Filed Pursuant to Rule 424(b)(3)
Registration Nos. 333-157057, 333-157057-01 to 333-157057-44

TEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY LLC

TCEH FINANCE, INC.

SUPPLEMENT NO. 6 TO

MARKET MAKING PROSPECTUS DATED

JUNE 16, 2009

THE DATE OF THIS SUPPLEMENT IS OCTOBER 30, 2009

On October 30, 2009, the registrant parent guarantor, Energy Future Competitive Holdings Company, filed

the attached Quarterly Report on Form 10-Q with the Securities and Exchange Commission.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009

— OR —

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

Commission File Number 333-153529-02

Energy Future Competitive Holdings Company

(Exact name of registrant as specified in its charter)

Texas	75-1837355
(State of incorporation)	(I.R.S. Employer Identification No.)

1601 Bryan Street, Dallas, TX 75201-3411	(214) 812-4600
(Address of principal executive offices)(Zip Code)	(Registrant’s telephone number)

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

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

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

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

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

Common Stock Outstanding at October 29, 2009: 2,062,768 Class A shares, without par value and 39,192,594 Class B shares, without par value.

Energy Future Competitive Holdings meets the conditions set forth in General Instructions (H)(1)(a) and (b) of Form 10-Q and is therefore filing this report with the reduced disclosure format.

TABLE OF CONTENTS

		PAGE
GLOSSARY		ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Statements of Consolidated Income (Loss) – Three and Nine Months Ended September 30, 2009 and 2008	1
	Condensed Statements of Consolidated Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2009 and 2008	2
	Condensed Statements of Consolidated Cash Flows – Nine Months Ended September 30, 2009 and 2008	3
	Condensed Consolidated Balance Sheets – September 30, 2009 and December 31, 2008	4
	Notes to Condensed Consolidated Financial Statements	5
	Report of Independent Registered Public Accounting Firm	44
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	70
Item 4.	Controls and Procedures	76
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	76
Item 1A.	Risk Factors	76
Item 6.	Exhibits	77

Energy Future Competitive Holdings Company’s (EFC Holdings) 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 Energy Future Holdings 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 Energy Future Holdings 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 EFC Holdings 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 EFC Holdings and its subsidiaries occasionally make references to EFC Holdings (or “the company”), TCEH, TXU Energy or Luminant when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or any other affiliate.

i

GLOSSARY

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

2008 Form 10-K	EFC Holdings’ Annual Report on Form 10-K for the year ended December 31, 2008
Adjusted EBITDA	Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain debt arrangements of TCEH and EFH Corp. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. EFC Holdings is providing TCEH’s and EFH Corp.’s 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 the debt arrangements. EFC Holdings does 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, EFC Holdings does 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, EFC Holdings’ presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
DOE	US Department of Energy
EBITDA	Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.
EFC Holdings	Refers to Energy Future Competitive Holdings Company, a direct subsidiary of EFH Corp. and the direct parent of TCEH, and/or its consolidated subsidiaries, depending on context.
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. Cash-Pay Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).
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

ii

FERC	US Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
GAAP	generally accepted accounting principles
GWh	gigawatt-hours
Intermediate Holding	Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.
kWh	kilowatt-hours
LIBOR	London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.
Luminant	Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. The market heat rate is based on the price offer of the marginal supplier in Texas (generally natural gas plants) in generating electricity and is calculated by dividing the wholesale market price of electricity by the market price of natural gas.
Merger	The transaction referred to in Merger Agreement (Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.) that was completed on October 10, 2007.
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, that is consolidated as a variable interest entity under consolidations accounting standards.
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act

iii

Purchase accounting	The purchase method of accounting for a business combination as prescribed by 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.
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
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, wholesale and retail energy markets and development and construction activities. Its major subsidiaries include Luminant and TXU Energy.
TCEH Finance	Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.
TCEH Senior Notes	Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes Series B due November 1, 2015 (collectively, TCEH Cash-Pay 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 4 to Financial Statements for details of these facilities.
TCEQ	Texas Commission on Environmental Quality
Texas Holdings	Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.
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.
US	United States of America

iv

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Operating revenues	$	2,433		$	3,258		$	6,144		$	7,809
Fuel, purchased power costs and delivery fees		(1,187	)		(1,923	)		(2,987	)		(4,646	)
Net gain (loss) from commodity hedging and trading activities		123			6,045			1,003			(248	)
Operating costs		(161	)		(158	)		(504	)		(501	)
Depreciation and amortization		(303	)		(296	)		(862	)		(827	)
Selling, general and administrative expenses		(192	)		(172	)		(555	)		(495	)
Franchise and revenue-based taxes		(27	)		(26	)		(74	)		(73	)
Impairment of goodwill (Note 2)		—			—			(70	)		—
Other income (Note 12)		33			2			38			8
Other deductions (Note 12)		(6	)		(531	)		(19	)		(550	)
Interest income		21			20			39			44
Interest expense and related charges (Note 12)		(842	)		(647	)		(1,547	)		(1,957	)
Income (loss) before income taxes		(108	)		5,572			606			(1,436	)
Income tax (expense) benefit		36			(1,986	)		(259	)		493
Net income (loss)		(72	)		3,586			347			(943	)
Net (income) loss attributable to noncontrolling interests		—			—			—			—
Net income (loss) attributable to EFC Holdings	$	(72	)	$	3,586		$	347		$	(943	)

See Notes to Financial Statements.

1

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Net income (loss)	$	(72	)	$	3,586		$	347		$	(943	)
Other comprehensive income (loss), net of tax effects:
Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of $2, $75, $11 and $98)		(4	)		(139	)		(20	)		(182	)
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $21, $22, $53 and $45)		41			41			99			83
Total adjustments to net income (loss)		37			(98	)		79			(99	)
Comprehensive income (loss)		(35	)		3,488			426			(1,042	)
Comprehensive (income) loss attributable to noncontrolling interests		—			—			—			—
Comprehensive income (loss) attributable to EFC Holdings	$	(35	)	$	3,488		$	426		$	(1,042	)

See Notes to Financial Statements.

2

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(millions of dollars)

	Nine Months Ended September 30,
	2009			2008
Cash flows — operating activities:
Net income (loss)	$	347		$	(943	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization		1,307			1,162
Deferred income tax expense (benefit) — net		136			(388	)
Noncash interest expense related to pushed down debt of Parent (Note 4)		131			126
Impairment of goodwill (Note 2)		70			—
Impairment of emission allowances intangible assets		—			501
Charge related to Lehman bankruptcy (Note 12)		—			26
Unrealized net (gains) losses from mark-to-market valuations of commodity positions		(713	)		221
Unrealized net gains from mark-to-market valuations of interest rate swaps		(527	)		(36	)
Bad debt expense		87			57
Stock-based incentive compensation expense		5			7
Reversal of use tax accrual (Note 12)		(23	)		—
Other net		6			28
Changes in operating assets and liabilities:
Margin deposits — net		260			(236	)
Other operating assets and liabilities		385			340
Cash provided by operating activities		1,471			865
Cash flows — financing activities:
Issuances of long-term debt:
Pollution control revenue bonds		—			242
Other long-term debt (Note 4)		522			1,035
Repayments/repurchases of long-term debt:
Pollution control revenue bonds		—			(242	)
Other long-term debt (Note 4)		(217	)		(157	)
Increase in short-term borrowings (Note 4)		—			2,032
Decrease in income tax-related note payable to Oncor		(26	)		(25	)
Contributions from noncontrolling interests (Note 6)		42			—
Debt discount, financing and reacquisition expenses		(35	)		(4	)
Other — net		1			33
Cash provided by financing activities		287			2,914
Cash flows — investing activities:
Net loans to affiliates		(528	)		(381	)
Capital expenditures		(1,106	)		(1,402	)
Nuclear fuel purchases		(157	)		(112	)
Money market fund redemptions (investments)		142			(242	)
Net proceeds from sale of controlling interest in natural gas gathering pipeline business		40			—
Reduction of restricted cash related to letter of credit facility (Note 4)		115			—
Reduction of restricted cash related to pollution control revenue bonds		—			29
Transfer of cash collateral from (to) custodian account		3			(20	)
Proceeds from sales of environmental allowances and credits		22			30
Purchases of environmental allowances and credits		(23	)		(18	)
Proceeds from sales of nuclear decommissioning trust fund securities		2,972			747
Investments in nuclear decommissioning trust fund securities		(2,983	)		(758	)
Other		20			5
Cash used in investing activities		(1,483	)		(2,122	)
Net change in cash and cash equivalents		275			1,657
Cash and cash equivalents — beginning balance		479			215
Cash and cash equivalents — ending balance	$	754		$	1,872

See Notes to Financial Statements.

3

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)

	September 30, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	754		$	479
Investments held in money market fund		—			142
Restricted cash (Note 12)		1			4
Trade accounts receivable — net (Note 3)		751			994
Notes receivable from parent (Note 11)		1,112			584
Inventories (Note 12)		403			361
Commodity and other derivative contractual assets (Note 7)		2,537			2,391
Accumulated deferred income taxes		83			21
Margin deposits related to commodity positions		158			439
Other current assets		49			86
Total current assets		5,848			5,501
Restricted cash (Note 12)		1,135			1,250
Investments (Note 12)		581			484
Property, plant and equipment — net (Note 12)		20,980			20,902
Goodwill (Note 2)		10,252			10,322
Intangible assets — net (Note 2)		2,658			2,774
Commodity and other derivative contractual assets (Note 7)		1,153			962
Other noncurrent assets, principally unamortized debt issuance costs		722			805
Total assets	$	43,329		$	43,000
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 4)	$	900		$	900
Long-term debt due currently (Note 4)		207			269
Trade accounts payable — nonaffiliates		589			1,000
Trade accounts and other payable to affiliates		232			171
Commodity and other derivative contractual liabilities (Note 7)		2,535			2,730
Margin deposits related to commodity positions		504			525
Accrued income taxes payable to parent (Note 11)		140			33
Accrued taxes other than income		95			70
Accrued interest		603			354
Other current liabilities		323			275
Total current liabilities		6,128			6,327
Accumulated deferred income taxes		5,381			5,242
Commodity and other derivative contractual liabilities (Note 7)		1,343			2,095
Notes or other liabilities due affiliates (Note 11)		227			254
Long-term debt, less amounts due currently (Note 4)		32,123			31,556
Other noncurrent liabilities and deferred credits (Note 12)		2,644			2,528
Total liabilities		47,846			48,002
Commitments and Contingencies (Note 5)
Equity (Note 6):
EFC Holdings shareholders’ equity		(4,559	)		(5,002	)
Noncontrolling interests in subsidiaries		42			—
Total equity		(4,517	)		(5,002	)
Total liabilities and equity	$	43,329		$	43,000

See Notes to Financial Statements.

4

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFC Holdings is a subsidiary of EFH Corp. and is a Dallas-based holding company that conducts its operations principally through its wholly-owned subsidiary, TCEH. TCEH is a Dallas-based holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Commodity risk management and allocation of financial resources are performed at the consolidated level; therefore, there are no reportable business segments.

See “Glossary” for definition of terms and abbreviations.

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in the 2008 Form 10-K, with the exception of the adoption of new accounting and disclosure guidance related to derivative instruments and hedging activities, subsequent events and reporting of fair value as discussed below. All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in the 2008 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequent events have been evaluated through October 29, 2009, the date these condensed consolidated financial statements were issued.

Use of Estimates

Preparation of the financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.

Changes in Accounting Standards

In August 2009, the FASB issued guidance on measuring fair value of liabilities, which provides clarification of fair value measurement when there is limited or no observable data available. This new guidance is effective for periods beginning October 1, 2009. EFC Holdings is evaluating the impact of this new guidance, but currently does not expect a material effect on its financial statements.

In June 2009, the FASB issued “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles,” which establishes the FASB Accounting Standards Codification™ (Codification) as the source of authoritative US GAAP recognized by the FASB to be applied to nongovernmental entities. The Codification was effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of the Codification did not affect reported results of operations, financial condition or cash flows. EFC Holdings implemented the Codification in this Form 10-Q.

5

In June 2009, the FASB issued new guidance that (i) changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated and (ii) requires additional disclosures. This new guidance is effective for periods beginning after November 15, 2009. EFC Holdings is evaluating the impact of this new guidance, including the impact to its sale of receivable program discussed in Note 3 and immediately below.

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. This new guidance is effective in the first quarter of 2010. EFC Holdings continues to evaluate the impact of this new guidance on its financial statements and footnote disclosures; however, it currently expects that its accounts receivable securitization program discussed in Note 3 will no longer be accounted for as a sale of accounts receivable as a result of the guidance, and the funding under the program will be reported as short-term borrowings. This new guidance will not impact the covenant-related ratio calculations in EFC Holdings’ debt agreements.

In May 2009, the FASB issued new guidance related to subsequent events that requires disclosure of the date through which EFC Holdings has evaluated subsequent events related to the financial statements being issued and the basis for that date. This guidance was effective for interim and annual reporting periods ending after June 15, 2009. EFC Holdings’ adoption of this guidance as of April 1, 2009 did not affect reported results of operations, financial condition or cash flows, and the required disclosure is provided above in “Basis of Presentation.”

In April 2009, the FASB issued new guidance regarding determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly. This guidance was effective for interim reporting periods ending after June 15, 2009, and EFC Holdings adopted it as of April 1, 2009. This guidance did not change EFC Holdings’ fair value measurement techniques. However, this guidance requires disclosures of additional detail of securities held in EFC Holdings’ nuclear decommissioning trust that are provided in Notes 8 and 12.

In April 2009, the FASB issued new guidance regarding the recognition and presentation of other-than-temporary impairments, which changed the guidance for recording impairment of investments in debt securities. This guidance was effective for interim and annual reporting periods ending after June 15, 2009, and is expected to affect many utility companies that hold debt securities in nuclear decommissioning trust funds. However, EFC Holdings’ adoption as of April 1, 2009 did not affect the accounting for its nuclear decommissioning trust fund because the trust balance is reported at fair value, with changes in fair value of the trust resulting in changes in Oncor’s regulatory asset or liability related to the decommissioning cost. This new guidance also requires the disclosure of information about the fair value of the investments for interim reporting as provided in Note 12.

In April 2009, the FASB issued new guidance requiring the disclosure of summarized financial information about the fair value of financial instruments for interim reporting. This new guidance was effective for interim reporting periods ending after June 15, 2009, and EFC Holdings adopted it as of April 1, 2009. As this new guidance provides only disclosure requirements, the adoption did not have any effect on reported results of operations, financial condition or cash flows. The disclosures are provided in Note 9.

In December 2008, the FASB issued new guidance for employers’ disclosures about postretirement benefit plan assets. This new guidance provides enhanced disclosures regarding how investment allocation decisions are made and certain aspects of fair value measurements on plan assets. The required disclosures are intended to provide transparency related to the types of assets and associated risks in an employer’s defined benefit pension or other postretirement employee benefits plan and events in the economy and markets that could have a significant effect on the value of plan assets. These new disclosure requirements are effective for fiscal years ending after December 15, 2009. As this new guidance provides only disclosure requirements, the adoption will not have any effect on reported results of operations, financial condition or cash flows.

6

In March 2008, the FASB issued amended disclosure guidance for derivative instruments and hedging activities. This amended guidance enhances required disclosures regarding derivatives and hedging activities to enable investors to better understand their effects on an entity’s financial position, financial performance and cash flows. This guidance was effective with reporting for the three months ended March 31, 2009. As this guidance provides only disclosure requirements, the adoption did not have any effect on reported results of operations or financial condition. The disclosures are provided in Note 7.

In December 2007, the FASB issued amended guidance for accounting for noncontrolling interests in consolidated financial statements effective for fiscal years beginning on or after December 15, 2008. This amended guidance requires noncontrolling interests in subsidiaries initially to be measured at fair value and classified as a separate component of equity. Effective January 2009, EFC Holdings classified the noncontrolling interests created as part of the nuclear generation development joint venture formed in the first quarter of 2009 as a separate component of equity in the balance sheet, and reported consolidated net income (loss) includes the net income attributable to noncontrolling interests, the amount of which was immaterial in the period from the formation of the joint venture in January 2009 through September 30, 2009.

2. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Reported goodwill totaled $10.25 billion and $10.32 billion as of September 30, 2009 and December 31, 2008, respectively.

In the first quarter of 2009, EFC Holdings recorded a $70 million goodwill impairment charge. This charge resulted from the completion of fair value calculations supporting the initial $8.0 billion goodwill impairment charge that was recorded in the fourth quarter of 2008. The impairment charge primarily reflected the dislocation in the capital markets during the fourth quarter of 2008 that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies. The impairment determination involved significant assumptions and judgments in estimating EFC Holdings’ enterprise value and the fair values of its assets and liabilities. There have been no other goodwill impairments recorded since the Merger.

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

Identifiable Intangible Assets

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

	As of September 30, 2009						As of December 31, 2008
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	194	$	269	$	463	$	130	$	333
Favorable purchase and sales contracts		700		340		360		700		249		451
Capitalized in-service software		179		23		156		48		13		35
Environmental allowances and credits		988		187		801		994		121		873
Mining development costs		19		4		15		19		2		17
Total intangible assets subject to amortization	$	2,349	$	748		1,601	$	2,224	$	515		1,709
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization)						102						110
Total intangible assets					$	2,658					$	2,774

7

Amortization expense related to intangible assets consisted of:

	Three Months Ended September 30,				Nine Months Ended September 30,
Intangible Asset (Income Statement line)	2009		2008		2009		2008
Retail customer relationship (Depreciation and amortization)	$	21	$	13	$	64	$	39
Favorable purchase and sales contracts (Operating revenues/fuel, purchased power costs and delivery fees)		18		9		91		115
Capitalized in-service software (Depreciation and amortization)		5		2		11		8
Environmental allowances and credits (Fuel, purchased power costs and delivery fees)		25		28		66		77
Mining development costs (Depreciation and amortization)		1		—		2		—
Total amortization expense	$	70	$	52	$	234	$	239

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

Year	Amount
2009	$	323
2010		228
2011		174
2012		138
2013		122

3. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables

TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards (see Note 1 for discussion of a new accounting standard effective in the first quarter of 2010). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is a special purpose entity created for the 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 special purpose entities established by financial institutions (the funding entities).

Program funding totaled $700 million at September 30, 2009, the maximum amount currently available under the accounts receivable securitization program.

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 subordinated notes payable to the originators for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is reported in trade accounts receivable, totaled $489 million and $268 million at September 30, 2009 and December 31, 2008, respectively.

8

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, which are also referred to as losses on sale of the receivables under transfers and servicing accounting standards, consist primarily of interest costs on the underlying financing. The discount also funds a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company, a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Program fees	$	2		$	7		$	9		$	18
Program fees as a percentage of average funding (annualized)		1.3	%		4.2	%		2.4	%		5.2	%

The trade accounts receivable balance reported in the September 30, 2009 consolidated balance sheet has been reduced by $1.189 billion face amount of retail accounts receivable sold to TXU Receivables Company, partially offset by the inclusion of $489 million of subordinated notes receivable from TXU Receivables Company. Funding under the program increased $284 million and $337 million for the nine month periods ending September 30, 2009 and 2008, respectively. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.

Activities of TXU Receivables Company were as follows:

	Nine Months Ended September 30,
	2009			2008
Cash collections on accounts receivable	$	4,660		$	4,881
Face amount of new receivables purchased		(5,165	)		(5,263	)
Discount from face amount of purchased receivables (to fund fees paid)		11			22
Program fees paid to funding entities		(9	)		(18	)
Servicing fees paid to EFH Corp. subsidiary for recordkeeping and collection services		(2	)		(3	)
Increase in subordinated notes payable		221			44
Operating cash flows provided to originator under the program	$	(284	)	$	(337	)

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 the EFH Corp. subsidiary acting as collection agent defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than the EFH Corp. subsidiary, any parent guarantor of 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 September 30, 2009, there were no such events of termination.

Upon termination of the program, cash flows would be delayed as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. The level of cash flows would normalize in approximately 16 to 30 days.

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

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Trade Accounts Receivable

	September 30, 2009			December 31, 2008
Gross wholesale and retail trade accounts receivable	$	1,535		$	1,474
Retail accounts receivable sold to TXU Receivables Company		(1,189	)		(684	)
Subordinated notes receivable from TXU Receivables Company		489			268
Allowance for uncollectible accounts		(84	)		(64	)
Trade accounts receivable — reported in balance sheet	$	751		$	994

Gross trade accounts receivable at September 30, 2009 and December 31, 2008 included unbilled revenues of $449 million and $427 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Nine Months Ended September 30,
	2009			2008
Allowance for uncollectible accounts receivable as of beginning of period	$	64		$	24
Increase for bad debt expense		87			57
Decrease for account write-offs		(67	)		(46	)
Charge related to Lehman bankruptcy		—			26
Allowance for uncollectible accounts receivable as of end of period	$	84		$	61

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4. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At September 30, 2009, EFC Holdings and its subsidiaries had outstanding short-term borrowings of $900 million at a weighted average interest rate of 3.79%, excluding certain customary fees, at the end of the period. At December 31, 2008, EFC Holdings and its subsidiaries had outstanding short-term borrowings of $900 million at a weighted average interest rate of 3.95%, excluding certain customary fees, at the end of the period. All short-term borrowings were under the TCEH Revolving Credit Facility.

Credit Facilities

EFC Holdings’ (through TCEH) credit facilities with cash borrowing and/or letter of credit availability at September 30, 2009 are presented below. The facilities are all senior secured facilities.

	Maturity Date	At September 30, 2009
Authorized Borrowers and Facility		Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Delayed Draw Term Loan Facility (a)	October 2014	$	4,100	$	—	$	4,085	$	—
TCEH Revolving Credit Facility (b)	October 2013		2,700		38		900		1,736
TCEH Letter of Credit Facility (c)	October 2014		1,250		—		1,250		—
Subtotal TCEH (d)		$	8,050	$	38	$	6,235	$	1,736
TCEH Commodity Collateral Posting Facility (e)	December 2012		Unlimited	$	—	$	—		Unlimited

(a) Facility was used to fund expenditures for constructing certain new generation facilities and environmental upgrades of existing generation facilities. Availability amount excludes $15 million of commitments from a subsidiary of Lehman Brothers Holding Inc. (such subsidiary, Lehman) that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. Borrowings are classified as long-term debt.

(b) 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 September 30, 2009 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility.

(c) Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the 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 $676 million issued as of September 30, 2009 are supported by the restricted cash, and the remaining letter of credit availability totals $459 million.

(d) Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at September 30, 2009, the total availability under the TCEH credit facilities should be further reduced by $237 million.

(e) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 650 million MMBtu as of September 30, 2009. As of September 30, 2009, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.

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Long-Term Debt

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

	September 30, 2009			December 31, 2008
TCEH
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39		$	39
7.700% Fixed Series 1999A due April 1, 2033		111			111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (a)		16			16
7.700% Fixed Series 1999C due March 1, 2032		50			50
8.250% Fixed Series 2001A due October 1, 2030		71			71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)		217			217
8.250% Fixed Series 2001D-1 due May 1, 2033		171			171
0.450% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.340% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.450% 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)		(150	)		(161	)
Senior Secured Facilities:
3.754% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)		16,121			16,244
3.754% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		4,085			3,562
3.754% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
0.243% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (g)		—			—
Other:
10.25% Fixed Senior Notes due November 1, 2015		3,000			3,000
10.25% Fixed Senior Notes Series B due November 1, 2015		2,000			2,000
10.50 / 11.25% Senior Toggle Notes due November 1, 2016		1,848			1,750
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.100% Promissory Note due January 5, 2009		—			65
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		55			67
Capital lease obligations		158			159
Unamortized fair value discount (d)		(5	)		(6	)
Total TCEH	$	29,902		$	29,470

12

	September 30, 2009			December 31, 2008
EFC Holdings (parent entity)
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	55		$	55
8.254% Fixed Notes due in quarterly installments through December 31, 2021		51			53
1.283% 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
10.875% EFH Corp. Fixed Senior Notes due November 1, 2017 (h)		1,000			1,000
11.25/12.00% EFH Corp. Senior Toggle Notes due November 1, 2017 (h)		1,325			1,250
Unamortized fair value discount (d)		(12	)		(12	)
Total EFC Holdings		2,428			2,355
Total EFC Holdings consolidated		32,330			31,825
Less amount due currently		207			(269	)
Total long-term debt	$	32,123		$	31,556

(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 September 30, 2009. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

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

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

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

(f) Interest rates in effect at September 30, 2009.

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

(h) Represents 50% of the principal amount of EFH Corp. debt guaranteed by EFC Holdings (pushed-down debt) per the discussion below under “Push Down of EFH Corp. Notes.”

Debt-Related Activity in 2009 — Repayments of long-term debt in 2009 totaling $217 million represented principal payments at scheduled maturity dates as well as other repayments totaling $29 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $123 million repaid under the TCEH Initial Term Loan Facility and $65 million of a TCEH promissory note.

Increases in long-term debt during 2009 totaling $522 million consisted of borrowings under the TCEH Delayed Draw Term Loan Facility, which was fully drawn as of July 2009, to fund expenditures related to construction of new generation facilities and environmental upgrades of existing lignite/coal-fueled generation facilities. In addition, long-term debt increased as a result of the issuance of $75 million of EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes) (see “Push Down of EFH Corp. Notes” below) and $98 million of TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes) in lieu of cash interest payments as discussed below.

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

TCEH made its May 2009 interest payment and will make its November 2009 and May 2010 interest payments by using the PIK feature of the TCEH Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the TCEH Toggle Notes by $98 million on May 1, 2009 and will further increase the aggregate principal amount of the TCEH Toggle Notes by approximately $104 million on November 1, 2009 and $110 million on May 1, 2010. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $92 million and will further increase liquidity as of November 1, 2009 and May 1, 2010 by an amount equal to approximately $97 million and approximately $103 million, respectively, with such amounts constituting the amount of cash interest that otherwise would have been payable on the respective dates, and will increase the expected annual cash interest expense by approximately $33 million, constituting the additional cash interest that will be payable with respect to the $312 million of additional toggle notes.

13

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 September 30, 2009 is provided in the long-term debt table above and reflects LIBOR-based borrowings.

In August 2009, the Credit Agreement governing the TCEH Senior Secured Facilities was amended to reduce the existing first lien capacity under the TCEH Senior Secured Facilities by $1.25 billion in exchange for the ability for TCEH to issue up to an additional $4 billion of secured notes or loans ranking junior to TCEH’s first lien obligations, provided that:

• such notes or loans mature later than the latest maturity date of any of the initial term loans under the TCEH Senior Secured Facilities, and

• any net cash proceeds from any such issuances are used (i) in exchange for, or to refinance, repay, retire, refund or replace indebtedness of TCEH or (ii) to acquire, directly or indirectly, all or substantially all of the property and assets or business of another person or to finance the purchase price, cost of design, acquisition, construction, repair, restoration, replacement, expansion, installation or improvement of certain fixed or capital assets.

In addition, the amended Credit Agreement permits TCEH to, among other things:

• issue new secured notes or loans, which may include, in each case, indebtedness secured on a pari passu basis with the obligations under the TCEH Senior Secured Facilities, so long as, in each case, among other things, the net cash proceeds from any such issuance are used to prepay certain loans under the TCEH Senior Secured Facilities at par;

• agree with individual lenders to extend the maturity of their term loans or extend or refinance their revolving credit commitments under the TCEH Senior Secured Facilities, and pay increased interest rates or otherwise modify the terms of their loans or revolving commitments in connection with such an extension, and

• exclude from the financial maintenance covenant under the TCEH Senior Secured Facilities any new debt issued that ranks junior to TCEH’s first lien obligations 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 Hedges” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

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

14

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

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

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

Push Down of EFH Corp. Notes — The EFH Corp. Senior Notes described immediately below are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding. In accordance with SEC Staff Accounting Bulletin (SAB) Topic 5-J, EFC Holdings reflects $2.325 billion principal amount of the EFH Corp. Senior Notes on its balance sheet and the related interest expense in its income statement. The amount reflected on EFC Holdings’ balance sheet, which represents 50% of the EFH Corp. debt guaranteed by EFC Holdings, was calculated based upon the relative equity investment of EFC Holdings and Intermediate Holding in their respective operating subsidiaries at the time of the Merger. Because payment of principal and interest on the notes is the responsibility of EFH Corp., EFC Holdings records the settlement of such amounts as noncash capital contributions from EFH Corp. See Note 12 in the 2008 Form 10-K for more information on the notes and guarantees.

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

EFH Corp. made its May 2009 interest payment and will make its November 2009 and May 2010 interest payments by using the PIK feature of the EFH Corp. Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 11.25% to 12.00%. As of result of the PIK elections, EFH Corp. increased the aggregate principal amount of the EFH Corp. Toggle Notes by $150 million on May 1, 2009 and will further increase the aggregate principal amount of the EFH Corp. Toggle Notes by $159 million on November 1, 2009 and $169 million on May 1, 2010. The elections will increase the expected annual cash interest expense by approximately $54 million (50% of which relates to EFC Holdings due to push down), constituting the additional cash interest that will be payable with respect to the $478 million of additional toggle notes. These amounts may be affected by the debt exchange offers discussed below.

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

EFH Corp. Debt Exchange Offers — In October 2009, EFH Corp. and certain of its subsidiaries commenced offers to exchange certain EFH Corp. outstanding debt securities and the TCEH Cash-Pay Notes for up to $3 billion principal amount of new senior secured notes that will be guaranteed by EFC Holdings and Intermediate Holding. The purpose of the exchange offers is to reduce the outstanding principal amount and extend the weighted average maturity of the long-term debt of EFH Corp. and its subsidiaries. The exchange offers may result in (i) a reduction of the amount of debt guaranteed by EFC Holdings and the amount of debt pushed down to EFC Holdings from EFH Corp. related to EFH Corp. Senior Notes exchanged and (ii) an increase in the amount of debt guaranteed by, and the amount pushed down to, EFC Holdings from EFH Corp. related to any new senior secured notes issued. EFH Corp. filed a registration statement on Form S-4 relating to the exchange offers with the SEC on October 5, 2009 as amended on October 23, 2009.

TCEH Interest Rate Swap Transactions — As of September 30, 2009, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $17.55 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2009 to 2014. Interest rate swaps on an aggregate of $15.05 billion were being accounted for as cash flow hedges related to variable interest rate cash flows until August 29, 2008, at which time these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at the dedesignation date and was recorded in accumulated other comprehensive income. This balance will be reclassified into net income as interest on the hedged debt is reflected in net income. No ineffectiveness gains or losses were recorded.

As of September 30, 2009, 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 $18.0 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 0.353%. These transactions include swaps entered into in the nine months ended September 30, 2009 related to an aggregate $9.55 billion principal amount of senior secured term loans of TCEH and reflect the expiration of swaps in the nine months ended September 30, 2009 that related to an aggregate $4.595 billion principal amount of senior secured term loans of TCEH.

The interest rate swap counterparties are secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Subsequent to the dedesignation in August 2008 discussed above, changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $138 million in net losses and $36 million in net gains in the three months ended September 30, 2009 and 2008, respectively, and $527 million and $36 million in net gains in the nine months ended September 30, 2009 and 2008, respectively. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.4 billion at September 30, 2009, of which $238 million (pre-tax) was reported in accumulated other comprehensive income.

See Note 7 for discussion of collateral investments related to certain of these interest rate swaps.

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5. COMMITMENTS AND CONTINGENCIES

Generation Development

Construction of three lignite-fueled generation units in Texas, two units at Oak Grove and one unit at Sandow, is nearing completion. The Sandow unit achieved substantial completion (as defined in the EPC Agreement for the unit) on September 30, 2009, and one Oak Grove unit is in the commissioning and start-up phase.

In connection with the acquisition of the development rights to the Sandow unit, a subsidiary of TCEH (Sandow Power Company LLC, or Sandow Power) became a party to a federal consent decree with, among others, the US Department of Justice in August 2007 (the Consent Decree). A 2007 federal court order that was merged into the Consent Decree requires that, among other things, the Sandow unit commence commercial operation (as defined in the Consent Decree) and achieve and maintain certain emission-related deadlines by August 31, 2009. The Sandow unit met the commercial operation deadline by synchronizing to the ERCOT grid in early July 2009. However, due to unforeseen weather events and equipment malfunctions experienced during commissioning and start-up activities, the Sandow unit was not able to meet the emission-related deadlines by August 31, 2009. Under the terms of the Consent Decree, Sandow Power may request an extension to these deadlines from the federal district court that presides over the Consent Decree for certain force majeure events (including such events as the weather events and equipment malfunctions described above). In September 2009, the federal district court granted Sandow Power’s request for force majeure relief and gave Sandow Power an additional sixty-one days from August 31, 2009 to begin achieving compliance with the applicable Consent Decree deadlines.

TCEH has received the air permits for the Sandow and Oak Grove units. However, the issuances of the air permits have been challenged as discussed below under “Litigation Related to Generation Facilities.”

Construction work-in-process asset balances for the Oak Grove units totaled approximately $3.3 billion as of September 30, 2009, which includes the effects of the fair value adjustments related to purchase accounting and capitalized interest. In the unexpected event the development of the Oak Grove units was cancelled due to air permit challenges, the cancellation exposure as of September 30, 2009 totaled $3.4 billion, which includes the carrying value of the project and up to approximately $100 million of termination obligations. This estimated exposure amount excludes any potential recovery values for assets acquired to date and for assets already owned prior to executing such agreements that are being utilized in these projects.

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Litigation Related to Generation Facilities

In September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs has asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. EFC Holdings believes 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 June and September 2008, administrative appeals were filed in the State District Court of Travis County, Texas to challenge the administrative action of the TCEQ Executive Director in issuing an air permit alteration for the previously-permitted construction and operation of the Sandow 5 generation facility in Milam County, Texas, and the failure of the TCEQ to overturn that administrative action. Plaintiffs asked that the District Court reverse the issuance of the permit alteration. The Attorney General of Texas, on behalf of TCEQ, is defending the issuance of the permit alteration. Sandow Power has intervened in support of the TCEQ. The plaintiff’s brief was filed in late August 2009, and the Attorney General of Texas and Sandow Power have filed responsive briefs. EFC Holdings believes the Sandow 5 air permit alteration administratively issued by the Executive Director of 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 Sandow 5 project.

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

Other Litigation

In July 2008, Alcoa Inc. filed a lawsuit in Milam County, Texas district court against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of EFC Holdings’ 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 EFC Holdings is unable to estimate any possible loss or predict the outcome of this litigation, it believes the plaintiff’s claims made in this litigation are without merit and, accordingly, intends to vigorously defend this litigation.

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Regulatory Investigations and Reviews

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

Other Proceedings

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

Guarantees

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

Residual value guarantees in operating leases — Subsidiaries of EFC Holdings are the lessee under various operating leases that guarantee the residual values of the leased assets. At September 30, 2009, the aggregate maximum amount of residual values guaranteed was approximately $41 million with an estimated residual recovery of approximately $46 million. These leased assets consist primarily of mining equipment and rail cars. The average life of the residual value guarantees under the lease portfolio is approximately four years.

See Note 4 above and Note 12 to Financial Statements in the 2008 Form 10-K for discussion of guarantees and security for certain EFC Holdings indebtedness.

Letters of Credit

At September 30, 2009, TCEH had outstanding letters of credit under its credit facilities totaling $714 million as follows:

• $360 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

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

• $65 million for collateral funding transactions with counterparties to interest rate swap agreements related to TCEH debt (see Note 7), and

• $81 million for miscellaneous credit support requirements.

Long-Term Contractual Obligations and Commitments — In the nine months ended September 30, 2009, EFC Holdings entered into contractual obligations for fuel for its generation facilities totaling approximately $320 million to purchase nuclear fuel in periods between 2010 and 2020 and totaling approximately $153 million to purchase coal in periods between 2010 and 2012.

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6. EQUITY

Dividend Restrictions — There are no restrictions on EFC Holdings’ ability to use its retained earnings or net income to make distributions on its equity. However, EFC Holdings relies on distributions or loans from TCEH to meet its cash requirements, including funding of distributions. The TCEH Senior Secured Facilities and Indenture generally restrict TCEH’s ability to make distributions or loans to EFC Holdings. Thus, all of TCEH’s net income, which represents essentially all of EFC Holdings’ net income, is restricted from being used to make distributions or loans to EFC Holdings unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and Indenture. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies, EFC Holdings and EFH Corp., 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. The TCEH Senior Secured Facilities generally restrict TCEH from making any distribution to any of its parent companies for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0.

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

EFC Holdings has not paid any cash dividends on its common stock subsequent to the Merger.

Noncontrolling Interests

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

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Equity

The following table presents the changes to equity for the nine months ended September 30, 2009:

	EFC Holdings Shareholders’ Equity
	Preferred Stock			Common Stock		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests (a)		Total Equity
Balance at December 31, 2008	$	1		$	5,538	$	(10,305	)	$	(236	)	$	—	$	(5,002	)
Net income		—			—		347			—			—		347
Net effect of cash flow hedges		—			—		—			79			—		79
Effects of stock-based incentive compensation plans		—			5		—			—			—		5
Investment in subsidiary by noncontrolling interests		—			—		—			—			42		42
Effects of debt push-down from EFH Corp. (Note 4)		—			13		—			—			—		13
Preferred stock redemption		(1	)		—		—			—			—		(1	)
Other		—			1		—			(1	)		—		—
Balance at September 30, 2009	$	—		$	5,557	$	(9,958	)	$	(158	)	$	42	$	(4,517	)

(a) See Note 1 for discussion of adoption of amended guidance for accounting for noncontrolling interests in consolidated financial statements.

7. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Risk Management Hedging Strategy

EFC Holdings enters 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. EFC Holdings’ principal activities involving derivatives consist of a long-term hedging program and the hedging of interest costs on its long-term debt. See Note 8 for a discussion of the fair value of all derivatives.

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

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to a fixed basis, thereby hedging future interest costs and related cash flows. 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 4 for additional information about these and other interest rate swap agreements.

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

As of September 30, 2009, commodity positions accounted for as cash flow hedges, which represent a small portion of economic hedge positions, reduce exposure to variability of future cash flows through 2009.

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

	Derivatives not under hedge accounting											Cash flow hedges
	Derivative assets					Derivative liabilities						Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Commodity contracts			Total
Current assets	$	2,517		$	9	$	11		$	—		$	—		$	2,537
Noncurrent assets		1,118			5		30			—			—			1,153
Current liabilities		(28	)		—		(1,910	)		(595	)		(2	)		(2,535	)
Noncurrent liabilities		(19	)		—		(524	)		(800	)		—			(1,343	)
Net assets (liabilities)	$	3,588		$	14	$	(2,393	)	$	(1,395	)	$	(2	)	$	(188	)

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $396 million and $190 million in net liabilities at September 30, 2009 and December 31, 2008, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Amounts presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because EFC Holdings 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 early 2009, EFH Corp. and TCEH entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which the companies elected to enter into as a cash management measure, as of September 30, 2009 EFH Corp. (parent) has posted $400 million in cash and TCEH has 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. At September 30, 2009, the net mark-to-market liability under the derivative agreements exceeded the collateral posted under such agreements. In particular, the net commodity and interest rate swap mark-to-market liability related to the $400 million cash posting totaled $685 million at September 30, 2009. The companies are not required to post any additional collateral to these counterparties, regardless of the net mark-to-market liability under the applicable derivative agreement, and the applicable counterparty will return the cash collateral to the extent the mark-to-market liability under the applicable derivative agreement falls below the funded amount, subject to a $50 million minimum transfer amount. The counterparties are required to return any remaining collateral, along with accrued and unpaid interest, on March 31, 2010.

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The following table presents the pre-tax effect of derivatives not under hedge accounting on net income, including realized and unrealized effects, for the three and nine months ended September 30, 2009:

Derivative (Income statement presentation)	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Commodity contracts (Net gain (loss) from commodity hedging and trading activities)	$	136		$	1,026
Interest rate swaps (Interest expense and related charges)		(317	)		16
Net gain (loss)	$	(181	)	$	1,042

Results for the three and nine months ended September 30, 2008 include net “day one” losses totaling $10 million and $68 million, respectively, primarily associated with commodity contracts entered into at below market prices. Substantially all of these amounts represent losses associated with related series of transactions involving natural gas financial instruments intended to hedge exposure to future changes in electricity prices. The losses are reported in the income statement in net gain (loss) from commodity hedging and trading activities, consistent with other mark-to-market hedging and trading gains and losses.

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

Three Months Ended September 30, 2009
Derivative	Amount of (loss) recognized in OCI (effective portion)			Income statement presentation of gain (loss) reclassified from accumulated OCI into income (effective portion)	Amount
Interest rate swaps	$	—		Interest expense and related charges	$	(56	)
Commodity contracts		(6	)	Fuel, purchased power costs and delivery fees		(6	)
				Operating revenues		—
Total	$	(6	)		$	(62	)
Nine Months Ended September 30, 2009
Derivative	Amount of (loss) recognized in OCI (effective portion)			Income statement presentation of gain (loss) reclassified from accumulated OCI into income (effective portion)	Amount
Interest rate swaps	$	—		Interest expense and related charges	$	(140	)
Commodity contracts		(31	)	Fuel, purchased power costs and delivery fees		(10	)
				Operating revenues		(2	)
Total	$	(31	)		$	(152	)

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

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Accumulated other comprehensive income related to cash flow hedges at September 30, 2009 totaled $158 million in net losses (after-tax), substantially all of which relates to interest rate swaps. EFC Holdings expects that $81 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of September 30, 2009 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

The following table presents the gross notional amounts of derivative volumes at September 30, 2009:

Derivative type	Notional Volume		Unit of Measure
Interest rate swaps:
Floating/fixed	$	17,550	Million US dollars
Basis	$	18,000	Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		3,522	Million MMBtu
Locational basis swaps		909	Million MMBtu
All other		1,366	Million MMBtu
Electricity		190,431	GWh
Coal		7	Million tons
Fuel oil		166	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 1.7 billion MMBtu.

Credit Risk-Related Contingent Features

The agreements that govern EFC Holdings’ 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 TCEH’s credit rating is downgraded by one or more of the credit rating agencies; however, due to TCEH’s below investment grade ratings, substantially all of such collateral posting requirements are already effective.

As of September 30, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $850 million. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $162 million as of September 30, 2009. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of September 30, 2009, the remaining related liquidity requirement would have totaled $28 million 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 September 30, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.602 billion (before consideration of the amount of assets under the liens). The liquidity exposure associated with these liabilities was reduced by cash collateral and letters of credit posted with counterparties totaling $483 million as of September 30, 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 September 30, 2009, the remaining related liquidity requirement would have totaled $779 million after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 12 to the Financial Statements in EFC Holdings’ 2008 Form 10-K for a description of other obligations that are supported by asset liens.

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As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.452 billion at September 30, 2009. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.

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

While the disclosures above address EFC Holdings’ derivative liabilities, EFC Holdings also manages its counterparty credit exposure with respect to derivative assets.

8. 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. EFC Holdings uses 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 its assets and liabilities subject to fair value measurement on a recurring basis. EFC Holdings primarily uses the market approach for recurring fair value measurements and uses valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

EFC Holdings categorizes its 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. EFC Holdings’ Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of EFC Holdings’ 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. EFC Holdings’ 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, EFC Holdings’ 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. EFC Holdings uses the most meaningful information available from the market combined with internally developed valuation methodologies to develop its best estimate of fair value. For example, EFC Holdings’ 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.

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EFC Holdings utilizes 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, EFC Holdings attempts to obtain multiple quotes from brokers that are active in the commodity markets in which it participates (and requires 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, EFC Holdings uses 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. EFC Holdings believes the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

With respect to amounts presented in the following fair value hierarchy table, the fair value measurement of an asset or liability (e.g. a contract) is required 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 September 30, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	1,035	$	2,276	$	277	$	88	$	3,676
Interest rate swaps		—		14		—		—		14
Nuclear decommissioning trust – equity securities (c)		142		99		—		—		241
Nuclear decommissioning trust – debt securities (c)		—		216		—		—		216
Total assets	$	1,177	$	2,605	$	277	$	88	$	4,147
Liabilities:
Commodity contracts	$	1,133	$	944	$	318	$	88	$	2,483
Interest rate swaps		—		1,395		—		—		1,395
Total liabilities	$	1,133	$	2,339	$	318	$	88	$	3,878

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

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

(c) The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 12.

26

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

	Level 1		Level 2			Level 3 (a)		Total
Assets:
Commodity contracts	$	1,010	$	2,061		$	283	$	3,354
Interest rate swaps		—		(1	)		—		(1	)
Nuclear decommissioning trust – equity securities (b)		109		83			—		192
Nuclear decommissioning trust – debt securities (b)		—		193			—		193
Total assets	$	1,119	$	2,336		$	283	$	3,738
Liabilities:
Commodity contracts	$	1,288	$	1,274		$	355	$	2,917
Interest rate swaps		—		1,908			—		1,908
Total liabilities	$	1,288	$	3,182		$	355	$	4,825

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

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

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 7 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 4 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of 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.

27

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Balance at beginning of period	$	(72	)	$	(539	)	$	(72	)	$	(173	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		42			297			57			(48	)
Included in other comprehensive income (loss)		(6	)		(12	)		(31	)		3
Purchases, sales, issuances and settlements (net) (b)		(6	)		(42	)		(15	)		(45	)
Net transfers in and/or out of Level 3 (c)		1			104			20			71
Balance at end of period	$	(41	)	$	(192	)	$	(41	)	$	(192	)
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period (d)	$	44		$	213		$	61		$	(33	)

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

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

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

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

9. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

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

	September 30, 2009						December 31, 2008
	Carrying Amount			Fair Value (a)			Carrying Amount			Fair Value (a)
On balance sheet assets (liabilities):
Long-term debt (including current maturities (b)	$	(32,172	)	$	(24,537	)	$	(31,666	)	$	(21,724	)
Off balance sheet assets (liabilities):
Financial guarantees	$	—		$	(8	)	$	—		$	(3	)

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

(b) Excludes capital leases.

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

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10. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS

Subsidiaries of EFC Holdings are participating employers in the EFH Retirement Plan, a defined benefit pension plan sponsored by EFH Corp. Subsidiaries of EFC Holdings also participate with EFH Corp. and certain other affiliated subsidiaries of EFH Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. The net allocated pension and other postretirement employee benefits (OPEB) costs applicable to EFC Holdings totaled $7 million and $4 million for the three months ended September 30, 2009 and 2008, respectively, and $17 million and $11 million for the nine months ended September 30, 2009 and 2008, respectively.

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

EFC Holdings provided cash contributions totaling $883 thousand to the pension plan and $464 thousand to the OPEB plan in the nine months ended September 30, 2009, and expects to make additional contributions of approximately $287 thousand and $136 thousand, respectively, in the remainder of 2009.

11. RELATED–PARTY TRANSACTIONS

The following represent the significant related-party transactions of EFC Holdings:

• TCEH incurs electricity delivery fees charged by Oncor. These fees totaled $308 million and $783 million for the three and nine month periods ended September 30, 2009, respectively, and $292 million and $778 million for the three and nine month periods ended September 30, 2008, respectively.

• 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, EFC Holdings’ financial statements reflect a noninterest bearing note payable to Oncor of $263 million ($36 million reported as trade accounts and other payable to affiliates) at September 30, 2009 and $289 million ($35 million reported as trade accounts and other payable to affiliates) at December 31, 2008.

• TCEH reimburses Oncor for interest expense on Oncor’s bankruptcy-remote financing subsidiary’s securitization bonds. This interest expense totaled $10 million and $32 million for the three and nine month periods ended September 30, 2009, respectively, and $11 million and $35 million for the three and nine month periods ended September 30, 2008, respectively.

• Notes receivable from EFH Corp. are payable to EFC Holdings on demand and arise from borrowings used for the working capital and general corporate purposes of EFH Corp. The notes totaled $1.112 billion at September 30, 2009 and $584 million at December 31, 2008. The average daily balance of the notes for the three and nine month periods ended September 30, 2009 was $1.061 billion and $801 million, respectively, and was $480 million and $365 million for the three and nine month periods ended September 30, 2008, respectively . The notes carry interest at a rate based on the one-month LIBOR rate plus 5.00%, and interest income totaled $14 million and $33 million for the three and nine month periods ended September 30, 2009, respectively, and $9 million and $22 million for the three and nine month periods ended September 30, 2008, respectively.

• An EFH Corp. subsidiary charges subsidiaries of EFC Holdings for financial, accounting, environmental and other administrative services at cost. These costs, which are primarily reported in SG&A expenses, totaled $17 million and $53 million for the three and nine month periods ended September 30, 2009, respectively, and $15 million and $46 million for the three and nine month periods ended September 30, 2008, respectively.

29

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in investments on EFC Holdings’ 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 EFC Holdings’ balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by EFC Holdings 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 September 30, 2009 and December 31, 2008, the excess of the net decommissioning liability over the trust fund balance resulted in a regulatory asset at Oncor of $90 million and $127 million, respectively.

• TCEH had posted cash collateral of $15 million as of September 30, 2009 and December 31, 2008 to Oncor related to interconnection agreements for three generation units being developed by TCEH. The collateral is reported in EFC Holdings’ balance sheet in other current assets.

• EFC Holdings has a 53.1% limited partnership interest, with a carrying value of $12 million and $17 million at September 30, 2009 and December 31, 2008, respectively, in an EFH Corp. subsidiary holding software and other computer-related assets. Equity losses related to this interest totaled $1 million and $5 million for the three and nine month periods ended September 30, 2009, respectively, and totaled $2 million and $7 million for the three and nine month periods ended September 30, 2008, respectively. These losses primarily represent amortization of assets held by the subsidiary. The equity losses are reported as other deductions.

• EFH Corp. files a consolidated federal income tax return; however, EFC 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 EFC Holdings filed its own income tax returns. As a result, EFC Holdings had income taxes payable to EFH Corp. of $140 million and $33 million at September 30, 2009 and December 31, 2008, respectively.

• 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 September 30, 2009 and December 31, 2008, TCEH had posted letters of credit in the amount of $16 million and $13 million, respectively, for the benefit of Oncor.

• 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 will post a letter of credit in an amount equal to $170 million to secure retail payment obligations to Oncor if two or more of Oncor’s credit ratings are below investment grade.

• At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities with a syndicate of financial institutions and other lenders. This syndicate included affiliates of GS Capital Partners (a member of the Sponsor Group). In November and December 2007, TCEH offered the TCEH Notes. Affiliates of GS Capital Partners served as initial purchasers in such offerings. Affiliates of GS Capital Partners have from time to time engaged in commercial banking and financial advisory transactions with EFC Holdings in the normal course of business.

• Affiliates of GS Capital Partners are parties to certain commodity and interest rate hedging transactions with EFC Holdings in the normal course of business.

• Affiliates of the Sponsor Group may sell or acquire debt or debt securities issued by EFC Holdings or its subsidiaries in open market transactions or through loan syndications.

See Note 3 for information regarding the accounts receivable securitization program and related subordinated notes receivable from TXU Receivables Company and Note 4 for guarantees and push-down of certain EFH Corp. debt.

30

12. SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Other income:
Reversal of reserve recorded in purchase accounting (a)	$	23	$	—	$	23	$	—
Fee received related to interest rate swap commodity hedge derivative agreement (Note 7)		6		—		6		—
Sales tax refund		3		—		3		—
Mineral rights royalty income		1		1		2		3
Other		—		1		4		5
Total other income	$	33	$	2	$	38	$	8
Other deductions:
Impairment of emission allowances intangible assets	$	—	$	499	$	—	$	501
Charge related to Lehman bankruptcy (b)		—		26		—		26
Severance charges		—		—		6		—
Litigation/regulatory settlements		—		—		—		7
Equity losses - unconsolidated affiliates		1		3		5		8
Other		5		3		8		8
Total other deductions	$	6	$	531	$	19	$	550

(a) Reversal of a use tax accrual, related to periods prior to the Merger, due to state ruling in the third quarter of 2009.

(b) Reserve established against amounts due (excluding termination related costs) from subsidiaries of Lehman Brothers Holdings Inc. arising from commodity hedging and trading activities.

Interest Expense and Related Charges

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Interest (including net amounts settled/ accrued under interest rate swaps)	$	694		$	692		$	2,083		$	2,085
Unrealized mark-to-market net (gain) loss on interest rate swaps		138			(36	)		(527	)		(36	)
Amortization of interest rate swap losses at dedesignation of hedge accounting		56			17			140			17
Amortization of fair value debt discounts resulting from purchase accounting		4			4			12			12
Amortization of debt issuance costs and discounts		30			44			91			99
Capitalized interest		(80	)		(74	)		(252	)		(220	)
Total interest expense and related charges	$	842		$	647		$	1,547		$	1,957

Restricted Cash

	At September 30, 2009				At December 31, 2008
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to the TCEH Letter of Credit Facility (See Note 4)	$	—	$	1,135	$	—	$	1,250
Amounts related to margin deposits held		1		—		4		—
Total restricted cash	$	1	$	1,135	$	4	$	1,250

31

Inventories by Major Category

	September 30, 2009		December 31, 2008
Materials and supplies	$	153	$	134
Fuel stock		222		162
Natural gas in storage		28		65
Total inventories	$	403	$	361

Investments

	September 30, 2009		December 31, 2008
Nuclear decommissioning trust	$	457	$	385
Assets related to employee benefit plans, including employee savings programs, net of distributions		36		36
Land		42		42
Investment in natural gas gathering pipeline business (a)		31		—
Investment in unconsolidated affiliate		12		17
Miscellaneous other		3		4
Total investments	$	581	$	484

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

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

	September 30, 2009
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	210	$	9	$	(3	)	$	216
Equity securities (c)		191		71		(21	)		241
Total	$	401	$	80	$	(24	)	$	457
	December 31, 2008
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	203	$	4	$	(14	)	$	193
Equity securities (c)		181		46		(35	)		192
Total	$	384	$	50	$	(49	)	$	385

(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 4.15% and 3.77% and an average maturity of 8.3 years and 8.0 years at September 30, 2009 and December 31, 2008, 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 September 30, 2009 mature as follows: $79 million in one to five years, $33 million in five to ten years and $104 million after ten years.

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Property, Plant and Equipment

As of September 30, 2009 and December 31, 2008, property, plant and equipment of $21.0 billion and $20.9 billion, respectively, was stated net of accumulated depreciation and amortization of $2.4 billion and $1.5 billion, respectively.

Asset Retirement Obligations

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

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

Asset retirement liability at January 1, 2009	$	859
Additions:
Accretion		45
Reductions:
Payments, essentially all mining reclamation		(21	)
Asset retirement liability at September 30, 2009	$	883

Exit Liabilities

As part of purchase accounting, EFC Holdings accrued $38 million in costs expected to be incurred related to the termination and transition of outsourcing arrangements. EFC Holdings incurred $7 million and $16 million of the exit liabilities in the three and nine months ended September 30, 2009, respectively, and the remaining accrual is expected to be settled no later than June 30, 2010, the targeted date of completion of transition of outsourced activities back to EFC Holdings or to service providers.

Other Noncurrent Liabilities and Deferred Credits

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

	September 30, 2009		December 31, 2008
Uncertain tax positions (including accrued interest)	$	983	$	861
Asset retirement obligations		883		859
Unfavorable purchase and sales contracts		707		727
Retirement plan and other employee benefits		57		56
Other		14		25
Total other noncurrent liabilities and deferred credits	$	2,644	$	2,528

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

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $7 million and $6 million in the three months ended September 30, 2009 and 2008, respectively, and $21 million and $23 million in the nine months ended September 30, 2009 and 2008, respectively. Favorable purchase and sales contracts are recorded as intangible assets (see Note 2).

33

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

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

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2009			2008
Cash payments (receipts) related to:
Interest paid (a)	$	1,603		$	1,734
Capitalized interest		(252	)		(220	)
Interest paid (net of capitalized interest) (a)		1,351			1,514
Income taxes		38			31
Noncash investing and financing activities:
Issuance of toggle notes in lieu of cash interest for TCEH		98			—
Effect of Parent’s payment of interest and issuance of toggle notes as consideration for cash interest, net of tax, on pushed down debt		87			126
Noncash construction expenditures (b)		72			155
Capital leases		15			13
Purchase accounting adjustments		—			(66	)

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

(b) Represents end of period accruals.

34

13. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

In 2007, TCEH and TCEH Finance, as Co-Issuers, issued $3.0 billion 10.25% Senior Notes Due 2015, $2.0 billion 10.25% Series B Senior Notes due 2015 and $1.75 billion 10.50%/11.25% Senior Toggle Notes due 2016 (the TCEH Senior Notes). In May 2009, the Co-Issuers issued an additional $98.5 million of the Senior Toggle Notes (see Note 4). The TCEH Senior Notes are unconditionally guaranteed by EFC Holdings and by each subsidiary that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the TCEH Senior Notes. The guarantees rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFC Holdings, either direct or indirect, do not guarantee the TCEH Senior Notes (collectively the Non-Guarantors). The indenture governing the TCEH Senior Notes contains certain restrictions, subject to certain exceptions, on EFC Holdings’ ability to pay dividends or make investments. See Note 6.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income of EFC Holdings (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors for the three- and nine-month periods ended September 30, 2009 and 2008, the condensed consolidating statements of cash flows of the Parent, Issuer, the Guarantors and the Non-Guarantors for the nine-month periods ended September 30, 2009 and 2008 and the condensed consolidating balance sheets as of September 30, 2009 and December 31, 2008 of the Parent, Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5J, Push Down Basis of Accounting Required in Certain Limited Circumstances, including the effects of the push down of the $2.325 billion and $2.250 billion of the EFH Corp. Senior Notes to the Parent Guarantor as of September 30, 2009 and December 31, 2008, respectively, and the TCEH Senior Notes and the TCEH Senior Secured Facilities to the Other Guarantors. TCEH Finance’s sole function is to be the co-issuer of the TCEH Senior Notes; therefore, it has no other independent assets, liabilities or operations (see Notes 4 and 5).

EFC Holdings (parent entity) received no dividends from its consolidated subsidiaries for the nine-month period ended September 30, 2009 or for the nine-month period ended September 30, 2008.

35

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended September 30, 2009

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-Guarantors		Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,433		$	—	$	—		$	2,433
Fuel, purchased power costs and delivery fees		—			—			(1,187	)		—		—			(1,187	)
Net gain (loss) from commodity hedging and trading activities		—			152			(29	)		—		—			123
Operating costs		—			—			(161	)		—		—			(161	)
Depreciation and amortization		—			—			(303	)		—		—			(303	)
Selling, general and administrative expenses		—			—			(192	)		—		—			(192	)
Franchise and revenue-based taxes		—			—			(27	)		—		—			(27	)
Other income		—			5			28			—		—			33
Other deductions		—			—			(6	)		—		—			(6	)
Interest income		—			112			111			—		(202	)		21
Interest expense and related charges		(72	)		(988	)		(407	)		—		625			(842	)
Income (loss) before income taxes		(72	)		(719	)		260			—		423			(108	)
Income tax (expense) benefit		25			239			(82	)		—		(146	)		36
Equity earnings (losses) of subsidiaries		(25	)		455			—			—		(430	)		—
Net income (loss)		(72	)		(25	)		178			—		(153	)		(72	)
Net (income) loss attributable to noncontrolling interests		—			—			—			—		—			—
Net income (loss) attributable to EFC Holdings	$	(72	)	$	(25	)	$	178		$	—	$	(153	)	$	(72	)

36

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended September 30, 2008

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-Guarantors		Eliminations			Consolidated
Operating revenues	$	—		$	—		$	3,258		$	—	$	—		$	3,258
Fuel, purchased power costs and delivery fees		—			—			(1,923	)		—		—			(1,923	)
Net gain (loss) from commodity hedging and trading activities		—			3,669			2,377			—		(1	)		6,045
Operating costs		—			—			(158	)		—		—			(158	)
Depreciation and amortization		—			—			(296	)		—		—			(296	)
Selling, general and administrative expenses		—			—			(173	)		—		1			(172	)
Franchise and revenue-based taxes		—			—			(26	)		—		—			(26	)
Other income		—			—			2			—		—			2
Other deductions		—			25			(555	)		—		(1	)		(531	)
Interest income		—			90			178			—		(248	)		20
Interest expense and related charges		(66	)		(796	)		(603	)		—		818			(647	)
Income (loss) before income taxes		(66	)		2,988			2,081			—		569			5,572
Income tax (expense) benefit		23			(1,068	)		(744	)		—		(197	)		(1,986	)
Equity earnings (losses) of subsidiaries		3,629			1,709			—			—		(5,338	)		—
Net income (loss)	$	3,586		$	3,629		$	1,337		$	—	$	(4,966	)	$	3,586

37

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Nine Months Ended September 30, 2009

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	6,144		$	—		$	—		$	6,144
Fuel, purchased power costs and delivery fees		—			—			(2,987	)		—			—			(2,987	)
Net gain from commodity hedging and trading activities		—			538			465			—			—			1,003
Operating costs		—			—			(504	)		—			—			(504	)
Depreciation and amortization		—			—			(862	)		—			—			(862	)
Selling, general and administrative expenses		—			—			(552	)		(3	)		—			(555	)
Franchise and revenue-based taxes		—			—			(74	)		—			—			(74	)
Impairment of goodwill		—			(70	)		—			—			—			(70	)
Other income		—			6			32			—			—			38
Other deductions		—			—			(19	)		—			—			(19	)
Interest income		—			315			303			—			(579	)		39
Interest expense and related charges		(217	)		(1,975	)		(1,231	)		—			1,876			(1,547	)
Income (loss) before income taxes		(217	)		(1,186	)		715			(3	)		1,297			606
Income tax (expense) benefit		71			371			(252	)		1			(450	)		(259	)
Equity earnings (losses) of subsidiaries		493			1,308			—			—			(1,801	)		—
Net income (loss)		347			493			463			(2	)		(954	)		347
Net (income) loss attributable to noncontrolling interests		—			—			—			—			—			—
Net income (loss) attributable to EFC Holdings	$	347		$	493		$	463		$	(2	)	$	(954	)	$	347

38

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Nine Months Ended September 30, 2008

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- Guarantors		Eliminations			Consolidated
Operating revenues	$	—		$	—		$	7,809		$	—	$	—		$	7,809
Fuel, purchased power costs and delivery fees		—			—			(4,646	)		—		—			(4,646	)
Net gain (loss) from commodity hedging and trading activities		—			12			(260	)		—		—			(248	)
Operating costs		—			—			(501	)		—		—			(501	)
Depreciation and amortization		—			—			(827	)		—		—			(827	)
Selling, general and administrative expenses		—			—			(495	)		—		—			(495	)
Franchise and revenue-based taxes		1			—			(74	)		—		—			(73	)
Other income		1			—			8			—		(1	)		8
Other deductions		—			25			(574	)		—		(1	)		(550	)
Interest income		5			215			486			—		(662	)		44
Interest expense and related charges		(206	)		(2,383	)		(1,765	)		—		2,397			(1,957	)
Income (loss) before income taxes		(199	)		(2,131	)		(839	)		—		1,733			(1,436	)
Income tax (expense) benefit		67			741			287			—		(602	)		493
Equity earnings (losses) of subsidiaries		(811	)		579			—			—		232			—
Net income (loss)	$	(943	)	$	(811	)	$	(552	)	$	—	$	1,363		$	(943	)

39

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2009

(millions of dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non-guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(5	)	$	(1,073	)	$	2,557		$	(8	)	$	—		$	1,471
Cash flows – financing activities:
Issuances of long-term debt		—			522			—			—			—			522
Retirements/repurchases of long-term debt		(2	)		(122	)		(93	)		—			—			(217	)
Change in advances/notes-affiliates		7			653			—			41			(727	)		(26	)
Contributions from noncontrolling interests		—			—			—			42			—			42
Debt discount, financing and reacquisition expenses		—			(33	)		—			(2	)		—			(35	)
Other-net		—			—			1			—			—			1
Cash provided by (used in) financing activities		5			1,020			(92	)		81			(727	)		287
Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(1,202	)		(61	)		—			(1,263	)
Redemption of investment held in money market fund		—			142			—			—			—			142
Reduction of restricted cash related to letter of credit facility		—			115			—			—			—			115
Transfer of cash collateral from custodian account		—			—			3			—			—			3
Proceeds from sales of environmental allowances and credits		—			—			22			—			—			22
Purchases of environmental allowances and credits		—			—			(23	)		—			—			(23	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			2,972			—			—			2,972
Investments in nuclear decommissioning trust fund securities		—			—			(2,983	)		—			—			(2,983	)
Changes in loans - affiliates		—			—			(1,255	)		—			727			(528	)
Proceeds from sale of controlling interest in natural gas gathering pipeline business		—			40			—			—			—			40
Other-net		—			—			20			—			—			20
Cash provided by (used in) investing activities		—			297			(2,446	)		(61	)		727			(1,483	)
Net change in cash and cash equivalents		—			244			19			12			—			275
Cash and cash equivalents – beginning balance		—			475			4			—			—			479
Cash and cash equivalents – ending balance	$	—		$	719		$	23		$	12		$	—		$	754

40

ENERGY FUTURE COMPETITIVE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2008

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	1		$	(1,024	)	$	1,883		$	5		$	—		$	865
Cash flows – financing activities:
Issuances of long-term debt		—			1,277			—			—			—			1,277
Retirements/repurchases of long-term debt		(2	)		(373	)		(24	)		—			—			(399	)
Change in short-term borrowings		—			2,032			—			—			—			2,032
Change in advances/notes – affiliates		1			—			—			10			(36	)		(25	)
Other-net		—			(4	)		33			—			—			29
Cash provided by (used in) financing activities		(1	)		2,932			9			10			(36	)		2,914
Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(1,499	)		(15	)		—			(1,514	)
Investment held in money market fund		—			(242	)		—			—			—			(242	)
Reduction of restricted cash related to pollution control revenue bonds		—			29			—			—			—			29
Proceeds from sales of environmental allowances and credits		—			—			30			—			—			30
Purchases of environmental allowances and credits		—			—			(18	)		—			—			(18	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			747			—			—			747
Investments in nuclear decommissioning trust fund securities		—			—			(758	)		—			—			(758	)
Change in loans – affiliates		—			(42	)		(375	)		—			36			(381	)
Other-net		—			1			(16	)		—			—			(15	)
Cash provided by (used in) investing activities		—			(254	)		(1,889	)		(15	)		36			(2,122	)
Net change in cash and cash equivalents		—			1,654			3			—			—			1,657
Cash and cash equivalents – beginning balance		—			207			8			—			—			215
Cash and cash equivalents – ending balance	$	—		$	1,861		$	11		$	—		$	—		$	1,872

41

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at September 30 2009

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	719		$	23		$	12	$	—		$	754
Restricted cash		—			—			1			—		—			1
Advances to affiliates		1			—			5,535			—		(5,536	)		—
Trade accounts receivable – net		—			—			751			—		—			751
Notes receivable from parent		—			1,130			—			—		(18	)		1,112
Income taxes receivable from parent		6			62			—			1		(69	)		—
Accounts receivable from affiliates		—			8			—			—		(8	)		—
Inventories		—			—			403			—		—			403
Commodity and other derivative contractual assets		—			495			2,051			—		(9	)		2,537
Accumulated deferred income taxes		1			81			1			—		—			83
Margin deposits related to commodity positions		—			—			158			—		—			158
Other current assets		—			7			42			—		—			49
Total current assets		8			2,502			8,965			13		(5,640	)		5,848
Restricted cash		—			1,135			—			—		—			1,135
Investments		(2,077	)		21,024			584			—		(18,950	)		581
Property, plant and equipment – net		—			—			20,913			67		—			20,980
Goodwill		—			10,252			—			—		—			10,252
Intangible assets – net		—			—			2,658			—		—			2,658
Commodity and other derivative contractual assets		—			563			590			—		—			1,153
Accumulated deferred income taxes		30			293			—			—		(323	)		—
Other noncurrent assets, principally unamortized debt issuance costs		48			567			596			3		(492	)		722
Total assets	$	(1,991	)	$	36,336		$	34,306		$	83	$	(25,405	)	$	43,329
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	900		$	900		$	—	$	(900	)	$	900
Advances from affiliates		—			5,536			—			—		(5,536	)		—
Long-term debt due currently		8			165			199			—		(165	)		207
Trade accounts payable – nonaffiliates		—			—			586			3		—			589
Notes or other liabilities due to affiliates		22			—			233			3		(26	)		232
Commodity and other derivative contractual liabilities		—			720			1,824			—		(9	)		2,535
Margin deposits related to commodity positions		—			111			393			—		—			504
Accrued income taxes payable to parent		—			—			209			—		(69	)		140
Accrued taxes other than income		1			—			94			—		—			95
Accrued interest		113			487			350			—		(347	)		603
Other current liabilities		—			21			305			—		(3	)		323
Total current liabilities		144			7,940			5,093			6		(7,055	)		6,128
Accumulated deferred income taxes		—			—			5,670			—		(289	)		5,381
Commodity and other derivative contractual liabilities		—			887			456			—		—			1,343
Notes or other liabilities due affiliates		—			—			227			—		—			227
Long-term debt, less amounts due currently		2,421			29,529			28,313			—		(28,140	)		32,123
Other noncurrent liabilities and deferred credits		3			58			2,583			—		—			2,644
Total liabilities		2,568			38,414			42,342			6		(35,484	)		47,846
EFC Holdings’ shareholders’ equity		(4,559	)		(2,078	)		(8,036	)		35		10,079			(4,559	)
Noncontrolling interests in subsidiaries		—			—			—			42		—			42
Total equity		(4,559	)		(2,078	)		(8,036	)		77		10,079			(4,517	)
Total liabilities and equity	$	(1,991	)	$	36,336		$	34,306		$	83	$	(25,405	)	$	43,329

42

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31 2008

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	475		$	4		$	—	$	—		$	479
Investments held in money market fund		—			142			—			—		—			142
Restricted cash		—			—			4			—		—			4
Advances to affiliates		4			—			4,306			—		(4,310	)		—
Trade accounts receivable – net		—			—			994			—		—			994
Notes receivable from parent		—			597			—			—		(13	)		584
Income taxes receivable from parent		—			156			—			—		(156	)		—
Inventories		—			—			361			—		—			361
Commodity and other derivative contractual assets		—			223			2,168			—		—			2,391
Accumulated deferred income taxes		—			12			9			—		—			21
Margin deposits related to commodity positions		—			—			439			—		—			439
Other current assets		—			6			80			—		—			86
Total current assets		4			1,611			8,365			—		(4,479	)		5,501
Restricted cash		—			1,250			—			—		—			1,250
Investments		(2,653	)		19,693			482			—		(17,038	)		484
Property, plant and equipment – net		—			—			20,874			28		—			20,902
Goodwill		—			10,322			—			—		—			10,322
Intangible assets – net		—			—			2,774			—		—			2,774
Commodity and other derivative contractual assets		—			429			533			—		—			962
Accumulated deferred income taxes		7			905			—			9		(921	)		—
Other noncurrent assets, principally unamortized debt issuance costs		55			620			698			—		(568	)		805
Total assets	$	(2,587	)	$	34,830		$	33,726		$	37	$	(23,006	)	$	43,000
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	—		$	900		$	900		$	—	$	(900	)	$	900
Advances from affiliates		—			4,287			—			23		(4,310	)		—
Long-term debt due currently		8			165			261			—		(165	)		269
Trade accounts payable – nonaffiliates		—			—			995			5		—			1,000
Notes or other liabilities due to affiliates		16			61			107			—		(13	)		171
Commodity and other derivative contractual liabilities		—			637			2,093			—		—			2,730
Margin deposits related to commodity positions		—			487			436			—		(398	)		525
Accrued income taxes payable to parent		—			—			189			—		(156	)		33
Accrued taxes other than income		—			—			70			—		—			70
Accrued interest		44			297			221			—		(208	)		354
Other current liabilities		—			29			251			—		(5	)		275
Total current liabilities		68			6,863			5,523			28		(6,155	)		6,327
Accumulated deferred income taxes		—			—			6,154			9		(921	)		5,242
Commodity and other derivative contractual liabilities		—			1,549			546			—		—			2,095
Notes or other liabilities due affiliates		—			—			254			—		—			254
Long-term debt, less amounts due currently		2,347			29,020			27,831			—		(27,642	)		31,556
Other noncurrent liabilities and deferred credits		—			52			2,477			—		(1	)		2,528
Total liabilities		2,415			37,484			42,785			37		(34,719	)		48,002
Shareholders’ equity		(5,002	)		(2,654	)		(9,059	)		—		11,713			(5,002	)
Total liabilities and shareholders’ equity	$	(2,587	)	$	34,830		$	33,726		$	37	$	(23,006	)	$	43,000

43

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Competitive Holdings Company:

We have reviewed the accompanying condensed consolidated balance sheet of Energy Future Competitive Holdings Company and subsidiaries (“EFC Holdings”) as of September 30, 2009, and the related condensed statements of consolidated income (loss) and comprehensive income (loss) for the three-month and nine-month periods ended September 30, 2009 and 2008, and of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of EFC Holdings’ management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Energy Future Competitive Holdings Company and subsidiaries as of December 31, 2008, and the related statements of consolidated income (loss), comprehensive income (loss), cash flows, and shareholders’ equity for the year then ended (not presented herein); and in our report dated March 2, 2009 (which report includes an explanatory paragraph related to Energy Future Holdings Corp. completing its merger with Texas Energy Future Merger Sub Corp and becoming a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2008 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Dallas, Texas

October 29, 2009

44

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

The following discussion and analysis of EFC Holdings’ financial condition and results of operations for the three and nine months ended September 30, 2009 and 2008 should be read in conjunction with its 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

EFC Holdings is a subsidiary of EFH Corp. and is a Dallas-based holding company that conducts its operations principally through its wholly-owned subsidiary, TCEH. TCEH is a Dallas-based holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Commodity risk management and allocation of financial resources are performed at the consolidated level; therefore, there are no reportable business segments.

Significant Activities and Events

Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of September 30, 2009, has effectively sold forward approximately 1.7 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 214,000 GWh at an assumed 8.0 market heat rate) for the period from October 1, 2009 through December 31, 2014 at weighted average annual hedge prices ranging from $7.19 per MMBtu to $8.05 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 71% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning October 1, 2009 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which are expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the NYMEX Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for the fourth quarter 2009 period and more than 95% 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 6% of the positions in the long-term hedging program at September 30, 2009, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. Financial instruments, including collars, are expected to be employed in future hedging activity under the long-term hedging program.

45

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

	Measure	Balance 2009 (a)	2010	2011	2012	2013	2014	Total
Natural gas hedge volumes (b)	mm MMBtu	~58	~298	~466	~492	~300	~97	~1,711
Weighted average hedge price (c)	$/MMBtu	~8.05	~7.80	~7.56	~7.36	~7.19	~7.80	—
Weighted average market price (d)	$/MMBtu	~4.75	~6.21	~6.87	~7.00	~7.06	~7.17	—

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

(b) Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e. delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 97 million MMBtu in 2014.

(c) Weighted average hedge prices are based on sales prices of forward natural gas sales positions in the long-term hedging program based on NYMEX Henry Hub prices (excluding the impact of offsetting purchases for rebalancing and price 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 September 30, 2009, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.7 billion in pretax unrealized mark-to-market gains or losses.

The reported unrealized mark-to-market net loss related to the long-term hedging program for the three months ended September 30, 2009 totaled $106 million. This amount reflects a $145 million net gain due to the effect of lower forward prices of natural gas on the value of positions in the program, which was more than offset by net losses of $251 million representing reversals of previously recorded unrealized gains on positions that settled in the period. The reported unrealized net gain for the nine months ended September 30, 2009 totaled $559 million. This amount reflects a $1.086 billion net gain due to the effect of lower forward prices of natural gas on the value of positions in the program, partially offset by net losses of $527 million representing reversals of previously recorded net gains on positions that settled in the period. Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost. The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $1.430 billion and $871 million at September 30, 2009 and December 31, 2008, respectively. These values can change materially as market conditions change.

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

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

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	Balance 2009 (a)		2010		2011		2012		2013
$1.00/MMBtu change in gas price (b)	$	~9	$	~12	$	~41	$	~91	$	~279
0.1/MMBtu/MWh change in market heat rate (c)	$	—	$	~16	$	~49	$	~57	$	~59
$1.00/gallon change in diesel fuel price	$	—	$	—	$	—	$	—	$	~50
$10.00/pound change in uranium/nuclear fuel	$	—	$	—	$	—	$	~4	$	~1

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

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

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

Debt Exchange Offers — See Note 4 to Financial Statements for discussion of debt exchange offers commenced by EFH Corp. and certain of its subsidiaries in October 2009.

TCEH Interest Rate Swap Transactions — As of September 30, 2009, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $17.55 billion principal amount of its senior secured debt maturing from 2009 to 2014. All of these swaps were entered into prior to January 1, 2009. Taking into consideration these swap transactions, approximately 10% of EFC Holdings’ total long-term debt portfolio at September 30, 2009 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce fixed borrowing costs, related to an aggregate of $18.0 billion principal amount of senior secured debt, including swaps entered into in 2009 related to $9.55 billion principal amount of debt and reflecting the expiration in 2009 of swaps related to an aggregate $4.595 billion principal amount of debt. EFC Holdings 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 $138 million in net losses and $527 million in net gains for the three and nine month periods ended September 30, 2009, respectively. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.4 billion at September 30, 2009, of which $238 million (pre-tax) was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 4 to Financial Statements regarding various interest rate swap transactions.

Texas Generation Facilities Development — TCEH is developing three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in the state of Texas with a total estimated capacity of approximately 2,200 MW. The Sandow unit achieved substantial completion (as defined in the EPC Agreement for the unit) effective September 30, 2009. Accordingly, the company has operational control of the unit. The first Oak Grove unit, which is in the commissioning and start-up phase, synchronized to the grid in August 2009 and is expected to achieve substantial completion (as defined in the EPC Agreement) in the fourth quarter of 2009. The second Oak Grove unit is nearing completion of construction and initiation of the commissioning and start-up phase and is expected to achieve substantial completion (as defined in the EPC Agreement) 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 $3.1 billion was spent as of September 30, 2009. 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 $4.6 billion as of September 30, 2009. See discussion in Note 5 to Financial Statements regarding contingencies related to the units.

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

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

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

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

Global Climate Change — A number of pieces of legislation dealing with greenhouse gas (GHG) emissions have been proposed recently in the US Congress, including the Waxman-Markey bill, known as the American Clean Energy and Security Act of 2009 (Waxman-Markey) and the Kerry-Boxer bill, known as the Clean Energy Jobs and American Power Act (Kerry-Boxer). This proposed legislation is not law, but in June 2009, Waxman-Markey was passed by the US House of Representatives and sent to the US Senate for consideration. Kerry-Boxer is currently being debated in the US Senate Environment and Public Works Committee. President Obama has also expressed support for Waxman-Markey and Kerry-Boxer.

As currently proposed, Waxman-Markey takes several approaches to address GHG emissions, including establishing renewable energy and energy efficiency standards, establishing performance standards for coal-fueled electricity generation units, and creating an economy-wide cap-and-trade program. The renewable energy and energy efficiency standards would require retail electricity suppliers to meet 6% of their load with renewable energy sources by 2012, increasing to 20% of their load by 2020, some of which could be met by energy efficiency measures. The performance standards for coal-fueled electricity generation units would require a 65% reduction in CO₂ emissions for subject generation units initially permitted after January 1, 2020, and a 50% reduction in CO₂ emissions for subject electricity generation units initially permitted between January 1, 2009 and January 1, 2020 once certain technology deployment criteria are met but no later than January 1, 2025. The cap-and-trade program would require emissions from capped sources, including coal-fueled electricity generation units, to be reduced 3% below 2005 levels by 2012, 17% by 2020, 42% by 2030 and 83% by 2050. The version of Waxman-Markey passed by the US House of Representatives included provisions that allocated a large percentage of the emissions allowances at no charge to various groups that would be impacted by such a cap-and-trade program, including certain merchant coal-fueled generation units. The Kerry-Boxer proposal employs a cap and trade approach similar to Waxman-Markey. However, there are the following key differences between Waxman-Markey and Kerry-Boxer: (i) a 20% reduction in CO₂ emissions levels by 2020; (ii) a smaller grant of emission allowances to the electric power sector, including merchant coal-fueled generation units and (iii) the lack of renewable energy and efficiency standards that are addressed in a separate proposal in the US Senate.

Both Waxman-Markey and Kerry-Boxer remain subject to deliberation and modifications in the US Congress, thereby precluding an accurate estimate of the cost of compliance; however, if Waxman-Markey, Kerry-Boxer or similar legislation were to be adopted, EFC Holdings’ costs of compliance with the law could be material.

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

In September 2009, the US Court of Appeals for the Second Circuit issued a decision in the case of State of Connecticut v. American Electric Power Company Inc. holding that various states, a municipality and certain private trusts have standing to sue and have sufficiently alleged a cause of action under the federal common law of nuisance for injuries allegedly caused by the defendant power generation companies’ emissions of GHGs. While the decision does not address the merits of the nuisance claim, and is still subject to appeal, it might encourage or form the basis for other lawsuits asserting similar nuisance claims regarding emissions of GHGs.

In October 2009, the US Court of Appeals for the Fifth Circuit also issued a decision in the case of Comer v. Murphy Oil USA holding that certain Mississippi residents have standing to sue to pursue state law nuisance, negligence and trespass claims for injuries purportedly suffered because the defendants’ emissions of GHGs allegedly increased the destructive force of Hurricane Katrina. This decision, like the American Electric Power decision discussed above, does not address the merits of such a nuisance claim and is still subject to appeal.

While EFC Holdings is not a party to these suits, if any similar suit was successfully asserted against EFC Holdings in the future, it could have a material adverse effect on EFC Holdings’ business, results of operations and financial condition.

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RESULTS OF OPERATIONS

Sales Volume and Customer Count Data

	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
	2009		2008				2009		2008
Sales volumes:
Retail electricity sales volumes — (GWh):
Residential	9,348		9,098		2.7		22,312		22,153		0.7
Small business (a)	2,598		2,241		15.9		6,228		5,802		7.3
Large business and other customers	4,049		4,038		0.3		10,905		10,951		(0.4	)
Total retail electricity	15,995		15,377		4.0		39,445		38,906		1.4
Wholesale electricity sales volumes	10,126		12,472		(18.8	)	30,180		35,529		(15.1	)
Net sales (purchases) of balancing electricity to/from ERCOT	(38	)	145		—		(304	)	(1,335	)	(77.2	)
Total sales volumes	26,083		27,994		(6.8	)	69,321		73,100		(5.2	)
Average volume (kWh) per residential customer (b):	4,936		4,802		2.8		11,772		11,767		—
Weather (North Texas average) — percent of normal (c):
Cooling degree days	99.1	%	100.7	%	(1.6	)	103.3	%	109.0	%	(5.2	)
Heating degree days	—	%	—	%	—		89.3	%	93.7	%	(4.7	)
Customer counts:
Retail electricity customers (end of period and in thousands) (d):
Residential							1,876		1,909		(1.7	)
Small business (a)							273		276		(1.1	)
Large business and other customers							23		27		(14.8	)
Total retail electricity customers							2,172		2,212		(1.8	)

(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 20-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. Nine months ended September 30, 2008 amounts reflect a reclassification of 18 thousand meters from residential to small business to conform to current presentation.

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Revenue and Commodity Hedging and Trading Activities

	Three Months Ended September 30,						% Change		Nine Months Ended September 30,						% Change
	2009			2008					2009			2008
Operating revenues:
Retail electricity revenues:
Residential	$	1,272		$	1,258		1.1		$	3,048		$	2,966		2.8
Small business (a)		366			335		9.3			924			852		8.5
Large business and other customers		330			447		(26.2	)		955			1,143		(16.4	)
Total retail electricity revenues		1,968			2,040		(3.5	)		4,927			4,961		(0.7	)
Wholesale electricity revenues (b)		380			1,134		(66.5	)		1,043			2,797		(62.7	)
Net sales (purchases) of balancing electricity to/from ERCOT		(5	)		(44	)	—			(50	)		(227	)	—
Amortization of intangibles (c)		20			26		(23.1	)		10			(15	)	—
Other operating revenues		70			102		(31.4	)		214			293		(27.0	)
Total operating revenues	$	2,433		$	3,258		(25.3	)	$	6,144		$	7,809		(21.3	)
Commodity hedging and trading activities:
Unrealized net gains (losses) from changes in fair value	$	136		$	6,068		—		$	1,026		$	(237	)	—
Unrealized net gains (losses) representing reversals of previously recognized fair values of positions settled in the current period		(116	)		20		—			(257	)		(68	)	—
Realized net gains (losses) on settled positions		103			(43	)	—			234			57		—
Total gain (loss)	$	123		$	6,045		—		$	1,003		$	(248	)	—

(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 September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reported in revenues	$	(11	)	$	76		$	(135	)	$	155
Reported in fuel and purchased power costs		(6	)		(22	)		79			(71	)
Net gain (loss)	$	(17	)	$	54		$	(56	)	$	84

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

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Production, Purchased Power and Delivery Cost Data

	Three Months Ended September 30,						% Change		Nine Months Ended September 30,						% Change
	2009			2008					2009			2008
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	28		$	25		12.0		$	86		$	69		24.6
Lignite/coal		175			172		1.7			474			485		(2.3	)
Total baseload fuel		203			197		3.0			560			554		1.1
Natural gas fuel and purchased power (a)		431			1,161		(62.9	)		953			2,532		(62.4	)
Amortization of intangibles (b)		84			87		(3.4	)		224			246		(8.9	)
Other costs		39			94		(58.5	)		145			304		(52.3	)
Fuel and purchased power costs		757			1,539		(50.8	)		1,882			3,636		(48.2	)
Delivery fees		430			384		12.0			1,105			1,010		9.4
Total	$	1,187		$	1,923		(38.3	)	$	2,987		$	4,646		(35.7	)
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	5.42		$	4.88		11.1		$	5.55		$	4.75		16.8
Lignite/coal (c)		16.53			15.39		7.4			16.49			15.83		4.2
Natural gas fuel and purchased power		47.99			104.02		(53.9	)		44.06			91.55		(51.9	)
Delivery fees per MWh	$	26.68		$	24.77		7.7		$	27.77		$	25.69		8.1
Production and purchased power volumes (GWh):
Nuclear		5,219			4,996		4.5			15,512			14,448		7.4
Lignite/coal		12,209			12,240		(0.3	)		32,914			33,697		(2.3	)
Total baseload generation		17,428			17,236		1.1			48,426			48,145		0.6
Natural gas-fueled generation		1,135			2,124		(46.6	)		2,168			3,843		(43.6	)
Purchased power		7,890			9,042		(12.7	)		19,523			23,816		(18.0	)
Total energy supply		26,453			28,402		(6.9	)		70,117			75,804		(7.5	)
Line loss and power imbalances (d)		370			408		(9.3	)		796			2,704		(70.6	)
Net energy supply volumes		26,083			27,994		(6.8	)		69,321			73,100		(5.2	)
Baseload capacity factors (%):
Nuclear		103.1	%		98.4	%	4.8			103.1	%		95.6	%	7.8
Lignite/coal		94.0	%		95.0	%	(1.1	)		85.9	%		87.7	%	(2.1	)
Total baseload		96.6	%		95.9	%	0.7			90.7	%		89.9	%	0.9

(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 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.

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

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Financial Results

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Operating revenues decreased $825 million, or 25%, to $2.4 billion in 2009.

Wholesale electricity revenues decreased $754 million, or 66%, as compared to 2008, when wholesale revenues increased 93%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 55% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove a 19% decrease in sales volumes. Realized gains in 2009 on hedging activities mitigated the effect of lower wholesale electricity prices (see discussion of results from commodity hedging and trading activities below).

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

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

Retail electricity revenues declined $72 million, or 4%, to $1.968 billion in 2009 and reflected the following:

• Lower average pricing contributed $154 million to the revenue decline, driven by the contract business market and also reflecting lower residential pricing. Lower average pricing reflected declines in wholesale electricity prices. In July 2009, the company announced retail residential price reductions of as much as 15% applicable to over 250,000 existing customers on month-to-month plans as well as reductions on offerings for new customers. The price reductions were effective in August 2009.

• A four percent increase in retail sales volumes increased revenues by $82 million, reflecting increases in both the residential and business markets. Higher residential volumes reflected the effect of Hurricane Ike in 2008 and warmer weather in south Texas, while the higher business markets volume reflected customer mix changes.

• Total retail electricity customer counts at September 30, 2009 decreased two percent from September 30, 2008 driven by a two percent decrease in the residential markets and reflecting competitive activity.

Other operating revenues decreased $32 million, or 31%, to $70 million in 2009 due to the effect of lower natural gas prices and lower volumes on sales of natural gas to industrial customers.

The change in operating revenues also reflected a $6 million decrease in amortization of intangible assets arising in purchase accounting.

Fuel, purchased power costs and delivery fees decreased $736 million, or 38%, to $1.2 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($182 million) and the effect of lower natural gas prices and volumes on natural gas purchased for sale to industrial customers ($34 million).

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Overall baseload generation production increased one percent in 2009 reflecting a five percent increase in nuclear production, partially offset by a small decrease in lignite/coal-fueled production. The increase in nuclear production, which reflects a refueling outage in 2008, resulted in improved margin.

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

Three Months Ended September 30, 2009 — Unrealized mark-to-market net gains totaling $20 million included:

• $4 million in net losses related to hedge positions, which includes $121 million in net gains from changes in fair value driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $125 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

• $24 million in net gains related to trading positions, which includes $15 million in net gains from changes in fair value and $9 million in net gains that represent reversals of previously recorded net losses on positions settled in the period.

Realized net gains totaling $103 million include:

• $110 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

• $7 million in net losses related to trading positions.

Three Months Ended September 30, 2008 — Unrealized mark-to-market net gains totaling $6.088 billion include:

• $6.091 billion in net gains related to hedge positions, which includes $6.074 billion in net gains from changes in fair value and $17 million in net gains that represent reversals of previously recorded net losses on positions settled in the period. The net gains from changes in fair value were driven by the effect of decreases in natural gas prices in forward periods on the value of positions in the long-term hedging program;

• $10 million in “day one” losses related to large hedge positions (see Note 7 to Financial Statements), and

• $7 million in net gains related to trading positions, which includes $4 million in net gains from changes in fair value and $3 million in net gains that represent reversals of previously recorded net losses on positions settled in the period.

Realized net losses totaling $43 million include:

• $105 million in net losses related to hedge positions that primarily offset hedged electricity revenues recognized in the period, and

• $62 million in net gains related to trading positions.

Operating costs increased $3 million, or 2%, to $161 million in 2009. The increase reflected $6 million in operational readiness costs in preparation for new lignite-fueled generation facilities start-up and $6 million in increased normal baseload maintenance costs in 2009, partially offset by $6 million in 2008 maintenance costs incurred for a planned nuclear generation unit outage and $3 million in lower costs in 2009 due to natural gas-fueled generation unit retirements.

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Depreciation and amortization increased $7 million, or 2%, to $303 million in 2009. The increase was driven by $11 million in higher amortization expense related to the intangible asset representing retail customer relationships recorded in purchase accounting. Lower natural gas generation unit depreciation resulting from an impairment in 2008 was substantially offset by increased lignite generation unit depreciation as a result of normal capital additions as well as adjustments to useful lives of components.

SG&A expenses increased $20 million, or 12%, to $192 million in 2009 driven by a $19 million increase in retail bad debt expense. The increase in bad debt expense primarily reflects higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions.

Other income totaled $33 million in 2009 and $2 million in 2008. The 2009 amount included a $23 million reversal of a use tax accrual (see Note 12 to Financial Statements) and a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement. Other deductions totaled $6 million in 2009 and $531 million in 2008. The 2008 other deductions amount includes $499 million in impairment charges related to NO_x and SO₂ environmental allowances intangible assets and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 12 to Financial Statements for more details.

Interest expense and related charges increased $195 million, or 30%, to $842 million in 2009 reflecting a $138 million unrealized mark-to-market net loss in 2009 compared to a $36 million net gain in 2008 related to interest rate swaps and a $39 million increase in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008, partially offset by $14 million in lower amortization of discount and debt issuance costs and $6 million in increased capitalized interest.

Income tax benefit totaled $36 million in 2009 compared to income tax expense totaling $1.986 billion in 2008. The effective rates were 33.3% in 2009 and 35.6% in 2008. The decrease in the rate is primarily due to the effect of interest accrued for uncertain tax positions on a small loss in 2009.

Results declined by $3.7 billion to a loss of $72 million driven by the decrease in unrealized mark-to-market net gains related to commodity hedging activities and the unrealized mark-to-market net loss related to interest rate swaps in 2009 reported in interest expense and related charges, partially offset by the effect of impairment charges reported in other deductions in 2008.

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Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Operating revenues decreased $1.7 billion, or 21%, to $6.1 billion in 2009.

Wholesale electricity revenues decreased $1.8 billion, or 63%, as compared to 2008 when revenues increased 78%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 48% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove a 15% decline in wholesale sales volumes. Realized gains in 2009 on hedging activities mitigated the effect of lower wholesale electricity prices (see discussion of commodity hedging and trading activities below).

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

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

Retail electricity revenues declined $34 million, or 1%, to $4.927 billion and reflected the following:

• Lower average pricing contributed $103 million to the revenue decline. The change in average pricing reflected lower average contracted business rates driven by lower wholesale electricity prices, partially offset by higher average pricing in the residential and non-contract business markets resulting from advanced meter surcharges as well as customer mix.

• Retail sales volume growth of 1% increased revenues by $69 million. Volumes rose in both the residential and business markets.

Other operating revenues decreased $79 million, or 27%, to $214 million in 2009 due to the effect of lower natural gas prices and lower volumes on sales of natural gas to industrial customers.

The change in operating revenues also reflected a $25 million increase in amortization of intangible assets arising in purchase accounting.

Fuel, purchased power costs and delivery fees decreased $1.7 billion, or 36%, to $3.0 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($372 million), the effect of lower natural gas prices on natural gas purchased for sale to industrial customers ($111 million) and lower amortization of intangible assets arising in purchase accounting ($22 million).

Overall baseload generation production increased 1% in 2009 reflecting a seven percent increase in nuclear production, partially offset by a two percent decrease in lignite/coal-fueled production. The increase in nuclear production, which reflects a refueling outage in 2008, resulted in improved margin. The decrease in lignite/coal-fueled production reflected reductions during certain periods when power could be purchased in the wholesale market at prices below production costs, which was largely due to lower natural gas prices and higher wind generation availability, partially offset by lower maintenance and repair outages.

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

Nine Months Ended September 30, 2009 — Unrealized mark-to-market net gains totaling $769 million included:

• $750 million in net gains related to hedge positions, which includes $1.010 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $260 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

• $19 million in net gains related to trading positions, which includes $16 million in net gains from changes in fair value and $3 million in net gains that represent reversals of previously recorded net losses on positions settled in the period.

Realized net gains totaling $234 million included:

• $247 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

• $13 million in net losses related to trading positions.

Nine Months Ended September 30, 2008 — Unrealized mark-to-market net losses totaling $305 million included:

• $250 million in net losses related to hedge positions, which includes $248 million in net losses from changes in fair value and $2 million in net losses that represent reversals of previously recorded net gains on positions settled in the period;

• $69 million in “day one” net losses related to large hedge positions (see Note 7 to Financial Statements), and

• $13 million in net gains related to trading positions, which includes $79 million in net gains from changes in fair value and $66 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $57 million include:

• $76 million in net losses related to hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and

• $133 million in net gains related to trading positions.

Operating costs increased $3 million, or 1%, to $504 million in 2009. The increase reflected $21 million in higher maintenance costs incurred during planned and unplanned lignite-fueled generation unit outages in 2009 and $15 million in operational readiness costs incurred in preparation for new lignite-fueled generation facilities start-up, partially offset by the effect of $32 million in 2008 maintenance costs incurred for a planned nuclear generation unit outage.

Depreciation and amortization increased $35 million, or 4%, to $862 million in 2009. The increase was driven by $29 million in higher amortization expense related to the intangible asset representing retail customer relationships recorded in purchase accounting. Increased lignite generation unit depreciation as a result of normal capital additions as well as adjustments to useful lives of components was substantially offset by lower natural gas generation unit depreciation resulting from an impairment in 2008.

SG&A expenses increased $60 million, or 12%, to $555 million in 2009. The increase reflected $30 million in higher retail bad debt expense, reflecting higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions, $25 million in higher costs associated with the implementation of a new retail customer information management system and the transition of certain previously outsourced customer operations and $4 million in costs related to the nuclear generation development joint venture.

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See Note 2 to Financial Statements for discussion of the additional impairment of goodwill of $70 million in 2009.

Other income totaled $38 million in 2009 and $8 million in 2008. The 2009 amount included a $23 million reversal of a use tax accrual (see Note 12 to Financial Statements) and a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement. Other deductions totaled $19 million in 2009 and $550 million in 2008. The 2009 amount includes charges for severance and other individually immaterial miscellaneous expenses. The 2008 amount includes $501 million in impairment charges related to NOx and SO2 environmental allowances intangible assets and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 12 to Financial Statements for more details.

Interest expense and related charges decreased $410 million, or 21%, to $1.5 billion in 2009. The decrease reflected $491 million in higher unrealized mark-to-market net gains related to interest rate swaps and $32 million in increased capitalized interest, partially offset by $123 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008.

Income tax expense totaled $259 million in 2009 compared to an income tax benefit totaling $493 million in 2008. The effective rate was 42.7% on income in 2009 and 34.3% on a loss in 2008. The increase in the rate reflects the impacts of the non-deductible goodwill impairment in 2009, which added 4 percentage points to the effective rate, and the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.

Results improved $1.3 billion to net income of $347 million in 2009 driven by the change in unrealized mark-to-market results related to commodity hedging activities, the 2008 impairment charges reported in other deductions related to environmental allowances intangible assets and the unrealized mark-to-market net gains related to interest rate swaps reported in interest expense.

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2009. The net change in these assets and liabilities totaling $712 million, excluding “other activity” as described below, represents the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 7 to Financial Statements). These positions represent both economic hedging and trading activities.

	Nine Months Ended September 30, 2009
Commodity contract net asset at beginning of period	$	430
Settlements of positions (a)		(314	)
Unrealized mark-to-market valuations due to changes in fair value (b)		1,026
Other activity (c)		63
Commodity contract net asset at end of period (d)	$	1,205

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

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

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

(d) Amount excludes $12 million in net derivative liabilities related to instruments not marked-to-market in net income.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Unrealized gains/(losses) related to contracts marked-to-market	$	3	$	6,142	$	712	$	(217	)
Ineffectiveness gains/losses related to cash flow hedges		—		—		1		(4	)
Total unrealized gains (losses) related to commodity contracts	$	3	$	6,142	$	713	$	(221	)

Maturity Table — Following are the components of the net commodity contract asset at September 30, 2009:

	Amount
Net commodity contract asset	$	1,205
Net asset associated with receipts of natural gas under physical gas exchange transactions		4
Amount of net asset arising from mark-to-market accounting	$	1,209

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

	Maturity dates of unrealized net commodity contract asset at September 30, 2009
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(12	)	$	(80	)	$	(2	)	$	—		$	(94	)
Prices provided by other external sources		704			572			56			—			1,332
Prices based on models		(10	)		(29	)		140			(130	)		(29	)
Total	$	682		$	463		$	194		$	(130	)	$	1,209
Percentage of total fair value		57	%		38	%		16	%		(11	)%		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 8 to Financial Statements for fair value disclosures and discussion of fair value measurements.

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FINANCIAL CONDITION — LIQUIDITY AND CAPITAL RESOURCES

Consolidated Cash Flows — Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Cash provided by operating activities for the nine months ended September 30, 2009 totaled $1.471 billion compared to cash provided of $865 million in the nine months ended September 30, 2008. The increase in cash provided of $606 million reflected:

• a $496 million favorable change in margin deposits primarily due to the effect of lower forward natural gas prices on positions in the long-term hedging program, and

• a $131 million decrease in cash interest paid driven by the payment of $98 million of interest with new notes instead of cash as discussed under “PIK Interest Election” below.

Cash provided by financing activities decreased $2.627 billion as summarized below and reflected lower borrowings to support margin deposits:

	Nine Months Ended September 30,
	2009			2008
Net issuances, repayments and repurchases of borrowings	$	270		$	2,906
Decrease in income tax related note payable to Oncor (see Note 11 to Financial Statements)		(26	)		(25	)
Contributions from noncontrolling interests		42			—
Other		1			33
Total provided by financing activities	$	287		$	2,914
Cash used in investing activities decreased $639 million as summarized below:
	Nine Months Ended September 30,
	2009			2008
Net (loans to) repayments from affiliates	$	(528	)	$	(381	)
Capital expenditures, including nuclear fuel		(1,263	)		(1,514	)
Money market fund redemptions (investments)		142			(242	)
Change in restricted cash		118			9
Other		48			6
Total used in investing activities	$	(1,483	)	$	(2,122	)

The decline in capital spending for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008 primarily reflected a decrease in spending related to the construction of new generation facilities, which is nearing completion.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $445 million and $335 million for the nine months ended September 30, 2009 and 2008, respectively. The differences represent amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and delivery fees and interest expense and related charges. The differences also reflect the amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice. In addition, the differences reflect the amortization of losses on dedesignated cash flow hedges, which is reported in interest expense and related charges in the statement of income.

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Debt Financing Activity — Long-term borrowings for the nine months ended September 30, 2009 totaled $522 million consisting of borrowings under the TCEH Delayed Draw Term Loan Facility to fund capital expenditures principally related to the construction of the new generation facilities. Retirements for the nine months ended September 30, 2009 totaled $217 million and included $65 million of a matured TCEH promissory note, $123 million repaid under the TCEH Initial Term Loan Facility and other repayments totaling $29 million, principally related to capitalized leases. These issuances do not include the $98 million of TCEH Toggle Notes and $75 million of EFH Corp. Toggle Notes pushed down to EFC Holdings that were issued in May 2009 in payment of accrued interest as discussed below under “PIK Interest Election.”

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

EFC Holdings or its affiliates may from time to time purchase their outstanding debt securities for cash in open market purchases or privately negotiated transactions, or may refinance existing debt securities. EFC Holdings or its affiliates will evaluate any such transactions in light of market prices of the securities, taking into account liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. See Note 4 to Financial Statements for discussion of debt exchange offers announced by EFH Corp. and certain of its subsidiaries in October 2009.

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

	Available Liquidity
	September 30, 2009		December 31, 2008		Change
Cash and cash equivalents	$	754	$	479	$	275
Investments held in money market fund		—		142		(142	)
TCEH Delayed Draw Term Loan Facility		—		522		(522	)
TCEH Revolving Credit Facility (a)		1,736		1,767		(31	)
TCEH Letter of Credit Facility		459		490		(31	)
Subtotal	$	2,949	$	3,400	$	(451	)
Short-term investment (b)		65		—		65
Total liquidity (c)	$	3,014	$	3,400	$	(386	)

(a) As of September 30, 2009 and December 31, 2008, the TCEH Revolving Credit Facility includes $141 million and $144 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender.

(b) Represents $65 million in letters of credit posted related to certain interest rate swaps transactions. This collateral will be returned no later than March 2010. See Note 7 to Financial Statements.

(c) Pursuant to PUCT rules, TCEH is required to maintain available liquidity to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at September 30, 2009, the total availability under the TCEH credit facilities should be further reduced by $237 million. See “Regulation and Rates – Certification of REPs.

Note: Available liquidity above does not include the amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from November 2009 through November 2012 could add approximately $948 million and $615 million of liquidity, respectively.

The $386 million decrease in available liquidity, after taking into account the short-term investment, was driven by capital spending to construct the new generation facilities, as well as an increase in notes receivable from EFH Corp.

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

Long-Term Contractual Obligations and Commitments — In the nine months ended September 30, 2009, EFC Holdings entered into contractual obligations for fuel for its generation facilities totaling approximately $320 million to purchase nuclear fuel in periods between 2010 and 2020 and totaling approximately $153 million to purchase coal in periods between 2010 and 2012.

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PIK 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. 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. EFH Corp. and TCEH elected to do so for the May 2009, November 2009 and May 2010 interest payments as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy and related lower electricity demand and the continuing uncertainty in the financial markets. 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 2009 interest payment and will make its November 2009 and May 2010 interest payments by using the PIK feature of the EFH Corp. Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the EFH Corp. Toggle Notes by $150 million in May 2009 and will further increase the aggregate principal amount of the EFH Corp. Toggle Notes by $159 million in November 2009 and by $169 million in May 2010. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $141 million and will further increase liquidity as of November 1, 2009 and May 1, 2010 by an amount equal to approximately $149 million and $158 million, respectively, with such amounts constituting the amount of cash interest that otherwise would have been payable on the respective dates, and will increase the expected annual cash interest expense by approximately $54 million (50% of which relates to EFC Holdings due to push down), constituting the additional cash interest that will be payable with respect to the $478 million of additional toggle notes.

See Note 4 to Financial Statements for discussion of debt exchange offers that may result in redemption of portions of the outstanding principal amount of these notes, a reduction of the effect of the PIK election for the May 2010 interest payment discussed immediately below and the new notes offered by EFH Corp. in the exchange offers that would be subject to debt push down.

Similarly, TCEH made its May 2009 interest payment and will make its November 2009 and May 2010 interest payments by using the PIK feature of the TCEH Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the TCEH Toggle Notes by approximately $98.5 million in May 2009 and will further increase the aggregate principal amount of the TCEH Toggle Notes by approximately $104 million in November 2009 and $110 million in May 2010. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $92 million and will further increase liquidity as of November 1, 2009 and May 1, 2010 by an amount equal to approximately $97 million and $103 million, respectively, with such amounts constituting the amount of cash interest that otherwise would have been payable on the respective dates, and will increase the expected annual cash interest expense by approximately $33 million, constituting the additional cash interest that will be payable with respect to the $312 million of additional toggle notes.

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

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

• $151 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $317 million posted as of December 31, 2008;

• $497 million in cash has been received from counterparties, net of $7 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $402 million received, net of $122 million in cash posted, as of December 31, 2008;

• $360 million in letters of credit have been posted with counterparties, as compared to $342 million posted as of December 31, 2008, and

• $10 million in letters of credit have been received from counterparties, as compared to $30 million received as of December 31, 2008.

In addition, EFH Corp. (parent) elected to post cash collateral of $400 million in 2009 related to certain TCEH interest rate and commodity hedge transactions (see Note 7 to Financial Statements).

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 September 30, 2009, restricted cash collateral was less than $1 million. See Note 12 to Financial Statements regarding restricted cash.

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

Sale of Accounts Receivable — TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards. 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 special purpose entities established by financial institutions. 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 $700 million and $416 million at September 30, 2009 and December 31, 2008, respectively. See Note 3 to Financial Statements for a more complete description of the program including the impact of the program on the financial statements for the periods presented and the contingencies that could result in a reduction of funding available under the program.

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

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

Adjusted EBITDA (as used in the maintenance covenant contained in the indenture governing the TCEH Senior Notes) for the twelve months ended September 30, 2009 totaled $3.6 billion for TCEH. See Exhibit 99(b) and 99(c) for a reconciliation of net income to Adjusted EBITDA for TCEH and EFH Corp., respectively, for the nine and twelve months ended September 30, 2009 and 2008.

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

	September 30, 2009	December 31, 2008	Threshold Level
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to adjusted EBITDA ratio	4.68 to 1.00	4.77 to 1.00	Must not exceed 7.25 to 1.00
Debt Incurrence Covenants:
EFH Corp. Senior Notes:
EFH Corp. fixed charge coverage ratio	1.6 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (a)	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (a)	1.6 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	7.0 to 1.0	6.9 to 1.0	Equal to or less than 7.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to adjusted EBITDA ratio	8.4 to 1.0	8.7 to 1.0	At least 6.5 to 1.0

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

Credit Ratings — The issuer credit ratings as of October 5, 2009 for EFC Holdings and its subsidiaries are CC, Caa1 and B by S&P, Moody’s and Fitch, respectively.

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Additionally, the rating agencies assign credit ratings on certain of EFC Holdings’ debt securities. The credit ratings assigned for debt securities issued by EFC Holdings and certain of its subsidiaries and by EFH Corp. that are guaranteed by EFC Holdings as of October 5, 2009 are presented below:

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

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

(b) TCEH Cash-Pay Notes and TCEH Toggle Notes. S&Ps ratings of the TCEH Cash-Pay Notes and the TCEH Toggle Notes are CC and CCC, respectively.

In October 2009, both S&P and Moody’s announced rating actions related to their view that the debt exchange transaction announced by EFH Corp. in October 2009 represented a “distressed exchange.” As a result, S&P downgraded the corporate issuer ratings of EFH Corp., EFC Holdings and TCEH by four notches to CC from B- and affirmed their negative outlook. S&P also completed multi-notch downgrades of its ratings on issuances subject to the exchange to CC. Moody’s affirmed its Caa1 corporate family ratings and negative outlook for EFH Corp. and TCEH but downgraded its probability of default rating for EFH Corp. and TCEH three notches to Ca from Caa1. Additionally, Moody’s downgraded its ratings on certain issuances subject to the exchange and placed the ratings of TCEH Cash-Pay Notes on review for possible downgrade. S&P and Moody’s have indicated that shortly after settlement of the debt exchange transaction they expect to replace these temporary “distressed exchange” ratings with new ratings based on their analysis of the outcome of the exchange. Fitch affirmed their ratings and outlook for EFH Corp., EFC Holdings and TCEH.

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

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 September 30, 2009, counterparties to those contracts could have required TCEH to post up to an aggregate of $44 million in additional collateral. This amount largely represents the below market terms of these contracts as of September 30, 2009; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of September 30, 2009, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $28 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 September 30, 2009, TCEH maintained availability under its credit facilities of approximately $237 million. See “Regulation and Rates – Certification of REPs.”

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

ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $38 million as of September 30, 2009 (which is subject to weekly adjustments based on settlement activity with ERCOT).

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

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

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

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

A default by TCEH or any restricted subsidiary in respect of indebtedness, excluding indebtedness relating to the sale of receivables program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities such a default may cause the maturity of outstanding balances ($22.356 billion at September 30, 2009) under such facilities to be accelerated.

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

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

Under the terms of a TCEH rail car lease, which had approximately $54 million in remaining lease payments as of September 30, 2009 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements have been accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

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

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the 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.

EFC Holdings and its subsidiaries enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if EFC Holdings or those subsidiaries 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 $1.39 billion at September 30, 2009 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

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

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

OFF–BALANCE SHEET ARRANGEMENTS

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

Also see Note 5 to Financial Statements regarding guarantees.

COMMITMENTS AND CONTINGENCIES

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

CHANGES IN ACCOUNTING STANDARDS

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

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REGULATION AND RATES

Regulatory Investigations and Reviews

See Note 5 to Financial Statements.

Certification of REPs

In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule is considered a competition rule and thus is subject to judicial review as specified in PURA. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the rule, REPs are required to amend their certifications, including the manner in which they meet financial requirements, by May 21, 2010. TXU Energy plans to file its amended certification no later than the first quarter 2010. Under the new financial requirements, which will be effective upon approval of the amended certification, as of September 30, 2009, the amount of additional available liquidity required to be maintained by TCEH would have been reduced from $237 million to approximately $93 million as a result of no longer having to reserve liquidity for payments related to TDUs.

Wholesale Market Design

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

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

• operate a voluntary day-ahead energy market;

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

• use nodal energy prices for resources;

• provide information for energy trading hubs by aggregating nodes;

• use zonal prices for loads, and

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

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

ERCOT imposes a surcharge on all Qualified Scheduling Entities in the ERCOT market (including subsidiaries of TCEH) for the purpose of financing 38% of ERCOT’s expected nodal implementation costs. In November 2008, ERCOT filed a request with the PUCT for approval of an interim increase in the nodal surcharge from $0.169 per MWh to $0.375 per MWh. In September 2009, the PUCT approved an increase in the nodal surcharge to $0.375 per MWh, effective January 1, 2010. At the approved $0.375 per MWh nodal surcharge, the annual surcharge will be an estimated $30 million to $35 million, which is reported in fuel, purchased power costs and delivery fees. The implementation of a nodal market is still scheduled for December 2010. EFC Holdings cannot predict the ultimate impact of the proposed nodal wholesale market design on its operations or financial results.

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Summary

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that EFC Holdings 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. EFC Holdings’ exposure to market risk is affected by a number of factors, including the size, duration and composition of its energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interest rate risk related to indebtedness, as well as exchange traded, over-the-counter contracts and other contractual arrangements to manage commodity price risk as part of wholesale activities.

Risk Oversight

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

EFH Corp. has 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 EFC Holdings’ businesses and their associated transactions.

Commodity Price Risk

TCEH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. The company, similar to other participants in the market, cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads (differences between the market price of electricity and its cost of production).

In managing energy price risk, TCEH enters into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. The company continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. The company strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

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

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

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

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

	Nine Months Ended September 30, 2009		Year Ended December 31, 2008
Month-end average Trading VaR:	$	4	$	6
Month-end high Trading VaR:	$	7	$	15
Month-end low Trading VaR:	$	2	$	2

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

	Nine Months Ended September 30, 2009		Year Ended December 31, 2008
Month-end average MtM VaR:	$	1,034	$	2,290
Month-end high MtM VaR:	$	1,470	$	3,549
Month-end low MtM VaR:	$	638	$	1,087

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

	Nine Months Ended September 30, 2009		Year Ended December 31, 2008
Month-end average EaR:	$	1,034	$	2,300
Month-end high EaR:	$	1,450	$	3,916
Month-end low EaR:	$	676	$	1,069

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

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Interest Rate Risk

As of September 30, 2009, the potential reduction of annual pretax earnings due to a one percentage point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $31 million, taking into account the interest rate swaps discussed in Note 4 to Financial Statements.

Credit Risk

Credit Risk — Credit risk relates to the risk of loss associated with nonperformance by counterparties. EFC Holdings and its subsidiaries maintain credit risk policies with regard to their 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. EFC Holdings has processes for monitoring and managing credit exposure of its 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, the company has 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 — EFC Holdings’ gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $1.783 billion at September 30, 2009. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of September 30, 2009 include $1.074 billion in accounts receivable from the retail sale of electricity to residential and business customers. Cash deposits held as collateral for these receivables totaled $93 million at September 30, 2009. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

The remaining credit exposure arises from wholesale energy sales and hedging and trading activities. 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 September 30, 2009, the exposure to credit risk from these counterparties totaled $709 million taking into account the standardized master netting contracts and agreements described above but before taking into account $128 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $581 million decreased approximately $214 million in the nine months ended September 30, 2009, reflecting the netting and right of setoff related to certain interest rate and commodity hedging transactions under a new derivative agreement with a counterparty (see Note 7 to Financial Statements).

Of this $581 million net exposure, 97% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and TCEH’s internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. TCEH routinely monitors and manages credit exposure to these customers and counterparties on this basis.

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The following table presents the distribution of credit exposure as of September 30, 2009 arising from wholesale energy sales 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 and setoff provisions within each contract and any master netting contracts with counterparties. The amounts below do not include asset liens held as security for a portion of the net exposure.

									Net Exposure by Maturity
	Exposure Before Credit Collateral			Credit Collateral		Net Exposure			2 years or less		Between 2-5 years		Greater than 5 years			Total
Investment grade	$	688		$	127	$	561		$	659	$	29	$	(127	)	$	561
Noninvestment grade		21			1		20			20		—		—			20
Totals	$	709		$	128	$	581		$	679	$	29	$	(127	)	$	581
Investment grade		97	%				97	%
Noninvestment grade		3	%				3	%

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.

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

Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented 61% and 11% of the net $581 million exposure. Exposure to these counterparties is viewed to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of TCEH’s business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.

With respect to credit risk related to the long-term hedging program, over 99% of the transaction volumes are with counterparties with an A credit rating or better. However, 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 EFC Holdings. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through various ongoing risk management measures.

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by EFC Holdings 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 EFC Holdings expects or anticipates 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 its business and operations (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “projection,” “target,” “goal,” “objective” and “outlook”), are forward-looking statements. Although EFC Holdings believes that in making any such forward-looking statement its expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under “Risk Factors” in the 2008 Form 10-K and the following important factors, among others, that could cause the actual results of EFC Holdings 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;

• industry, market and rate structure;

• purchased power and recovery of investments;

• operations of nuclear generating facilities;

• operations of mines;

• acquisitions and disposal of assets and facilities;

• development, construction and operation of facilities;

• decommissioning costs;

• present or prospective wholesale and retail competition;

• changes in tax laws and policies, and

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

• legal and administrative proceedings and settlements;

• general industry trends;

• economic conditions, including the current recessionary environment;

• EFC Holdings’ ability to attract and retain profitable customers;

• EFC Holdings’ ability to profitably serve its 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;

• EFC Holdings’ 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 continued 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 EFH Holdings by its credit facilities and indentures governing its debt instruments;

• EFH Holdings’ ability to generate sufficient cash flow to make interest payments on its debt instruments;

• competition for new energy development and other business opportunities;

• inability of various counterparties to meet their obligations with respect to EFC Holdings’ financial instruments;

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• changes in technology used by and services offered by EFC Holdings;

• changes in electricity transmission that allow additional electricity generation to compete with EFC Holdings’ generation assets;

• significant changes in EFC Holdings’ relationship with its employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;

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

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

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• EFC Holdings’ ability to effectively execute its operational strategy;

• the ability of EFC Holdings to implement cost reduction initiatives, and

• with respect to the lignite coal-fueled generation construction and development program, more specifically, EFC Holdings’ 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, the ability of EFC Holdings and its contractors to attract and retain, at projected rates, skilled labor for constructing the new generating units, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, supplier performance risk, force majeure events, changes in the cost and availability of materials necessary for the construction program and the ability of EFC Holdings to manage the significant construction, commissioning and start-up program to a timely conclusion with limited cost overruns.

Any forward-looking statement speaks only as of the date on which it is made, and there is no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for EFC Holdings to predict all of them; nor can EFC Holdings assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

INDUSTRY AND MARKET INFORMATION

The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT or the PUCT. EFC Holdings did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from EFC Holdings’ 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 it believes that each of these studies and publications is reliable, EFC Holdings has not independently verified such data and makes no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and EFC Holdings does not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while EFC Holdings believes that its internal and external research is reliable, it has not been verified by any independent sources, and EFC Holdings makes no assurances that the predictions contained therein are accurate.

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Item 4. CONTROLS AND PROCEDURES.

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

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

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS.

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

Item 1A. RISK FACTORS.

There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the 2008 Form 10-K, except for the risk factor discussed below and the information discussed elsewhere in this Form 10-Q that provides factual updates to the risk factors contained in the 2008 Form 10-K.

EFC Holdings’ 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 it.

The Obama administration has proposed financial market reforms with respect to the currently unregulated Over-the-Counter (OTC) financial derivatives market. As a result, there are currently competing bills in the US House of Representatives that propose to regulate OTC derivatives. Certain of the proposals require entities to clear OTC derivatives that are currently traded on the bilateral market through exchanges, which require that all collateral be in the form of cash. EFC Holdings has entered into a significant number of asset-backed OTC derivatives to hedge risks associated with commodity and interest rate exposure. If this legislation were to be passed and be applicable to EFC Holdings so that it was required to clear its OTC derivatives through exchanges, EFC Holdings would likely be precluded from using its noncash assets as collateral for hedging arrangements. This preclusion could have a material impact on EFC Holdings’ liquidity, particularly if the final legislation does not provide for the grandfathering of existing OTC derivatives. As a result, if applied to EFC Holdings’ OTC derivatives transactions, this legislation could significantly increase its costs of entering into OTC derivatives and/or could significantly limit its ability to enter into OTC derivatives and hedge its commodity and interest rate risks. The most recent legislative developments in the US House of Representatives indicate a willingness to grandfather existing OTC derivatives and to exclude from the new clearing requirements swaps used for hedging purposes by end users. However, the proposed legislation is in the early stages of consideration, and EFC Holdings cannot predict whether or when the legislation will be enacted or whether these exemptions will be included in the final legislation.

76

Item 6. EXHIBITS

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

Exhibits	Previously Filed     With File Number*	As Exhibit
10	Material Contracts.
	Credit Agreements
10(a)	1-12833 Form 8-K (filed August 10, 2009)	10.1	—	Amendment No. 1, dated as of August 7, 2009, to the $24,500,000,000 Credit Agreement dated as of October 10, 2007 among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, as the Borrower, Citibank, N.A., as Administrative Agent, Goldman Sachs Credit Partners L.P. as Posting Agent, J. Aron & Company, as Posting Calculation Agent and the several lenders thereto from time to time.
10(b)	1-12833 Form 8-K (filed August 10, 2009)	10.2	—	Amended and Restated Collateral Agency and Intercreditor Agreement, dated as of October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary guarantors party thereto, Citibank, N.A., as administrative agent and collateral agent, Credit Suisse Energy LLC, J. Aron & Company, Morgan Stanley Capital Group Inc., Citigroup Energy Inc., and each other secured commodity hedge counterparty from time to time party thereto, and any other person that becomes a secured party pursuant thereto.
10(c)	1-12833 Form 8-K (filed August 10, 2009)	10.3	—	Amended and Restated Security Agreement, dated as of October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary grantors party thereto, and Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement.
10(d)	1-12833 Form 8-K (filed August 10, 2009)	10.4	—	Amended and Restated Pledge Agreement, dated as of October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary pledgors party thereto, and Citibank, N. A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement.
31	Rule 13a – 14(a)/15d – 14(a) Certifications.
31(a)			—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Company.
31(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Company.

77

Exhibits	Previously Filed     With File Number*	As Exhibit
32	Section 1350 Certifications.
32(a)			—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Company.
32(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Company.
(99)	Additional Exhibits.
99(a)			—	Condensed Statements of Consolidated Income (Loss) – Twelve Months Ended September 30, 2009.
99(b)			—	TCEH Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2009 and 2008.
99(c)			—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2009 and 2008.
99(d)			—	Texas Competitive Electric Holdings Company LLC Condensed Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008 and related Condensed Statements of Consolidated Income (Loss) and Comprehensive Income (Loss) for the three and nine month periods ended September 30, 2009 and 2008 and Cash Flows for the nine-month periods ended September 30, 2009 and 2008.

* 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 thereunto duly authorized.

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

Date: October 29, 2009

79

Exhibit 99(a)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Twelve Months Ended September 30, 2009
Operating revenues	$	8,122
Fuel, purchased power and delivery fees		(3,941	)
Net gain from commodity hedging and trading activities		3,435
Operating costs		(680	)
Depreciation and amortization		(1,127	)
Selling, general and administrative expenses		(740	)
Franchise and revenue-based taxes		(110	)
Impairment of goodwill		(8,070	)
Other income		65
Other deductions		(732	)
Interest income		54
Interest expense and related charges		(3,777	)
Loss before income taxes		(7,501	)
Income tax expense		(248	)
Net loss		(7,749	)
Net (income) loss attributable to noncontrolling interests		—
Net loss attributable to EFC Holdings	$	(7,749	)

Exhibit 99(b)

TCEH Consolidated

Adjusted EBITDA Reconciliation

(millions of dollars)

	Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2008			Twelve Months Ended September 30, 2009			Twelve Months Ended September 30, 2008
Net income (loss)	$	493		$	(811	)	$	(7,559	)	$	(1,956	)
Income tax expense (benefit)		330			(425	)		343			(1,010	)
Interest expense and related charges		1,331			1,756			3,492			2,356
Depreciation and amortization		862			827			1,127			1,150
EBITDA	$	3,016		$	1,347		$	(2,597	)	$	540
Interest income		(40	)		(45	)		(55	)		(66	)
Amortization of nuclear fuel		71			55			93			74
Purchase accounting adjustments (a)		224			290			347			424
Impairment of goodwill		70			—			8,070			—
Impairment of assets and inventory write down (b)		2			502			710			502
EBITDA amount attributable to consolidated unrestricted subsidiaries		3			—			3			—
Unrealized net (gain) loss resulting from hedging transactions		(713	)		221			(3,263	)		1,796
Amortization of “day one” net loss on Sandow 5 power purchase agreement		(7	)		—			(7	)		—
Corporate depreciation, interest and income tax expenses included in SG&A expense		5			—			5			—
Losses on sale of receivables		9			22			17			33
Noncash compensation expense (c)		1			8			3			8
Severance expense (d)		9			1			10			1
Transition and business optimization costs (e)		22			30			26			39
Transaction and merger expenses (f)		3			1			12			1
Insurance settlement proceeds (g)		—			—			(21	)		—
Restructuring and other (h)		(15	)		32			(15	)		34
Expenses incurred to upgrade or expand a generation station (i)		100			100			100			100
Adjusted EBITDA per Incurrence Covenant	$	2,760		$	2,564		$	3,438		$	3,486
Expenses related to unplanned generation station outages (i)		61			218			93			209
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (j)		21			8			28			9
Adjusted EBITDA per Maintenance Covenant	$	2,842		$	2,790		$	3,559		$	3,704

(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting.

(b) Impairment of assets includes impairments of emission allowances and trade name intangible assets and impairment of the natural gas-fueled generation fleet.

(c) Non-cash compensation expenses are accounted for under accounting standards related to stock compensation and exclude capitalized amounts.

(d) Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts.

(e) Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation.

(f) Transaction and merger expenses include costs related to the Merger, outsourcing transition costs and costs related to certain growth initiatives.

(g) Insurance settlement proceeds include the amount received for property damage to certain mining equipment.

(h) Restructuring and other for the twelve months ended September 30, 2008 includes a charge related to the bankruptcy of a subsidiary of Lehman Brothers Holdings Inc. and other restructuring initiatives and nonrecurring activities.

(i) Expenses incurred to upgrade or expand a generation station reflect noncapital outage costs.

(j) Primarily pre-operating expenses relating to Oak Grove and Sandow 5. 2008 amounts were not previously available.

Exhibit 99(c)

Energy Future Holdings Corp.

Adjusted EBITDA Reconciliation

(millions of dollars)

	Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2008			Twelve Months Ended September 30, 2009			Twelve Months Ended September 30, 2008
Net income (loss) attributable to EFH Corp.	$	207		$	(983	)	$	(8,648	)	$	(2,235	)
Income tax expense (benefit)		254			(462	)		245			(1,038	)
Interest expense and related charges		2,136			2,505			4,566			3,371
Depreciation and amortization		1,286			1,217			1,679			1,654
EBITDA	$	3,883		$	2,277		$	(2,158	)	$	1,752
Oncor EBITDA		(1,043	)		(1,053	)		(488	)		(1,338	)
Oncor distributions/dividends (a)		117			213			1,487			288
Interest income		(30	)		(22	)		(35	)		(49	)
Amortization of nuclear fuel		71			55			93			74
Purchase accounting adjustments (b)		259			325			394			463
Impairment of goodwill		90			—			8,090			—
Impairment of assets and inventory write down (c)		5			512			715			457
Net income attributable to noncontrolling interests		54			—			(106	)		—
EBITDA amount attributable to consolidated unrestricted subsidiaries		3			—			3			—
Unrealized net (gain) loss resulting from hedging transactions		(713	)		221			(3,263	)		1,796
Amortization of “day one” net loss on Sandow 5 power purchase agreement		(7	)		—			(7	)		—
Losses on sale of receivables		9			22			17			33
Income from discontinued operations, net of tax effect		—			—			—			(1	)
Noncash compensation expenses (d)		9			24			11			23
Severance expense (e)		9			1			10			1
Transition and business optimization costs (f)		22			38			29			47
Transaction and merger expenses (g)		65			44			84			107
Insurance settlement proceeds (h)		—			—			(21	)		—
Restructuring and other (i)		(10	)		32			(6	)		33
Expenses incurred to upgrade or expand a generation station (j)		100			100			100			100
Adjusted EBITDA per Incurrence Covenant	$	2,893		$	2,789		$	4,949		$	3,786
Add back Oncor adjustments		926			807			(148	)		1,014
Adjusted EBITDA per Restricted Payments Covenant	$	3,819		$	3,596		$	4,801		$	4,800

(a) Twelve months ended September 30, 2009 amount includes $1.253 billion distribution of net proceeds from the sale of Oncor noncontrolling interests in November 2008.

(b) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting.

(c) Impairment of assets includes impairments of emission allowances and trade name intangible assets, impairment of the natural gas-fueled generation fleet and charges related to the cancelled development of coal-fueled generation facilities.

(d) Non-cash compensation expenses are accounted for under accounting standards related to stock compensation and exclude capitalized amounts.

(e) Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts.

(f) Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation.

(g) Transaction and merger expenses include costs related to the Merger and abandoned strategic transactions. Also include outsourcing transition costs, administrative costs related to the cancelled program to develop coal-fueled generation facilities, the Sponsor management fee, costs related to certain growth initiatives and costs related to the Oncor sale of noncontrolling interests.

(h) Insurance settlement proceeds include the amount received for property damage to certain mining equipment.

(i) Restructuring and other for the twelve months ended September 30, 2008 includes a litigation accrual, a charge related to the bankruptcy of a subsidiary of Lehman Brothers Holdings Inc. and other restructuring initiatives and nonrecurring activities.

(j) Expenses incurred to upgrade or expand a generation station reflect noncapital outage costs.