflecting higher interest expense and related charges, partially offset by higher realized net gains related to commodity hedging activities and a charge for impairment of goodwill in 2009.

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, 2010 and 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 11 to Financial Statements). The portfolio consists primarily of economic hedges but also includes trading positions.


	Three Months Ended March 31,
	2010			2009
Commodity contract net asset at beginning of period	$	1,718		$	430

Settlements of positions (a)		(210	)		(125	)

Changes in fair value (b)		1,203			1,155

Other activity (c)		21			(2	)


Commodity contract net asset at end of period (d)	$	2,732		$	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)	Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”).

(c)

These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold and physical natural gas exchange transactions. 2010 amount includes $16 million related to option premiums and $5 million related to settlement of a power sales agreement.

(d)	2010 amount excludes $3 million in net derivative liability related to cash flow hedge positions not marked-to-market in net income. See Note 11 to Financial Statements for additional discussion of commodity contracts assets and liabilities.

Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of March 31, 2010, 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, 2010
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(126	)	$	(78	)	$	—		$	—		$	(204	)
Prices provided by other external sources		1,038			1,486			256			—			2,780
Prices based on models		42			2			275			(163	)		156

Total	$	954		$	1,410		$	531		$	(163	)	$	2,732

Percentage of total fair value		35	%		52	%		19	%		(6	)%		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 in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West zone) generally extend through 2012 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 9 to Financial Statements for fair value disclosures and discussion of fair value measurements.

FINANCIAL CONDITION

Liquidity and Capital Resources

Cash Flows — Cash provided by operating activities for the three months ended March 31, 2010 and 2009 totaled $102 million and $590 million, respectively. The decrease in cash provided of $488 million was driven by a $383 million effect of the amended accounting standard related to the sale of accounts receivable program (see Note 5 to Financial Statements). Changes in funding under the program have previously been reported as operating cash flows, and the amended accounting rule requires that the amount of funding under the program upon the January 1, 2010 adoption ($383 million) be reported as a use of operating cash flows and a source of financing cash flows. All changes in funding subsequent to adoption of the amended standard are reported as financing activities.

Cash provided by financing activities totaled $57 million in 2010 compared to $138 million in 2009 as summarized below:


	Three Months Ended March 31,
	2010			2009
Net issuances, repayments and repurchases of borrowings	$	(351	)	$	118
Net contributions from and distributions to noncontrolling interests		6			19
Net short-term borrowings under accounts receivable sales program		393			—
Other		9			1

Total provided by financing activities	$	57		$	138

Cash provided by investing activities totaled $9 million in 2010 compared to cash used of $882 million in 2009 as summarized below:


	Three Months Ended March 31,
	2010			2009
Capital expenditures, including nuclear fuel	$	(372	)	$	(646	)
Redemption of investment held in money market fund		—			142
Investment redeemed/(posted) with counterparty		400			(400	)
Other		(19	)		22

Total provided by (used in) investing activities	$	9		$	(882	)

The decline in capital spending for the three months ended March 31, 2010 as compared to the three months ended March 31, 2009 primarily reflected the deconsolidation of Oncor ($243 million capital expenditures in 2009) (see Note 3 to Financial Statements) in 2010 and a decrease in spending related to the construction of new generation facilities.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $101 million and $113 million for the three months ended March 31, 2010 and 2009, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice, and 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.

Debt Financing Activity — Activities related to short-term borrowings and long-term debt during the three months ended March 31, 2010 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):


	Borrowings (a)		Repayments and Repurchases (b)
TCEH	$	—	$	158
EFC Holdings		—		1
Intermediate Holding		—		—
EFH Corp.		534		18

Total long-term		534		177

Total short-term – TCEH (c)		—		700

Total	$	534	$	877

(a) Includes $34 million of noncash principal increases as a result of a March 2010 debt exchange transaction discussed in Note 6 to Financial Statements. (b) Includes $47 million of noncash retirements as a result of a March 2010 debt exchange transaction discussed in Note 6 to Financial Statements. (c) Short-term amounts represent net borrowings/repayments.

See Note 6 to Financial Statements for further detail of long-term debt and other financing arrangements.

We, our affiliates or our agents may from time to time purchase our outstanding debt for cash in open market purchases or privately negotiated transactions (including pursuant to a Section 10b-5(1) plan) or via privately negotiated exchange transactions similar to the March 2010 exchange transaction, or we may refinance existing debt. We will evaluate any such transactions in light of market prices of the debt, 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.

Available Liquidity — The following table summarizes changes in available liquidity for the three months ended March 31, 2010.


	Available Liquidity
	March 31, 2010		December 31, 2009		Change
Cash and cash equivalents	$	1,328	$	1,161	$	167
TCEH Revolving Credit Facility (a)		2,421		1,721		700
TCEH Letter of Credit Facility		434		399		35

Subtotal	$	4,183	$	3,281	$	902
Short-term investment (b)		—		490		(490	)

Total liquidity (c)	$	4,183	$	3,771	$	412

(a)

As of March 31, 2010 and December 31, 2009, the TCEH Revolving Credit Facility includes $141 million of commitments from Lehman that are only available from the fronting banks and the swingline lender. The $700 million change in availability reflects TCEH’s use of borrowings under a demand note payable to EFH Corp. to repay revolver borrowings.

(b)

December 31, 2009 amount includes $425 million cash investment (including accrued interest) and $65 million in letters of credit posted related to certain interest rate and commodity hedge transactions. Pursuant to the related agreement, the collateral was returned in March 2010. See Note 11 to Financial Statements.

(c)	Available liquidity for Oncor is not presented as a result of deconsolidation in 2010 as discussed in Notes 1 and 3 to Financial Statements.

Note: Available liquidity above does not include the amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from May 2010 through November 2012 could avoid cash interest payments of approximately $1.6 billion.

The $412 million increase in available liquidity reflected the net proceeds from the January 2010 issuance of $500 million principal amount of senior secured notes described in Note 6 to Financial Statements.

See Note 6 to Financial Statements for additional discussion of the credit facilities.

In May 2010, TCEH borrowed $360 million under its Revolving Credit Facility; $99 million was loaned to EFH Corp to fund interest payments on its 10.875% Notes, and the remainder was used to fund interest payments on TCEH debt, principally its 10.25% Notes.

Pension and OPEB Plan Funding — Pension and OPEB plan funding is expected to total $45 million and $24 million, respectively, in 2010. Oncor is expected to fund approximately 88% of this amount consistent with its share of the pension liability. We made pension and OPEB contributions of $1 million and $6 million, respectively, in the three months ended March 31, 2010, including $4 million contributed by Oncor.

Toggle Notes Interest Election — EFH Corp. and TCEH have the option every six months at their discretion, ending with the payment due November 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. We elected to do so beginning with the May 2009 interest payment as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy and related lower electricity demand and the continuing uncertainty in the financial markets. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.

EFH Corp. made its May 2010 interest payment and will make its November 2010 interest payment by using the PIK feature of its Toggle Notes. During such applicable interest periods, the interest rate on these notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $162 million in May 2010 and will further increase the aggregate principal amount of the notes by $172 million in November 2010. The elections increased liquidity in May 2010 by an amount equal to approximately $152 million and will further increase liquidity in November 2010 by an amount equal to approximately $161 million, constituting the amounts of cash interest that otherwise would have been payable on the notes in May 2010 and November 2010, respectively. These amounts are net of the effects of the April 2010 debt exchange transactions discussed in Note 6 to Financial Statements.

Similarly, TCEH made its May 2010 interest payment and will make its November 2010 interest payment by using the PIK feature of its Toggle Notes. During such applicable interest periods, the interest rate on these notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $110 million in May 2010 and will further increase the aggregate principal amount of the notes by $116 million in November 2010. The elections increased liquidity in May 2010 by an amount equal to approximately $103 million and will further increase liquidity in November 2010 by an amount equal to approximately $108 million, constituting the amounts of cash interest that otherwise would have been payable on the notes in May 2010 and November 2010, respectively.

See Note 6 to Financial Statements for discussion of a debt exchange transaction in March 2010 that resulted in redemption of portions of the outstanding principal of the EFH Corp. and TCEH Toggle Notes held by unaffiliated parties that are reflected in the amounts related to the May 2010 and November 2010 PIK elections.

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, asset-backed liens 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, 2010, 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 6 to Financial Statements for more information about this facility.

As of March 31, 2010, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

•

$210 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $183 million posted as of December 31, 2009;

•

$589 million in cash has been received from counterparties, net of $400 thousand in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $516 million received, net of $4 million in cash posted, as of December 31, 2009;

•

$304 million in letters of credit have been posted with counterparties, as compared to $379 million posted as of December 31, 2009, and

•

$41 million in letters of credit have been received from counterparties, as compared to $44 million received as of December 31, 2009.

With respect to exchange cleared transactions, these transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of March 31, 2010, restricted cash collateral held totaled $17 million. See Note 16 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 postings to counterparties. As of March 31, 2010, approximately 555 million 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 substantially all of these transactions.

Income Tax Refunds/Payments — Income tax payments, primarily amounts related to the Texas margin tax, are expected to total approximately $72 million in the next 12 months. Payments in the three months ended March 31, 2010 totaled $2 million.

Sale of Accounts Receivable — TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). As discussed in Note 1 to Financial Statements, in accordance with amended transfers and servicing accounting standards, the trade accounts receivable amounts under the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $393 million and $383 million at March 31, 2010 and December 31, 2009, respectively. See Note 5 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 termination of the program and a reduction of liquidity should the underlying financing be settled.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of March 31, 2010, we were in compliance with all such covenants.

Covenants and Restrictions under Financing Arrangements — Each of the TCEH Senior Secured Facilities and the indentures governing substantially all of the debt we have issued in connection with, and subsequent to, the Merger contain covenants that could have a material impact on the liquidity and operations of EFH Corp. and its subsidiaries.

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, 2010 totaled $5.016 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, 2010 and 2009.

The following table summarizes TCEH’s secured debt to adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp., Intermediate Holding and TCEH that are applicable under certain other covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the EFH Corp. Senior Notes, the EFH Corp. Senior Secured Notes and the EFIH Notes as of March 31, 2010 and December 31, 2009 and the corresponding maintenance and other covenant threshold levels as of March 31, 2010:


	March 31, 2010	December 31, 2009	Threshold Level as of March 31, 2010
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to adjusted EBITDA ratio (a)	5.02 to 1.00	4.76 to 1.00	Must not exceed 7.00 to 1.00 (b)

Debt Incurrence Covenants:
EFH Corp. Senior Notes:
EFH Corp. fixed charge coverage ratio	1.1 to 1.0	1.2 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.5 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
EFH Corp. Senior Secured Notes:
EFH Corp. fixed charge coverage ratio	1.1 to 1.0	1.2 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.5 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
EFIH Notes:
Intermediate Holding fixed charge coverage ratio (c)	8.2 to 1.0	53.8 to 1.0	At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.5 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.5 to 1.0	1.5 to 1.0	At least 2.0 to 1.0

Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (d)	1.4 to 1.0	1.4 to 1.0	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (d)	1.1 to 1.0	1.2 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	9.1 to 1.0	9.4 to 1.0	Equal to or less than 7.0 to 1.0
EFH Corp. Senior Secured Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (d)	1.4 to 1.0	1.4 to 1.0	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (d)	1.1 to 1.0	1.2 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	9.1 to 1.0	9.4 to 1.0	Equal to or less than 7.0 to 1.0
EFIH Notes:
General restrictions (non-EFH Corp. payments):
Intermediate Holding fixed charge coverage ratio (c) (e)	4.2 to 1.0	3.9 to 1.0	At least 2.0 to 1.0
General restrictions (EFH Corp. payments):
Intermediate Holding fixed charge coverage ratio (c) (e)	8.2 to 1.0	53.8 to 1.0	At least 2.0 to 1.0
Intermediate Holding leverage ratio	4.4 to 1.0	4.4 to 1.0	Equal to or less than 6.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.5 to 1.0	1.5 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	8.0 to 1.0	8.4 to 1.0	Equal to or less than 6.5 to 1.0

(a)

In accordance with the terms of the TCEH Senior Secured Facilities and as the result of the new Sandow and first Oak Grove generating units achieving average capacity factors of greater than or equal to 70% for the three months ended March 31, 2010, the maintenance covenant as of March 31, 2010 includes pro forma twelve months adjusted EBITDA for the units and the proportional amount of outstanding debt under the Delayed Draw Term Loan (see Note 6 to Financial Statements) applicable to the two units.

(b)	Threshold level decreased to a maximum of 7.00 to 1.00 effective March 31, 2010 and will further decrease to a maximum of 6.75 to 1.00 effective December 31, 2010. Calculation excludes debt that ranks junior to the TCEH Senior Secured Facilities.

(c)

Although Intermediate Holding currently meets the fixed charge coverage ratio threshold applicable to certain covenants contained in the indenture governing the EFIH Notes, Intermediate Holding’s ability to use such thresholds to incur debt or make restricted payments/investments is currently limited by the covenants contained in the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes.

(d)	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.

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

Credit Ratings — The issuer credit ratings as of April 1, 2010 for EFH Corp. and its subsidiaries, except for Oncor, are B-, Caa1 and B- by S&P, Moody’s and Fitch, respectively. The issuer credit ratings, as of April 1, 2010, for Oncor are BBB+ and BBB- by S&P and Fitch, respectively.

Additionally, the rating agencies assign credit ratings on certain of our and our affiliates’ debt securities. The credit ratings assigned for these debt securities as of April 1, 2010 are presented below:


	S&P	Moody’s	Fitch
EFH Corp. (Senior Secured) (a)	B+	Caa3	B+
EFH Corp. (Senior Unsecured) (b)	B-	Caa3	B
EFH Corp. (Unsecured)	CCC	Caa3	CCC
Intermediate Holding (Senior Secured)	B+	Caa3	B+
EFC Holdings (Senior Unsecured)	CCC	Caa3	CCC
TCEH (Senior Secured)	B+	B1	B+
TCEH (Senior Unsecured) (c)	CCC	Caa2	B-
TCEH (Unsecured)	CCC	Caa3	CCC
Oncor (Senior Secured) (d)	BBB+	Baa1	BBB
Oncor (Senior Unsecured) (d)	BBB+	Baa1	BBB-

(a)

EFH Corp. 9.75% Notes and EFH Corp. 10% Notes.

(b)

EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes.

(c)

TCEH 10.25% Notes and TCEH Toggle Notes.

(d)

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

In April 2010, Fitch downgraded the issuer default ratings of EFH Corp., Intermediate Holding, EFC Holdings and TCEH to B- from B and maintained a “negative” outlook. Additionally, Fitch downgraded its ratings of the TCEH Senior Secured Facilities two notches to B+ from BB and the TCEH senior unsecured notes to B- from B. Ratings for Oncor were unaffected by this action. S&P’s and Moody’s ratings outlook for EFH Corp. and its subsidiaries, except Oncor, remains “negative.” All three agencies’ 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, 2010, counterparties to those contracts could have required TCEH to post up to an aggregate of $39 million in additional collateral. This amount largely represents the below market terms of these contracts as of March 31, 2010; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of March 31, 2010, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $30 million, with $16 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, 2010, TCEH posted letters of credit in the amount of $84 million, which are subject to adjustments. See “Regulation and Rates – Certification of REPs.”

The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $650 million to $850 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 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 $44 million as of March 31, 2010 (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 rating agencies downgrade Oncor’s credit ratings below investment grade.

Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 5 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 of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the sale of receivables program and hedging obligations, 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 will allow the lenders to accelerate the maturity of outstanding balances ($21.606 billion at March 31, 2010) under such facilities.

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 or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Senior Notes.

Under the terms of a TCEH rail car lease, which had approximately $46 million in remaining lease payments as of March 31, 2010 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Under the terms of a TCEH rail car lease, which had approximately $52 million in remaining lease payments as of March 31, 2010 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are 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 indentures governing the EFH Corp. Senior Notes and Senior Secured Notes contain a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Senior Notes and Senior Secured Notes.

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

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, 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 $1.320 billion at March 31, 2010 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 ($756 million at March 31, 2010) under such facility to be accelerated.

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

Guarantees — See Note 7 to Financial Statements for details of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

See Notes 3 and 7 to Financial Statements regarding VIEs and guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 7 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.

REGULATION AND RATES

Regulatory Investigations and Reviews

See Note 7 to Financial Statements.

Certification of REPs

In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the new financial requirements, TXU Energy filed an amended certification, which became effective in March 2010. As a result, TCEH posted letters of credit in March 2010 totaling $84 million with the PUCT securing its payment obligations to TDUs, and is no longer required to reserve liquidity for such purposes. Liquidity reserved at December 31, 2009 totaled $228 million.

Wholesale Market Design – Nodal Market

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. The implementation of a nodal market is scheduled for December 2010. We cannot predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results.

Oncor Matters with the PUCT

Stipulation Approved by the PUCT — In April 2008, the PUCT entered an order, which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings of a Merger-related Joint Report and Application with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010. Oncor was named a defendant and intends to vigorously defend the appeal. Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order with respect to the rate review in August 2009 as discussed in the 2009 Form 10-K.

Transmission Rates (PUCT Docket No. 37882) — In order to recover increases in its transmission costs, including incremental fees paid to other transmission service providers due to an increase in their rates, 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 2010, an application was filed to increase the TCRF, which was administratively approved in February 2010 and became effective March 1, 2010. This application is expected to increase annualized revenues by $13 million.

Proposed PUCT Rulemaking — The PUCT has published proposed rule changes in two proceedings that would impact transmission rates. The first proceeding (PUCT Project No. 37909) proposes changes to the TCRF rule to allow for more complete cost recovery of wholesale transmission charges incurred by distribution service providers. Currently, increased wholesale transmission charges are recoverable by distribution service providers, effective with the March 1 and September 1 TCRF updates, but distribution service providers cannot recover increased charges incurred prior to such updates. If the rule is approved as proposed, TCRF filings would still be effective March 1 and September 1, but distribution service providers would be allowed to include wholesale transmission charges based on the effective date of the wholesale transmission rate changes. The second proceeding (PUCT Project No. 37519) proposes changes to the wholesale transmission rules to allow transmission service providers to update their wholesale transmission rates twice in a calendar year, as compared to once per year under the current rules, providing more timely recovery of incremental capital investment. Other changes included in this proposal would (i) require each transmission service provider to file a rate case no later than after its sixth interim rate update, (ii) require the PUCT to consider the effects of reduced regulatory lag when setting rates in the next full rate case and (iii) provide for administrative approval of uncontested interim wholesale transmission rate applications. After consideration of comments filed by interested parties, the PUCT will consider proposals for adoption in these two rulemaking proceedings. Oncor cannot predict when the PUCT would consider any such proposals for adoption.

Application for 2011 Energy Efficiency Cost Recovery Factor (PUCT Docket No. 38217) — On April 30, 2010, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2011. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. The requested 2011 EECRF is $51 million, as compared to $54 million established for 2010, and would result in a $0.91 per month charge for residential customers, as compared to the 2010 residential charge of $0.89 per month. As allowed by the rule, the 2011 EECRF is designed to recover $45 million of Oncor’s costs for the 2011 programs, to be reduced by $5 million for the over-recovery of 2009 program costs, plus a performance bonus to Oncor of $11 million based on 2009 results.

Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT awarded approximately $1.3 billion of CREZ construction projects to Oncor (PUCT Docket Nos. 35665 and 37902). The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. A written order reflecting the PUCT’s decision was entered in March 2009, and an order on rehearing was issued by the PUCT in May 2009. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT in April 2008. Based on the selection of final routes for the three default and nine priority projects and identification of additional costs not included in the original ERCOT estimate (e.g., wind interconnection facilities and required modifications to existing facilities), Oncor estimates that the cost of these projects will exceed ERCOT estimates by approximately $220 million. Final routes for five subsequent projects have not yet been selected by the PUCT. As of March 31, 2010, Oncor’s cumulative CREZ-related capital expenditures totaled approximately $159 million, including approximately $45 million during the three months ended March 31, 2010. It is expected that the necessary permitting actions and other requirements and all construction activities for Oncor’s CREZ construction projects will be completed by the end of 2013.

In October 2009, the PUCT initiated a proceeding to determine whether there is sufficient financial commitment from generators of renewable energy to grant Certificates of Convenience and Necessity (CCNs) for transmission facilities located in two areas in the panhandle of Texas designated as CREZs. If the PUCT determines that there is not sufficient financial commitment from the generators for either CREZ, the PUCT may take action, including delaying the filing of CREZ CCN applications until such time as the PUCT finds sufficient financial commitment for that CREZ in accordance with the financial commitment provisions of the PUCT’s rules. Three of the CREZ transmission projects awarded to Oncor are located in the two CREZs that are the subject of the proceeding. The estimated cost of these three transmission projects is approximately $380 million. The PUCT held a hearing in this proceeding in January 2010. Oncor expects the PUCT to issue an order concluding this proceeding in the second quarter of 2010.

In July 2009, the City of Garland, Texas filed an Original Petition and Application for Stay and Injunction in the 200^th District Court of Travis County, Texas seeking judicial review and a stay of the PUCT’s March 2009 written order selecting transmission service providers (including Oncor) to build CREZ transmission facilities. In January 2010, the district court issued an order reversing the PUCT’s order and remanding it to the PUCT for action consistent with the court’s opinion. The district court order did not contain a stay or injunction and severed the City of Garland’s requests for declaratory and injunctive relief. In February 2010, the PUCT issued orders that severed certain of the CREZ transmission projects awarded to Oncor and others from its consideration of the remand of the written order (PUCT Docket No. 37928) and suspended the schedule sequencing CREZ projects subsequent to CREZ priority projects (PUCT Docket No. 36802). On April 5, 2010, the PUCT issued an order in Docket No. 36802 establishing the sequencing for CREZ projects subsequent to priority projects, which did not affect Oncor other than resulting in the schedule for Oncor to file CCN applications for its five CREZ subsequent projects between May and September 2010 as compared to the original March to May 2010 timeframe. That order excludes two CREZ subsequent projects that had been originally awarded to Lower Colorado River Authority, and the PUCT has opened Docket No. 38045 to award these two projects.

Sunset Review — PURA, the PUCT and the RRC will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT or the RRC), along with an evaluation of the advisability of any changes to that agency’s authorizing legislation (PURA). A Sunset staff report on the PUCT was issued in April 2010, and the related Sunset public meeting is scheduled for May 2010. The April 2010 Sunset staff report offers various suggestions for consideration by the Sunset Commission, including statutory revisions that would give the PUCT additional enforcement power. A Sunset staff report on the RRC is scheduled to be issued in October 2010, and the related Sunset public meeting is scheduled for November 2010. We cannot predict the outcome of the sunset review process.

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.

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.

Risk Oversight

TCEH manages the commodity price, counterparty credit and commodity-related operational risk related to the unregulated energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (VaR) methodologies. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, validation of transaction capture, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

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

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.

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, 2010		Year Ended December 31, 2009
Month-end average Trading VaR:	$	3	$	4

Month-end high Trading VaR:	$	4	$	7

Month-end low Trading VaR:	$	3	$	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, 2010		Year Ended December 31, 2009
Month-end average MtM VaR:	$	491	$	1,050

Month-end high MtM VaR:	$	541	$	1,470

Month-end low MtM VaR:	$	420	$	638

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, 2010		Year Ended December 31, 2009
Month-end average EaR:	$	510	$	1,088

Month-end high EaR:	$	607	$	1,511

Month-end low EaR:	$	421	$	676

The decreases in the risk measures (MtM VaR and EaR) above were primarily driven by changes in market volatility and underlying commodity prices.

Interest Rate Risk

As of March 31, 2010, the potential reduction of annual pretax earnings due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $42 million, taking into account the interest rate swaps discussed in Note 6 to Financial Statements.

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 $2.782 billion at March 31, 2010. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of March 31, 2010 include $784 million in retail trade accounts receivable. Cash deposits held as collateral for these receivables totaled $76 million at March 31, 2010. 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.

The remaining credit exposure arises from wholesale energy sales and purchases and hedging and trading activities, including interest rate hedging. Counterparties to these transactions 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, 2010, the exposure to credit risk from these counterparties totaled $1.998 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $259 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.739 billion increased approximately $442 million in the three months ended March 31, 2010, reflecting the increase in derivative assets related to the long-term hedging program due to the decline in forward natural gas prices, partially offset by the return of the $400 million in collateral discussed in Note 11 to Financial Statements.

Of this $1.739 billion net exposure, essentially all 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. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.

The following table presents the distribution of credit exposure as of March 31, 2010 arising from wholesale energy sales and purchases and hedging and trading activities. 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 provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties.


									Gross Exposure by Maturity
	Exposure Before Credit Collateral			Credit Collateral		Net Exposure			2 years or less		Between 2-5 years		Greater than 5 years		Total
Investment grade	$	1,988		$	252	$	1,736		$	1,104	$	884	$	—	$	1,988
Noninvestment grade		10			7		3			9		1		—		10

Totals	$	1,998		$	259	$	1,739		$	1,113	$	885	$	—	$	1,998


Investment grade		99.5	%				99.8	%
Noninvestment grade		0.5	%				0.2	%

In addition to the exposures in the table above, contracts classified as “normal” purchase or sale and non-derivative contractual commitments 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.

Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented 49%, 29% and 13% of the net $1.739 billion exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of 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, essentially all of the transaction volumes are with counterparties with an A credit rating or better. However, there is 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 the various ongoing risk management measures described above.

Credit Exposure — Oncor — Oncor’s assets subject to credit risk include accounts receivable from electricity transmission and distribution services. This exposure, which totaled $256 million at March 31, 2010 excluding accounts receivable from subsidiaries of EFH Corp., consists almost entirely of noninvestment grade trade accounts receivable. Of this amount, $190 million represents trade accounts receivable from REPs. Oncor has a customer with subsidiaries that collectively represent 13% of the total exposure. No other nonaffiliated parties represent 10% or more of the total exposure. These amounts are not included in EFH Corp.’s balance sheet or in the total above due to deconsolidation of Oncor as discussed in Note 1 to Financial Statements.

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 “intends,” “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “should,” “projection,” “target,” “goal,” “objective” 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 Item 1A, “Risk Factors” 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;

•

permitted capital structure;

•

industry, market and rate structure;

•

purchased power and recovery of investments;

•

operations of nuclear generating facilities;

•

operations of fossil-fueled generating facilities;

•

operations of mines;

•

acquisitions and disposal of assets and facilities;

•

development, construction and operation of facilities;

•

decommissioning costs;

•

present or prospective wholesale and retail competition;

•

changes in tax laws and policies, and

•

changes in and compliance with environmental and safety laws and policies, including climate change initiatives;

•

legal and administrative proceedings and settlements;

•

general industry trends;

•

economic conditions, including the current recessionary environment;

•

our ability to attract and retain profitable customers;

•

our ability to profitably serve our customers;

•

restrictions on competitive retail pricing;

•

changes in wholesale electricity prices or energy commodity prices;

•

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

•

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

•

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

•

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

•

unanticipated population growth or decline, or 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 and the potential impact of disruptions in US credit markets;

•

access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets;

•

financial restrictions placed on us by our credit facilities and indentures governing our debt instruments;

•

our ability to generate sufficient cash flow to make interest payments on our debt instruments;

•

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;

•

changes in electricity transmission that allow additional electricity generation to compete with our generation assets;

•

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;

•

hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;

•

significant changes in critical accounting policies;

•

actions by credit rating agencies;

•

our ability to effectively execute our operational strategy;

•

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, adverse judicial rulings, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, force majeure events 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, except as may be required by law, we undertake 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. You should not unduly rely on such forward-looking statements.

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, the PUCT and NYMEX. 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.

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.

PART II. OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

Reference is made to the discussion in Note 7 to Financial Statements regarding legal proceedings.

Item 1A.

RISK FACTORS

There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the 2009 Form 10-K except for the risk factor discussed below and the information disclosed elsewhere in this Form 10-Q that provides factual updates to risk factors contained in the 2009 Form 10-K.

Our use of assets as collateral for hedging arrangements could be materially impacted if certain proposed legislation regarding the regulation of over-the-counter financial derivatives were to be enacted and be applicable to us.

The Obama Administration has proposed financial market reforms with respect to the currently unregulated Over-the-Counter (OTC) financial derivatives market. As a result, the US House of Representatives has approved a bill to regulate OTC derivatives and both the Senate Agriculture Committee and the Senate Banking Committee have also approved bills. As currently proposed, each bill (i) requires certain entities to clear through exchanges certain derivatives that are currently traded on the bilateral market, which would likely result in those entities being required to post cash collateral in future transactions and (ii) provides for grandfathering of existing OTC derivatives. We have entered into a substantial number of asset-backed OTC derivatives to hedge risks associated with commodity and interest rate exposure. If any final bill that becomes law requires us to clear such transactions, we would likely be precluded from using our noncash assets (i.e., first lien) as collateral for hedging arrangements. This preclusion would have a material impact on our liquidity. As a result, if applied to our OTC derivatives transactions, legislation that precludes the use of asset-backed transactions would increase our costs of entering into OTC derivatives and could significantly limit our ability to enter into OTC derivatives and hedge our commodity and interest rate risks. We cannot predict whether or when final legislation will be enacted or whether under any final legislation we will be required to clear OTC derivatives through exchanges.

Item 6.

Exhibits

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


Exhibits	Previously Filed With File Number*	As Exhibit

(4)	Instruments Defining the Rights of Security Holders, Including Indentures.
	Energy Future Holdings Corp.

4(a)	1-12833 Form 8-K (filed January 19, 2010)	4.1	–	Indenture, dated as of January 12, 2010, among Energy Future Holdings Corp., the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020 (including form of Senior Secured Notes due 2020)

4(b)	333-165860 Form S-3 (filed April 1, 2010)	4(j)	–	First Supplemental Indenture, dated as of March 16, 2010, to Indenture, dated as of January 12, 2010, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020

4(c)	1-12833 Form 8-K (filed January 19, 2010)	4.2	–	Registration Rights Agreement, dated January 12, 2010, among Energy Future Holdings Corp., the Guarantors named therein and the initial purchasers named therein, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020

4(d)	333-165860 Form S-3 (filed April 1, 2010)	4(l)	–	Registration Rights Letter Agreement, dated March 16, 2010, among Energy Future Holdings Corp., the Guarantors named therein and the initial purchasers named therein, relating to Energy Future Holdings Corp.’s 10.000% Senior Secured Notes due 2020

31	Rule 13a – 14(a)/15d – 14(a) Certifications.

31(a)			–	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b)			–	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications.

32(a)			–	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(b)			–	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


(99)	Additional Exhibits.

99(a)		–	Condensed Statements of Consolidated Income – Twelve Months Ended March 31, 2010.

99(b)		–	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the three and twelve months ended March 31, 2010 and 2009.

99(c)		–	TCEH Consolidated Adjusted EBITDA reconciliation for the three and twelve months ended March 31, 2010 and 2009.

*	Incorporated herein by reference.

SIGNATURE

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


Energy Future Holdings Corp.

By:		/s/ Stan Szlauderbach
Name:		Stan Szlauderbach
Title:		Senior Vice President and Controller (Principal Accounting Officer)

Date: May 3, 2010

Energy Future Holdings Corp /TX/ - FORM 10-Q - May 3, 2010

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Energy Future Holdings Corp /TX/ Reports