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. 7 TO

MARKET MAKING PROSPECTUS DATED

MAY 4, 2010

THE DATE OF THIS SUPPLEMENT IS NOVEMBER 2, 2010

On October 29, 2010, 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, 2010

— 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  (Do not check if a smaller reporting company)    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 28, 2010: 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 (Unaudited)
	Condensed Statements of Consolidated Income (Loss) – Three and Nine Months Ended September 30, 2010 and 2009	1
	Condensed Statements of Consolidated Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2010 and 2009	2
	Condensed Statements of Consolidated Cash Flows – Nine Months Ended September 30, 2010 and 2009	3
	Condensed Consolidated Balance Sheets – September 30, 2010 and December 31, 2009	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	77
Item 4.	Controls and Procedures	83
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	83
Item 1A.	Risk Factors	83
Item 6.	Exhibits	84
SIGNATURE		87

Energy Future Competitive Holdings Company’s (EFCH) 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. EFCH also from time to time makes available to the public, free of charge, on the Energy Future Holdings Corp. website certain financial statements of its wholly-owned subsidiary, Texas Competitive Electric Holdings Company LLC. 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 EFCH 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 EFCH and its subsidiaries occasionally make references to EFH Corp., EFCH (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 vice versa.

i

GLOSSARY

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

2009 Form 10-K	EFCH’s Annual Report on Form 10-K for the year ended December 31, 2009
Adjusted EBITDA	Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain debt arrangements of TCEH and EFH Corp. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. EFCH is providing TCEH’s and EFH Corp.’s Adjusted EBITDA in this Form 10-Q (see reconciliations in Exhibits 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. EFCH 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, EFCH 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, EFCH’s presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
baseload	Refers to the minimum constant level of electricity demand in a system, such as ERCOT, and/or to the electricity generation facilities or capacity normally expected to operate continuously throughout the year to serve such demand, such as EFCH’s nuclear and lignite/coal-fueled generation units.
EBITDA	Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.
EFCH	Refers to Energy Future Competitive Holdings Company, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its 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. 10.875% Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).
EFH Corp. Senior Secured Notes	Refers collectively to EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019 (EFH Corp. 9.75% Notes) and EFH Corp.’s 10.000% Senior Secured Notes due January 15, 2020 (EFH Corp. 10% Notes).
EFIH	Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.

ii

EFIH Finance	Refers to EFIH Finance Inc., a direct, wholly-owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities.
EFIH Notes	Refers collectively to EFIH’s and EFIH Finance’s 9.75% Senior Secured Notes due October 15, 2019 (EFIH 9.75% Notes) and EFIH’s and EFIH Finance’s 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% 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
FERC	US Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GWh	gigawatt-hours
kWh	kilowatt-hours
Lehman	Refers to certain subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code in 2008.
LIBOR	London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.
Luminant	Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.

iii

Merger	The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.
Merger Agreement	Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.
MMBtu	million British thermal units
Moody’s	Moody’s Investors Services, Inc. (a credit rating agency)
MW	megawatts
MWh	megawatt-hours
NERC	North American Electric Reliability Corporation
NRC	US Nuclear Regulatory Commission
NYMEX	Refers to the New York Mercantile Exchange, a physical commodity futures exchange.
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 EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context.
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
purchase accounting	The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
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	Refers collectively to 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.)

iv

TCEH	Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy.
TCEH Finance	Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.
TCEH Senior Notes	Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 Series B (collectively, TCEH 10.25% Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).
TCEH Senior Secured Facilities	Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 4 to Financial Statements for details of these facilities.
TCEH Senior Secured Second Lien Notes	Refers collectively to TCEH’s 15% Senior Secured Second Lien Notes due April 1, 2021 and TCEH’s 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.
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.
TRE	Refers to Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols.
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
VIE	variable interest entity

v

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,
	2010			2009			2010			2009
Operating revenues	$	2,607		$	2,433		$	6,599		$	6,144
Fuel, purchased power costs and delivery fees		(1,400	)		(1,187	)		(3,521	)		(2,987	)
Net gain from commodity hedging and trading activities		992			123			2,272			1,003
Operating costs		(197	)		(161	)		(623	)		(504	)
Depreciation and amortization		(345	)		(303	)		(1,027	)		(862	)
Selling, general and administrative expenses		(183	)		(192	)		(546	)		(555	)
Franchise and revenue-based taxes		(24	)		(27	)		(72	)		(74	)
Impairment of goodwill (Note 2)		(4,100	)		—			(4,100	)		(70	)
Other income (Note 13)		6			33			95			38
Other deductions (Note 13)		(3	)		(6	)		(12	)		(19	)
Interest income		23			21			64			39
Interest expense and related charges (Note 13)		(905	)		(842	)		(2,718	)		(1,547	)
Income (loss) before income taxes		(3,529	)		(108	)		(3,589	)		606
Income tax (expense) benefit		(191	)		36			(188	)		(259	)
Net income (loss)		(3,720	)		(72	)		(3,777	)		347
Net (income) loss attributable to noncontrolling interests		—			—			—			—
Net income (loss) attributable to EFCH	$	(3,720	)	$	(72	)	$	(3,777	)	$	347

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,
	2010			2009			2010			2009
Net income (loss)	$	(3,720	)	$	(72	)	$	(3,777	)	$	347
Other comprehensive income (loss), net of tax effects:
Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of $—, $2, $— and $11)		—			(4	)		—			(20	)
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $7, $21, $25 and $53)		13			41			49			99
Total effect of cash flow hedges		13			37			49			79
Comprehensive income (loss)		(3,707	)		(35	)		(3,728	)		426
Comprehensive (income) loss attributable to noncontrolling interests		—			—			—			—
Comprehensive income (loss) attributable to EFCH	$	(3,707	)	$	(35	)	$	(3,728	)	$	426

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, 2010			Nine Months Ended September 30, 2009
Cash flows — operating activities:
Net income (loss)	$	(3,777	)	$	347
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization		1,272			1,167
Deferred income tax expense (benefit) — net		430			136
Noncash interest expense related to pushed down debt of Parent (Note 4)		202			131
Impairment of goodwill (Note 2)		4,100			70
Increase of toggle notes in lieu of cash interest (Note 4)		110			98
Net gain on sale of assets		(81	)		(1	)
Unrealized net gains from mark-to-market valuations of commodity positions		(1,615	)		(713	)
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps		542			(527	)
Losses on dedesignated cash flow hedges (interest rate swaps)		73			140
Bad debt expense (Note 3)		88			87
Stock-based incentive compensation expense		5			5
Reversal of use tax accrual (Note 13)		—			(23	)
Other, net		6			7
Changes in operating assets and liabilities:
Impact of accounts receivable securitization program (Note 3)		(383	)		284
Margin deposits — net		164			260
Other operating assets and liabilities		(142	)		3
Cash provided by operating activities		994			1,471
Cash flows — financing activities:
Issuances of long-term debt (Note 4)		—			522
Repayments of long-term debt (Note 4)		(243	)		(217	)
Net short-term borrowings under accounts receivable securitization program (Note 3)		228			—
Decrease in other short-term borrowings (Note 4)		(873	)		—
Notes/loans from affiliates		804			—
Decrease in income tax-related note payable to Oncor		(27	)		(26	)
Contributions from noncontrolling interests (Note 6)		24			42
Debt issuance costs		—			(35	)
Other, net		28			1
Cash provided by (used in) financing activities		(59	)		287
Cash flows — investing activities:
Net notes/loans to affiliates		(282	)		(528	)
Capital expenditures		(676	)		(1,106	)
Nuclear fuel purchases		(84	)		(157	)
Money market fund redemptions		—			142
Proceeds from sale of assets		141			40
Reduction of restricted cash related to letter of credit facility (Note 4)		—			115
Other changes in restricted cash		(31	)		3
Proceeds from sale of environmental allowances and credits		7			22
Purchases of environmental allowances and credits		(13	)		(23	)
Proceeds from sales of nuclear decommissioning trust fund securities		937			2,972
Investments in nuclear decommissioning trust fund securities		(949	)		(2,983	)
Other, net		(8	)		20
Cash used in investing activities		(958	)		(1,483	)
Net change in cash and cash equivalents		(23	)		275
Cash received from VIE		7			—
Cash and cash equivalents — beginning balance		94			479
Cash and cash equivalents — ending balance	$	78		$	754

See Notes to Financial Statements.

3

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)

	September 30, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	78		$	94
Restricted cash (Note 13)		31			1
Trade accounts receivable — net (2010 includes $885 in pledged amounts related to a VIE (Notes 3 and 11))		1,244			1,009
Notes receivable from parent (Note 12)		1,690			1,406
Inventories (Note 13)		388			393
Commodity and other derivative contractual assets (Note 9)		3,383			2,339
Accumulated deferred income taxes		47			1
Margin deposits related to commodity positions		196			187
Other current assets		42			46
Total current assets		7,099			5,476
Restricted cash (Note 13)		1,135			1,135
Receivable from affiliate (Note 12)		—			85
Investments (Note 13)		574			591
Property, plant and equipment — net (Note 13)		20,309			20,980
Goodwill (Note 2)		6,152			10,252
Identifiable intangible assets — net (Note 2)		2,437			2,593
Commodity and other derivative contractual assets (Note 9)		2,553			1,533
Other noncurrent assets, principally unamortized debt issuance costs		478			600
Total assets	$	40,737		$	43,245
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (2010 includes $228 related to a VIE (Notes 3 and 11))	$	308		$	953
Long-term debt due currently (Note 4)		242			302
Trade accounts payable		632			748
Trade accounts and other payables to affiliates		246			203
Notes payable to affiliate (Note 12)		806			—
Commodity and other derivative contractual liabilities (Note 9)		2,899			2,310
Margin deposits related to commodity positions		693			520
Accrued income taxes payable to parent (Note 12)		12			50
Accrued taxes other than income		103			75
Accrued interest		537			349
Other current liabilities		227			339
Total current liabilities		6,705			5,849
Accumulated deferred income taxes		5,918			5,467
Commodity and other derivative contractual liabilities (Note 9)		1,422			1,060
Notes or other liabilities due affiliates (Note 12)		372			217
Long-term debt held by affiliates (Note 12)		427			143
Long-term debt, less amounts due currently (Note 4)		30,098			31,978
Other noncurrent liabilities and deferred credits (Note 13)		2,237			2,749
Total liabilities		47,179			47,463
Commitments and Contingencies (Note 5)
Equity (Note 6):
EFCH shareholder’s equity		(6,521	)		(4,266	)
Noncontrolling interests in subsidiaries		79			48
Total equity		(6,442	)		(4,218	)
Total liabilities and equity	$	40,737		$	43,245

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

EFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas-based holding company that conducts its operations almost entirely 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, wholesale energy sales and purchases, commodity risk management and trading activities and retail electricity sales. Key management activities, including commodity risk management, are performed on an integrated basis; consequently, 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 2009 Form 10-K with the exception of the prospective adoption of amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 3 and the prospective adoption of amended guidance that requires reconsideration of consolidation conclusions for all variable interest entities (VIEs) that resulted in the consolidation of TXU Receivables Company. All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in the 2009 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities as of 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

As of January 1, 2010, EFCH adopted new FASB guidance that requires reconsideration of consolidation conclusions for all VIEs and other entities with which EFCH is involved. See Note 11 for discussion of EFCH’s evaluation of VIEs. There were no material effects on EFCH’s financial statements as a result of the adoption of this new guidance.

5

As of January 1, 2010, EFCH adopted new FASB 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. Accordingly, the trade accounts receivable amounts under the accounts receivable securitization program discussed in Note 3 are prospectively reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable. This new guidance does not impact the covenant-related ratio calculations in EFCH’s debt agreements.

2. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides the goodwill balances as of September 30, 2010 and the changes in such balances for the nine months ended September 30, 2010. None of the goodwill is being deducted for tax purposes.

As of January 1, 2010:
Goodwill before impairment charges	$	18,322
Accumulated impairment charges		(8,070	)
Balance as of January 1, 2010		10,252
Changes — nine months ended September 30, 2010:
Impairment charge		(4,100	)
As of September 30, 2010:
Goodwill before impairment charges		18,322
Accumulated impairment charges		(12,170	)
Balance as of September 30, 2010	$	6,152

Goodwill Impairment

In the third quarter 2010, EFCH recorded a $4.1 billion noncash goodwill impairment charge. The impairment charge reflected the estimated effect of lower wholesale power prices on the enterprise value of EFCH, driven by the sustained decline in forward natural gas prices, as indicated by EFCH’s cash flow projections and declines in market values of securities of comparable companies.

The calculation of the goodwill impairment involved the following steps: first, EFCH estimated the debt-free enterprise value of its business taking into account future estimated cash flows and current securities values of comparable companies; second, EFCH estimated the fair values of the individual operating assets and liabilities of its business; third, EFCH calculated “implied” goodwill as the excess of the estimated enterprise value over the estimated value of the net operating assets; and finally, EFCH compared the implied goodwill amount to the carrying value of goodwill and recorded an impairment charge for the amount the carrying value of goodwill exceeded implied goodwill.

The impairment determination involved significant assumptions and judgments. The calculations supporting the estimates of the enterprise value of TCEH and the fair values of certain of its operating assets and liabilities utilized models that take into consideration multiple inputs, including commodity prices, discount rates, debt yields, securities prices of comparable companies and other inputs, assumptions regarding each of which could have a significant effect on valuations. The fair value measurements resulting from these models are classified as non-recurring Level 3 measurements consistent with accounting standards related to the determination of fair value (see Note 7).

The goodwill impairment testing in the third quarter 2010 resulted from current market conditions, and the annual impairment testing required by accounting rules remains scheduled for December 1, 2010. EFCH cannot predict the likelihood or amount of any future impairment.

6

Identifiable Intangible Assets

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

	As of September 30, 2010						As of December 31, 2009
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	274	$	189	$	463	$	215	$	248
Favorable purchase and sales contracts		548		247		301		700		374		326
Capitalized in-service software		198		44		154		184		28		156
Environmental allowances and credits		994		282		712		992		212		780
Mining development costs		47		14		33		32		5		27
Total intangible assets subject to amortization	$	2,250	$	861		1,389	$	2,371	$	834		1,537
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization)						93						101
Total intangible assets					$	2,437					$	2,593

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

		Three Months Ended September 30,				Nine Months Ended September 30,
Identifiable Intangible Asset	Income Statement Line	2010		2009		2010		2009
Retail customer relationship	Depreciation and amortization	$	20	$	21	$	59	$	64
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees		1		18		25		91
Capitalized in-service software	Depreciation and amortization		6		5		17		11
Environmental allowances and credits	Fuel, purchased power costs and delivery fees		25		25		69		66
Mining development costs	Depreciation and amortization		3		1		8		2
Total amortization expense		$	55	$	70	$	178	$	234

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

Year	Amount
2010	$	240
2011		182
2012		146
2013		128
2014		113

7

3. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is an entity created for the special purpose of purchasing receivables from the originator and is a wholly-owned bankruptcy-remote direct subsidiary of EFH Corp. Effective January 1, 2010 TXU Receivables Company is consolidated by EFCH in accordance with amended consolidated accounting standards as discussed in Note 11. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. In accordance with the amended transfers and servicing accounting standard as discussed in Note 1, the trade accounts receivable amounts under the program are reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, TXU Receivables Company was not consolidated by EFCH, and the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable.

In June 2010, the accounts receivable securitization program was amended. The amendments, among other things, reduced the maximum funding amount under the program to $350 million from $700 million. Program funding declined from $383 million as of December 31, 2009 to $228 million as of September 30, 2010. Under the terms of the program, available funding was reduced by $42 million of customer deposits held by the originator because TCEH’s credit ratings were lower than Ba3/BB-. The declines in actual and maximum funding amounts reflected exclusion of receivables under contractual sales agreements.

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. Ongoing changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued a subordinated note payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The subordinated note issued by TXU Receivables Company is subordinated to the undivided interests of the funding entities in the purchased receivables. The balance of the subordinated note payable, which is eliminated in consolidation beginning January 1, 2010, totaled $657 million and $463 million as of September 30, 2010 and December 31, 2009, respectively.

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

Program fee amounts were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Program fees	$	2		$	2		$	7		$	9
Program fees as a percentage of average funding (annualized)		4.8	%		1.3	%		3.3	%		2.4	%

Funding under the program decreased $155 million for the nine months ended September 30, 2010 and increased $284 million for the nine months ended September 30, 2009.

8

Activities of TXU Receivables Company were as follows:

	Nine Months Ended September 30,
	2010			2009
Cash collections on accounts receivable	$	4,828		$	4,660
Face amount of new receivables purchased		(4,867	)		(5,165	)
Discount from face amount of purchased receivables		9			11
Program fees paid to funding entities		(7	)		(9	)
Servicing fees paid to Service Co. for recordkeeping and collection services		(2	)		(2	)
Increase in subordinated notes payable		194			221
Financing/operating cash flows used by (provided to) originator under the program	$	155		$	(284	)

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

The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or Service Co. defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than Service Co., any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of September 30, 2010, there were no such events of termination.

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

Trade Accounts Receivable

	September 30, 2010			December 31, 2009
Wholesale and retail trade accounts receivable, including $885 in pledged retail receivables as of September 30, 2010	$	1,316		$	1,473
Retail accounts receivable sold to TXU Receivables Company		—			(846	)
Subordinated notes receivable from TXU Receivables Company		—			463
Allowance for uncollectible accounts		(72	)		(81	)
Trade accounts receivable — reported in balance sheet	$	1,244		$	1,009

Gross trade accounts receivable as of September 30, 2010 and December 31, 2009 included unbilled revenues totaling $351 million and $468 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Nine Months Ended September 30,
	2010			2009
Allowance for uncollectible accounts receivable as of beginning of period	$	81		$	64
Increase for bad debt expense		88			87
Decrease for account write-offs		(97	)		(67	)
Allowance for uncollectible accounts receivable as of end of period	$	72		$	84

9

4. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

As of September 30, 2010, outstanding short-term borrowings totaled $308 million, which included $80 million under TCEH credit facilities at a weighted average interest rate of 3.84%, excluding certain customary fees, and $228 million under the accounts receivable securitization program discussed in Note 3.

As of December 31, 2009, outstanding short-term borrowings totaled $953 million (all under the TCEH Revolving Credit Facility) at a weighted average interest rate of 3.73%, excluding certain customary fees, at the end of the period.

Credit Facilities

EFCH’s (through TCEH) credit facilities with cash borrowing and/or letter of credit availability as of September 30, 2010 are presented below. The facilities are all senior secured facilities.

			As of September 30, 2010
Authorized Borrowers and Facility	Maturity Date		Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)		October 2013	$	2,700	$	—	$	80	$	2,620
TCEH Letter of Credit Facility (b)		October 2014		1,250		—		1,250		—
Subtotal TCEH			$	3,950	$	—	$	1,330	$	2,620
TCEH Commodity Collateral Posting Facility (c)		December 2012		Unlimited	$	—	$	—		Unlimited

(a) Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $229 million of commitments from Lehman that are only available from the fronting banks and the swingline lender. All outstanding borrowings under this facility as of September 30, 2010 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility.

(b) Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $725 million issued as of September 30, 2010 are supported by the restricted cash, and the remaining letter of credit availability totals $410 million.

(c) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 435 million MMBtu as of September 30, 2010. As of September 30, 2010, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.

10

Long-Term Debt

As of September 30, 2010 and December 31, 2009, long-term debt consisted of the following:

	September 30, 2010			December 31, 2009
TCEH
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39		$	39
7.700% Fixed Series 1999A due April 1, 2033		111			111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (a)		16			16
7.700% Fixed Series 1999C due March 1, 2032		50			50
8.250% Fixed Series 2001A due October 1, 2030		71			71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)		217			217
8.250% Fixed Series 2001D-1 due May 1, 2033		171			171
0.277% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.297% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.286% 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)		(136	)		(147	)
Senior Secured Facilities:
3.828% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)(h)		15,956			16,079
3.758% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		4,044			4,075
3.756% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
0.250% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (g)		—			—
Other:
10.25% Fixed Senior Notes due November 1, 2015 (h)		3,000			3,000
10.25% Fixed Senior Notes due November 1, 2015, Series B (h)		2,000			2,000
10.50 / 11.25% Senior Toggle Notes due November 1, 2016 (h)		2,062			1,952
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		42			55
Capital lease obligations		80			153
Unamortized fair value discount (d)		(3	)		(4	)
Total TCEH	$	29,835		$	29,953

11

	September 30, 2010			December 31, 2009
EFCH (parent entity)
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	51		$	51
8.254% Fixed Notes due in quarterly installments through December 31, 2021		47			50
1.266% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (f)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized fair value discount (d)		(10	)		(11	)
Subtotal		97			99
EFH Corp. debt pushed down (i)
10.875% EFH Corp. Fixed Senior Notes due November 1, 2017		179			915
11.25/12.00% EFH Corp. Senior Toggle Notes due November 1, 2017		270			1,398
9.75% EFH Corp. Fixed Senior Secured Notes due October 15, 2019		58			58
10.000% EFH Corp. Fixed Senior Secured Notes due January 15, 2020		328			—
Subtotal – EFH Corp. debt pushed down		835			2,371
Total EFCH		932			2,470
Total EFCH consolidated		30,767			32,423
Less amount due currently		(242	)		(302	)
Less amount held by affiliates		(427	)		(143	)
Total long-term debt	$	30,098		$	31,978

(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 as of September 30, 2010. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(c) Interest rate in effect as of September 30, 2010. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

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

(e) Interest rate swapped to fixed on $16.30 billion principal amount.

(f) Interest rates in effect as of September 30, 2010.

(g) Interest rate in effect as of September 30, 2010, excluding quarterly maintenance fee of $11 million. See “Credit Facilities” above for more information.

(h) As discussed below and in Note 12, principal amounts of notes/loans totaling $427 million and $143 million as of September 30, 2010 and December 31, 2009, respectively, are held by affiliates as a result of debt exchanges completed by EFH Corp. and EFIH from November 2009 through September 2010.

(i) Represents 50% of the principal amount of these EFH Corp. securities guaranteed by EFCH and pushed down (pushed-down debt) per the discussion below under “Push Down of EFH Corp. Notes.”

Debt-Related Activity in 2010

Repayments of long-term debt in 2010 totaling $243 million represented principal payments at scheduled maturity dates as well as other repayments totaling $89 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 $31 million repaid under the TCEH Delayed Draw Term Loan Facility.

During the second quarter TCEH issued, through the payment-in-kind (PIK) election discussed under “TCEH Senior Notes” below, $110 million principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes) in lieu of making cash interest payments.

2010 Debt Exchanges, Repurchases and Issuances — Debt exchanges and repurchases completed by TCEH, EFH Corp. and EFIH year-to-date October 28, 2010 resulted in acquisitions of $5.635 billion aggregate principal amount of outstanding EFH Corp. and TCEH debt with due dates largely 2017 or earlier in exchange for $3.077 billion aggregate principal amount of new debt and $1.042 billion in cash. The new debt issued in exchange transactions consisted of $2.180 billion aggregate principal amount of EFIH 10% Notes due 2020, $561 million aggregate principal amount of EFH Corp. 10% Notes due 2020 and $336 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021. EFH Corp. also issued $500 million principal amount of EFH Corp. 10% Notes due 2020 for cash, and TCEH issued $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021 for cash. A discussion of these transactions, which were private, except as noted, and a description of the TCEH 15% Senior Secured Second Lien Notes are presented below.

12

Debt issued in exchange for or to repurchase Merger-related debt is considered Merger-related and subject to pushdown (see discussion below under “Push Down of EFH Corp. Notes”). Of the $5.635 billion aggregate principal amount of debt acquired, $3.892 billion represented EFH Corp. debt that had been pushed down to EFCH (at 50%). Of the $3.927 billion aggregate principal amount of debt issuances in 2010, $656 million represented EFH Corp. debt that has been pushed down to EFCH (at 50%) as of September 30, 2010.

Transactions completed in October 2010 were as follows:

• TCEH and TCEH Finance issued $336 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 in exchange for $423 million aggregate principal amount of TCEH 10.25% Notes (plus accrued interest paid in cash) and $55 million aggregate principal amount of TCEH Toggle Notes (together, the TCEH Senior Notes).

• TCEH and TCEH Finance issued $350 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021, and used $290 million of the proceeds to acquire TCEH Senior Notes as described immediately below. The remaining net proceeds totaling $53 million are being held in escrow pending their use for the payment, repayment or prepayment of term loans under the TCEH Senior Secured Facilities and/or the repurchase of outstanding principal amounts of TCEH Senior Notes. If proceeds remain in the escrow account on March 31, 2013, the issuers will be required to use such amounts to offer to repurchase TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021 at a price of 100% of the principal amount thereof, plus accrued interest.

• TCEH repurchased $226 million principal amount of TCEH 10.25% Notes and $200 million principal amount of TCEH Toggle Notes for $290 million in cash using the proceeds from the issuance described immediately above and paid accrued interest from cash on hand.

• EFH Corp. repurchased $9 million principal amount of TCEH Toggle Notes for $5 million in cash.

Transactions completed in the three months ended September 30, 2010 were as follows:

• In a public (registered with the SEC) debt exchange transaction, EFIH and EFIH Finance, a wholly-owned subsidiary of EFIH, (together, the Issuers) issued $2.180 billion aggregate principal amount of EFIH 10% Notes due 2020 and paid $500 million in cash, plus accrued interest, in exchange for $2.166 billion aggregate principal amount of EFH Corp. Toggle Notes and $1.428 billion aggregate principal amount of EFH Corp. 10.875% Notes (together, the EFH Corp. Senior Notes). As a result of EFIH acquiring these EFH Corp. Senior Notes, they are no longer pushed down to EFCH’s financial statements. (See “Push Down of EFH Corp. Notes” below.)

• EFH Corp. issued $455 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $549 million principal amount of EFH Corp. 5.55% Series P Senior Notes (not pushed down to EFCH), $25 million principal amount of EFH Corp. Toggle Notes, $25 million principal amount of EFH Corp. 10.875% Notes and $13 million principal amount of TCEH 10.25% Notes.

• EFH Corp. repurchased $28 million principal amount of EFH Corp. Toggle Notes, $13 million principal amount of TCEH 10.25% Notes and $15 million principal amount of TCEH Toggle Notes for $36 million in cash plus accrued interest.

In connection with the registered debt exchange transaction, EFH Corp. received the requisite consents from holders of the EFH Corp. Senior Notes and executed a supplemental indenture to incorporate certain amendments to the indenture that governs the EFH Corp. Senior Notes. These amendments, among other things, eliminate substantially all of the restrictive covenants related to the EFH Corp. Senior Notes, eliminate certain events of default, modify covenants regarding mergers and consolidations, and modify or eliminate certain other provisions.

13

Transactions completed in the three months ended June 30, 2010 were as follows:

• EFH Corp. repurchased $96 million principal amount of EFH Corp. Toggle Notes, $19 million principal amount of EFH Corp. 10.875% Notes, $168 million principal amount of TCEH 10.25% Notes, $8 million principal amount of TCEH Toggle Notes and $20 million principal amount of TCEH’s initial term loans under its Senior Secured Facilities for $211 million in cash plus accrued interest.

• EFH Corp. issued $72 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $85 million principal amount of EFH Corp. Toggle Notes and $17 million principal amount of TCEH Toggle Notes.

Transactions completed in the three months ended March 31, 2010 were as follows:

• EFH Corp. issued $500 million aggregate principal amount of EFH Corp. 10% Notes due 2020, with the proceeds intended to be used for general corporate purposes including debt exchanges and repurchases.

• EFH Corp. issued $34 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $20 million principal amount of EFH Corp. Toggle Notes and $27 million principal amount of TCEH Toggle Notes.

The EFH Corp. notes acquired by EFIH and the TCEH notes and initial term loans under the TCEH Senior Secured Facilities acquired by EFH Corp. are held as an investment. All other securities acquired in the above transactions have been cancelled. (See “Push Down of EFH Corp. Notes” below.)

TCEH 15% Senior Secured Second Lien Notes — The TCEH 15% Senior Secured Second Lien Notes and the TCEH 15% Senior Secured Second Lien Notes (Series B) (collectively, the TCEH Senior Secured Second Lien Notes) mature in April 2021, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1, beginning January 1, 2011, at a fixed rate of 15% per annum. The notes are unconditionally guaranteed on a joint and several basis by EFCH and subsidiary guarantors (collectively, the Guarantors). The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Credit Facilities on a first-priority basis (the TCEH Collateral), subject to certain exceptions and permitted liens. The guarantee from EFCH is not secured.

The TCEH Senior Secured Second Lien Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH’s obligations under the TCEH Senior Secured Credit Facilities and TCEH’s commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

The guarantees of the TCEH Senior Secured Second Lien Notes from the Subsidiary Guarantors are effectively senior to any unsecured debt of the Subsidiary Guarantors to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral). These guarantees are effectively subordinated to all debt of the Subsidiary Guarantors secured by the TCEH Collateral on a first-priority basis or that is secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt. EFCH’s guarantee ranks equally with its unsecured debt (including debt it guarantees on an unsecured basis) and is effectively subordinated to any of its secured debt to the extent of the value of the collateral securing that debt.

14

The TCEH Senior Secured Second Lien Notes and indenture governing such notes restrict TCEH’s and its restricted subsidiaries’ ability to, among other things, make restricted payments, including certain investments, incur debt and issue preferred stock, incur liens, pay dividends, merge, consolidate or sell assets and engage in transactions with affiliates. These covenants are subject to a number of limitations and exceptions. These notes and related indenture also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. In general, all of the series of TCEH Senior Secured Second Lien Notes vote together as a single class. As a result, if certain events of default occur under the related indenture, the trustee or the holders of at least 30% of aggregate principal amount of all outstanding TCEH Senior Secured Second Lien Notes may declare the principal amount on all such notes to be due and payable immediately.

Until October 1, 2013, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of each series of the TCEH Senior Secured Second Lien Notes from time to time at a redemption price of 115.00% of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEH may redeem each series of the notes at any time prior to October 1, 2015 at a price equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. TCEH may also redeem each series of the notes, in whole or in part, at any time on or after October 1, 2015, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture), TCEH must offer to repurchase each series of the notes at 101% of their principal amount, plus accrued interest.

The TCEH Senior Secured Second Lien Notes were issued in private placements and have not been registered under the Securities Act. TCEH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the TCEH Senior Secured Second Lien Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the TCEH Senior Secured Second Lien Notes unless such notes meet certain transferability conditions (as described in the related registration rights agreement). If the registration statement is required and has not been filed and declared effective within 365 days after the original issue date (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.

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, 2010 is provided in the long-term debt table and in the discussion of short-term borrowings above and reflects LIBOR-based borrowings. These borrowings totaled $21.330 billion as of September 30, 2010 (including $20 million principal amount held by EFH Corp.).

In August 2009, the TCEH Senior Secured Facilities were 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.

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In addition, the amended facilities permit TCEH to, among other things:

• issue new secured notes or loans, which may include, in each case, debt 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;

• upon making an offer to all lenders within a particular series, agree with lenders of that series 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.

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

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

The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility ($41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of December 2009 ($10 million quarterly), with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.

TCEH Senior Notes — The TCEH 10.25% Notes bear interest that is payable semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum payable in cash. TCEH’s Toggle Notes bear interest that is payable semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK Interest. For any interest period until November 2012, the issuers may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.

The TCEH 10.25% and Toggle Notes (collectively, the TCEH Senior Notes) had a total principal amount as of September 30, 2010 of $7.062 billion (including $407 million principal amount held by EFH Corp. and EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH’s direct parent, EFCH (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.

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The issuers may redeem the TCEH 10.25% Notes and TCEH Toggle Notes at any time prior to November 1, 2011 and 2012, respectively, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. The issuers may redeem the TCEH 10.25% Notes and TCEH Toggle Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFCH or TCEH, the 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 — Merger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing at the time of the Merger. Debt issued in exchange for Merger-related debt is considered Merger-related. Debt issuances are considered Merger-related debt to the extent the proceeds are used to repurchase Merger-related debt. Merger-related debt that is fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH is subject to push down in accordance with SEC Staff Accounting Bulletin (SAB) Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected in the financial statements of EFCH. The amount reflected on EFCH’s balance sheet represents 50% of the EFH Corp. Merger-related debt it has guaranteed. This percentage reflects the fact that at the time of the Merger, the equity investments of EFCH and EFIH in their respective operating subsidiaries were essentially equal amounts. Because payment of principal and interest on the notes is the responsibility of EFH Corp., EFCH records the settlement of such amounts as noncash capital contributions from EFH Corp.

The Merger-related debt of EFH Corp. as of September 30, 2010 guaranteed by EFCH and EFIH totaled $1.669 billion and consisted of:

• $656 million principal amount of EFH Corp. 10% Notes issued in 2010, consisting of $561 million principal amount issued in exchange for EFH Corp. and TCEH Merger-related debt and $95 million representing proceeds from an issuance used to repurchase EFH Corp. Merger-related debt;

• $539 million principal amount of EFH Corp. Toggle Notes;

• $359 million principal amount of 10.875% Senior Notes due November 2017 (EFH Corp. 10.875% Notes), and

• $115 million principal amount of 9.75% Senior Secured Notes due October 2019 (EFH Corp. 9.75% Notes).

EFCH’s balance sheet as of September 30, 2010 reflects 50% of these amounts.

The guarantees from EFCH are not secured, and the guarantees from EFIH on the EFH Corp. Senior Notes are not secured. The guarantees from EFIH with respect to the EFH Corp. 10% and 9.75% Notes are secured by EFIH’s pledge of 100% of the membership interests and other investments it owns in Oncor Holdings. The guarantees are the general senior obligation of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantees will be effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the Collateral to the extent of the value of the assets securing such indebtedness and will be structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.’s subsidiaries that are not guarantors.

TCEH Interest Rate Swap Transactions — As of September 30, 2010, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $16.30 billion principal amount of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2010 to 2014. No interest rate swap transactions have been entered into in 2010.

As of September 30, 2010, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $16.30 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.2055%. These transactions include swaps entered into in the nine months ended September 30, 2010 related to an aggregate $2.55 billion principal amount of senior secured term loans of TCEH and reflect the expiration of swaps in the nine months ended September 30, 2010 related to an aggregate $2.50 billion principal amount of senior secured term loans of TCEH.

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The interest rate swap counterparties are proportionately secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $181 million and $542 million in net losses in the three and nine months ended September 30, 2010, respectively, and $138 million in net losses and $527 million in net gains in the three and nine months ended September 30, 2009, respectively. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.755 billion as of September 30, 2010, of which $120 million (pre-tax) was reported in accumulated other comprehensive income.

See Note 9 for discussion of collateral investments related to certain of these interest rate swaps that expired in March 2010.

5. COMMITMENTS AND CONTINGENCIES

Guarantees

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

Residual value guarantees in operating leases — Subsidiaries of EFCH are the lessee under various operating leases that guarantee the residual values of the leased assets. As of September 30, 2010, the aggregate maximum amount of residual values guaranteed was $13 million with an estimated residual recovery of $13 million. These leased assets consist primarily of rail cars. The average life of the residual value guarantees under the lease portfolio is approximately six years.

See Note 4 above and Note 10 to Financial Statements in the 2009 Form 10-K for discussion of guarantees and security for certain of EFCH’s debt.

Letters of Credit

As of September 30, 2010, TCEH had outstanding letters of credit under its credit facilities totaling $725 million as follows:

• $325 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

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

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

• $108 million for miscellaneous credit support requirements.

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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. Subsequently, the non-parties to the original administrative proceeding non-suited their claims, thus ending their legal challenge. In July 2010, the court issued an order rejecting the remaining plaintiff’s claims and upholding the TCEQ’s issuance of the Oak Grove air permit. The plaintiff did not appeal the court’s order. Accordingly, the matter has been resolved favorably for EFCH, and the judgment in the case is now final.

In July 2008, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Holdings’ general partner as parties to the suit. The lawsuit made various claims concerning the operation of the Sandow Unit 4 generation facility and the related Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requested money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. In May 2010, the trial court granted a summary judgment dismissing substantially all of Alcoa’s claims other than its breach of contract claims against Luminant Generation and Luminant Mining. On the breach of contract claims against Luminant Generation relating to the Sandow Unit 4 generation facility, a jury rendered a verdict in Luminant Generation’s favor in June 2010. The jury awarded no damages to Alcoa and awarded $10 million in damages to Luminant Generation. In June 2010, the judge presiding in the case ruled in Luminant Mining’s favor on the claims against it, awarding no damages to Alcoa and awarding nearly $2 million in damages to Luminant Mining. As a result, the lawsuit was concluded favorably to Luminant. Alcoa did not appeal the final judgment.

In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violations of the Clean Air Act at Luminant’s Martin Lake generation facility. As previously disclosed, in July 2008, the Sierra Club had given Luminant notice of its intention to sue. While EFCH is unable to estimate any possible loss or predict the outcome of the litigation, EFCH believes that the Sierra Club’s claims are without merit, and EFCH intends to vigorously defend this litigation. In addition, in February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. EFCH cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

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Regulatory Investigations and Reviews

In June 2008, the EPA issued a request for information to TCEH under the EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.

Sandow Power Company LLC (Sandow Power), a subsidiary of TCEH, is a party to a federal consent decree (the Consent Decree) with, among others, the US Department of Justice (DOJ) and certain private plaintiffs related to Sandow Power’s Sandow Unit 5 lignite-fueled generation facility. Between December 3, 2009 and March 31, 2010, Sandow Power submitted several force majeure claims to the DOJ regarding ostensible deviations from emissions limits at Sandow Unit 5 resulting from force majeure events, as that term is defined in the Consent Decree. In September 2010, Sandow Power, the DOJ, the EPA and the private plaintiffs filed with the court a notice of settlement regarding these force majeure claims, and the court subsequently issued an order approving that settlement. The settlement involves a payment to the US Treasury that is not material to the company, but in excess of the $100,000 disclosure threshold applicable to such matters.

Other Proceedings

In addition to the above, EFCH 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.

6. EQUITY

Dividend Restrictions

There are no restrictions on EFCH’s ability to use its retained earnings or net income to make distributions on its equity. However, EFCH relies on distributions or loans from TCEH to meet its cash requirements, including funding of distributions. The TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes and TCEH Senior Secured Second Lien Notes generally restrict TCEH’s ability to make distributions or loans to EFCH. Thus, all of TCEH’s net income, which represents essentially all of EFCH’s net income, is restricted from being used to make distributions or loans to EFCH unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes and TCEH Senior Secured Second Lien Notes. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies, EFCH 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 cash distribution to any of its parent companies for the ultimate purpose of making a cash distribution to Texas Holdings unless at the time, and after giving effect to such distribution, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. As of September 30, 2010, EFH Corp. demand notes payable to TCEH totaled $1.690 billion, of which $704 million is related to principal and interest payments. Such principal and interest amounts are guaranteed by EFCH and EFIH on a pari passu basis with their guarantees of the EFH Corp. Senior Notes; the remaining balance of the demand notes is not guaranteed.

In addition, under applicable law, EFCH 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.

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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, Comanche Peak Nuclear Power Company LLC (CPNPC), to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary (see Note 11).

Equity

The following table presents the changes to equity during the nine months ended September 30, 2010:

	EFCH Shareholder’s Equity
	Common Stock			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total Equity
Balance as of December 31, 2009	$	5,651		$	(9,790	)	$	(127	)	$	48	$	(4,218	)
Net income		—			(3,777	)		—			—		(3,777	)
Effects of stock-based incentive compensation plans		7			—			—			—		7
Net effects of cash flow hedges		—			—			49			—		49
Effect of consolidation of TXU Receivables Company (Note 3)		—			—			—			7		7
Investment by noncontrolling interests		—			—			—			24		24
Effects of debt push-down from EFH Corp. (a)		1,467			—			—			—		1,467
Other		(1	)		—			—			—		(1	)
Balance as of September 30, 2010	$	7,124		$	(13,567	)	$	(78	)	$	79	$	(6,442	)

(a) Represents the effect of net reduction of debt pushed down from EFH Corp. of $1.536 billion (Note 4) and related interest and income tax effects.

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7. 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. EFCH 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. EFCH 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.

EFCH 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. EFCH’s Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of EFCH’s 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. EFCH’s 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, EFCH’s 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. EFCH 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, EFCH’s 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.

EFCH 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, EFCH 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, EFCH 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.

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

As of September 30, 2010, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	1,165	$	4,166	$	538	$	62	$	5,931
Interest rate swaps		—		5		—		—		5
Nuclear decommissioning trust – equity securities (c)		170		109		—		—		279
Nuclear decommissioning trust – debt securities (c)		—		229		—		—		229
Total assets	$	1,335	$	4,509	$	538	$	62	$	6,444
Liabilities:
Commodity contracts	$	1,350	$	866	$	284	$	62	$	2,562
Interest rate swaps		—		1,759		—		—		1,759
Total liabilities	$	1,350	$	2,625	$	284	$	62	$	4,321

(a) Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including a long-term wind generation purchase contract, certain natural gas positions (collars) in the long-term hedging program and certain power transactions valued at illiquid pricing locations as discussed below.

(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 13.

As ERCOT transitions to a nodal wholesale market structure, EFCH has entered (and expects to increasingly enter) into certain derivative transactions that are valued at illiquid pricing locations (unobservable inputs), thus requiring classification as Level 3 assets or liabilities. As the nodal market matures and more transactions and pricing information becomes available for these pricing locations, EFCH expects more of the valuation inputs to become observable.

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As of December 31, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	918	$	2,588	$	350	$	4	$	3,860
Interest rate swaps		—		12		—		—		12
Nuclear decommissioning trust – equity securities (c)		154		105		—		—		259
Nuclear decommissioning trust – debt securities (c)		—		216		—		—		216
Total assets	$	1,072	$	2,921	$	350	$	4	$	4,347
Liabilities:
Commodity contracts	$	1,077	$	796	$	269	$	4	$	2,146
Interest rate swaps		—		1,224		—		—		1,224
Total liabilities	$	1,077	$	2,020	$	269	$	4	$	3,370

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

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

(c) The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 13.

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 9 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.

There were no significant transfers between the levels of the fair value hierarchy for the three and nine months ended September 30, 2010.

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The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Balance at beginning of period	$	169		$	(72	)	$	81		$	(72	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		118			42			182			57
Included in other comprehensive income (loss)		—			(6	)		—			(31	)
Purchases, sales, issuances and settlements (net) (b)		(24	)		(6	)		7			(15	)
Transfers into Level 3 (c)		(11	)		1			(10	)		1
Transfers out of Level 3 (c)		2			—			(6	)		19
Balance at end of period	$	254		$	(41	)	$	254		$	(41	)
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period	$	116		$	44		$	199		$	61

(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. For 2010, in accordance with new accounting guidance issued by the FASB in January 2010, transfers in and out occur at the end of each quarter, which is when the assessments are performed. Prior period transfers in were assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter.

8. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments attributable to EFCH (including 50% of the EFH Corp. Merger-related debt) as of September 30, 2010 and December 31, 2009 were as follows:

	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value (a)		Carrying Amount		Fair Value (a)
On balance sheet liabilities:
Long-term debt (including current maturities) (b):	$	30,687	$	22,934	$	32,270	$	25,885
Off balance sheet liabilities:
Financial guarantees	$	—	$	4	$	—	$	6

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

(b) Excludes capital leases.

See Notes 7 and 9 for discussion of accounting for financial instruments that are derivatives.

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9. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

EFCH 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. EFCH’s principal activities involving derivatives consist of a long-term commodity hedging program and the hedging of interest costs on its long-term debt. See Note 7 for a discussion of the fair value of all derivatives.

Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is highly correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2014. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

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

Financial Statement Effects of Derivatives

Substantially all commodity and other derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities as reported in the balance sheets as of September 30, 2010 and December 31, 2009:

	September 30, 2010
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	3,364		$	4	$	15		$	—		$	3,383
Noncurrent assets		2,518			1		34			—			2,553
Current liabilities		(6	)		—		(2,258	)		(635	)		(2,899	)
Noncurrent liabilities		(7	)		—		(291	)		(1,124	)		(1,422	)
Net assets (liabilities)	$	5,869		$	5	$	(2,500	)	$	(1,759	)	$	1,615

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	December 31, 2009
	Derivative assets				Derivative liabilities
	Commodity contracts		Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	2,327	$	8	$	4		$	—		$	2,339
Noncurrent assets		1,529		4		—			—			1,533
Current liabilities		—		—		(1,705	)		(605	)		(2,310	)
Noncurrent liabilities		—		—		(441	)		(619	)		(1,060	)
Net assets (liabilities)	$	3,856	$	12	$	(2,142	)	$	(1,224	)	$	502

As of September 30, 2010 and December 31, 2009, there were no derivative positions accounted for as cash flow or fair value hedges.

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $503 million and $358 million in net liabilities as of September 30, 2010 and December 31, 2009, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because EFCH may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Derivative (Income statement presentation)	2010			2009			2010			2009
Commodity contracts (Net gain from commodity hedging and trading activities)	$	979		$	136		$	2,255		$	1,026
Interest rate swaps (Interest expense and related charges)		(350	)		(317	)		(1,048	)		16
Net gain	$	629		$	(181	)	$	1,207		$	1,042

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The following tables present the pre-tax effect on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges:

	Amount of gain (loss) recognized in OCI (effective portion)						Income statement presentation of loss reclassified from accumulated OCI into income (effective portion)
Derivative	Three Months Ended September 30, 2010			Nine Months Ended September 30, 2010				Three Months Ended September 30, 2010			Nine Months Ended September 30, 2010
Interest rate swaps	$	—		$	—		Interest expense and related charges	$	(19	)	$	(72	)
							Depreciation and amortization		(1	)		(1	)
Commodity contracts		—			—		Fuel, purchased power costs and delivery fees		—			—
							Operating revenues		—			(1	)
Total	$	—		$	—			$	(20	)	$	(74	)
	Amount of gain (loss) recognized in OCI (effective portion)						Income statement presentation of loss reclassified from accumulated OCI into income (effective portion)
Derivative	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009				Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Interest rate swaps	$	—		$	—		Interest expense and related charges	$	(56	)	$	(140	)
Commodity contracts		(6	)		(31	)	Fuel, purchased power costs and delivery fees		(6	)		(10	)
							Operating revenues		—			(2	)
Total	$	(6	)	$	(31	)		$	(62	)	$	(152	)

There were no transactions designated as cash flow hedges during the three and nine months ended September 30, 2010. There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the three and nine months ended September 30, 2009.

Accumulated other comprehensive income related to cash flow hedges as of September 30, 2010 and December 31, 2009 totaled $79 million and $127 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. EFCH expects that $26 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of September 30, 2010 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

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Derivative Volumes — The following table presents the gross notional amounts of derivative volumes as of September 30, 2010 and December 31, 2009:

	September 30, 2010		December 31, 2009
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed	$	16,300	$	16,300	Million US dollars
Basis	$	16,300	$	16,250	Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		2,727		3,402	Million MMBtu
Locational basis swaps		1,006		1,010	Million MMBtu
All other		1,094		1,433	Million MMBtu
Electricity		172,010		198,230	GWh
Coal		7		6	Million tons
Fuel oil		116		161	Million gallons

(a) Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, was 1.25 billion MMBtu and 1.6 billion MMBtu as of September 30, 2010 and December 31, 2009, respectively.

Credit Risk-Related Contingent Features of Derivatives

The agreements that govern EFCH’s 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 credit ratings being below investment grade, substantially all of such collateral posting requirements are already effective.

As of September 30, 2010 and December 31, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $620 million and $687 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $94 million and $152 million as of September 30, 2010 and December 31, 2009, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of September 30, 2010 and December 31, 2009, the remaining related liquidity requirement would have totaled $24 million and $20 million, respectively, after reduction for net accounts receivable and derivative assets under netting arrangements.

In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of September 30, 2010 and December 31, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $2.193 billion and $1.400 billion, respectively, (before consideration of the amount of assets under the liens). No cash collateral or letters of credit were posted with these counterparties as of September 30, 2010 to reduce the liquidity exposure, but $489 million of such collateral was posted as of December 31, 2009, with the decline reflecting the return of collateral from counterparties to certain interest rate swaps related to TCEH debt as discussed above in this note. 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, 2010 and December 31, 2009, the remaining related liquidity requirement would have totaled $1.095 billion and $450 million, respectively, after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 10 to Financial Statements in the 2009 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 $2.813 billion and $2.087 billion as of September 30, 2010 and December 31, 2009, respectively. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.

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

Concentrations of Credit Risk Related to Derivatives

TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of September 30, 2010, total credit risk exposure to all counterparties related to derivative contracts totaled $6.1 billion (including associated accounts receivable). The net exposure to those counterparties totaled $2.2 billion as of September 30, 2010 after taking into effect master netting arrangements, setoff provisions and collateral. The net exposure, assuming setoff provisions in the event of default across all EFH Corp. consolidated subsidiaries, totaled $1.6 billion. As of September 30, 2010, the credit risk exposure to the banking and financial sector represented 94% of the total credit risk exposure, a significant amount of which is related to the long-term hedging program, and the largest net exposure to a single counterparty totaled approximately $1.0 billion. Exposure to the banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially all of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on EFCH’s financial condition and results of operations.

The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. EFCH maintains credit risk policies with regard to its counterparties to minimize overall credit risk. These policies specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to EFCH.

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

Subsidiaries of EFCH are participating employers in the EFH Retirement Plan, a defined benefit pension plan sponsored by EFH Corp. Subsidiaries of EFCH 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 EFCH totaled $11 million and $7 million for the three months ended September 30, 2010 and 2009, respectively, and $29 million and $17 million for the nine months ended September 30, 2010 and 2009, respectively.

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

EFCH provided no cash contributions to the pension plan in the nine months ended September 30, 2010 and does not expect to make any cash contributions for the remainder of 2010. EFCH made cash contributions totaling $646 thousand to the OPEB plan in the nine months ended September 30, 2010, and expects to make additional contributions totaling $239 thousand in the remainder of 2010.

11. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

EFCH adopted amended accounting standards on January 1, 2010 that require consolidation of a VIE if EFCH has the power to direct the significant activities of the VIE and the right or obligation to absorb profit and loss from the VIE. A VIE is an entity with which EFCH has a relationship or arrangement that indicates some level of control over the entity or results in economic risks to EFCH. As discussed below, EFCH’s balance sheet includes assets and liabilities of VIEs that meet the consolidation standards.

EFCH’s variable interests consist of equity investments and TXU Receivables Company, the activities of which are discussed in Note 3. In determining the appropriateness of consolidation of a VIE, EFCH evaluates its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. EFCH also examines the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.

Consolidated VIEs

Effective January 1, 2010, TXU Receivables Company is consolidated by EFCH in accordance with amended consolidation accounting standards because EFCH (as the owner of TXU Energy) is the primary economic beneficiary of TXU Receivables Company, which is owned and controlled by its parent, EFH Corp.

EFCH continues to consolidate CPNPC, which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at TCEH’s existing Comanche Peak nuclear-fueled generation facility using MHI’s US-Advanced Pressurized Water Reactor technology and to obtain a combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries of TCEH and MHI that hold 88% and 12% of CPNPC’s equity interests, respectively (see Note 6).

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The carrying amounts and classifications of the assets and liabilities related to EFCH’s consolidated VIEs as of September 30, 2010 are as follows:

Assets:			Liabilities:
Cash and cash equivalents	$	9	Short-term borrowings (a)	$	228
Accounts receivable (a)		885	Trade accounts payable		4
Property, plant and equipment		105	Other current liabilities		1
Other noncurrent assets, including $2 current		8	Total liabilities	$	233
Total assets	$	1,007

(a) As a result of the January 1, 2010 adoption of new accounting guidance related to transfers of financial assets, the balance sheet as of September 30, 2010 reflects $885 million of pledged accounts receivable and $228 million of short-term borrowings (see Note 3).

The assets of EFCH’s consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of EFCH’s consolidated VIEs do not have recourse to EFCH’s general credit.

12. RELATED–PARTY TRANSACTIONS

The following represent the significant related-party transactions of EFCH:

• TCEH’s retail operations incur electricity delivery fees charged by Oncor. These fees totaled $317 million and $839 million for the three and nine months ended September 30, 2010, respectively, and $308 million and $783 million for the three and nine months ended September 30, 2009, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheet as of September 30, 2010 and December 31, 2009 reflects amounts due currently to Oncor totaling $182 million and $151 million, respectively, primarily related to these delivery fees.

• Oncor’s bankruptcy-remote financing subsidiary has issued securitization bonds to recover generation-related regulatory assets through a transition surcharge to its customers. Oncor’s incremental income taxes related to the transition surcharges it collects are being reimbursed by TCEH. Therefore, the balance sheet reflects a noninterest bearing note payable to Oncor of $227 million ($38 million current portion included in trade accounts and other payables to affiliates) as of September 30, 2010 and $254 million ($37 million current portion included in trade accounts and other payables to affiliates) as of December 31, 2009.

• TCEH reimburses Oncor for interest expense on Oncor’s bankruptcy-remote financing subsidiary’s securitization bonds. This interest expense totaled $9 million and $28 million for the three and nine months ended September 30, 2010, respectively, and $10 million and $32 million for the three and nine months ended September 30, 2009, respectively.

• Notes receivable from EFH Corp. are payable to TCEH on demand and arise from cash loaned for debt principal and interest payments and other general corporate purposes of EFH Corp. The notes totaled $1.690 billion and $1.406 billion as of September 30, 2010 and December 31, 2009, respectively, including $704 million and $416 million, respectively, related to principal and interest on EFH Corp. debt. Such principal and interest notes are guaranteed by EFCH and EFIH on a pari passu basis with their guarantees of the EFH Corp. Senior Notes; the remaining balance of the demand notes is not guaranteed. The average daily balance of the notes for the three and nine months ended September 30, 2010 was $1.649 billion and $1.516 billion, respectively, and was $1.061 billion and $801 million for the three and nine months ended September 30, 2009, respectively. The notes carry interest at a rate based on the one-month LIBOR rate plus 5.00%, and interest income totaled $22 million and $61 million for the three and nine months ended September 30, 2010, respectively, and $14 million and $33 million for the three and nine months ended September 30, 2009, respectively.

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• A note to EFH Corp. is payable by TCEH on demand and arises from borrowings used to repay borrowings under the TCEH Revolving Credit Facility. The note totaled $770 million as of September 30, 2010. The average daily balance of the note for the three and nine months ended September 30, 2010 was $770 million and $607 million, respectively. The note carries interest at a rate based on the one-month LIBOR rate plus 3.50%, and interest expense totaled $7 million and $17 million for the three and nine months ended September 30, 2010. In addition, a note to EFH Corp. is payable by EFCH on demand and arises from borrowings used to repay outstanding debt. The note totaled $36 million as of September 30, 2010. The note carries interest at a rate based on the one-month LIBOR rate plus 5.00%.

• An EFH Corp. subsidiary charges subsidiaries of EFCH for information technology, financial, accounting and other administrative services at cost. These costs, which are primarily reported in SG&A expenses, totaled $48 million and $141 million for the three and nine months ended September 30, 2010, respectively, and $17 million and $53 million for the three and nine months ended September 30, 2009, respectively. The increases were driven by services now provided by the EFH Corp. subsidiary that were previously outsourced and billed directly to EFCH by the third party. The increases also reflected $12 million and $35 million in new costs allocated from corporate, principally fees paid to the Sponsor Group.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in investments on EFCH’s 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 as receivable from affiliate on EFCH’s balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by EFCH 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. As of September 30, 2010, the excess of the trust fund balance over the decommissioning liability resulted in a payable to Oncor totaling $183 million.

The intercompany receivable/payable with Oncor has changed from a receivable of $85 million as of December 31, 2009 to a payable of $183 million as of September 30, 2010 due to a new decommissioning cost estimate completed in the second quarter 2010 that resulted in a decline of the liability. The new cost estimate was completed in accordance with regulatory requirements to perform a cost estimate every five years. The lower estimated liability was driven by lower cost escalation assumptions in the new estimate. (Also see Note 13 under “Asset Retirement Obligations.”)

• TCEH had posted cash collateral of $4 million and $15 million as of September 30, 2010 and December 31, 2009, respectively, to Oncor related to interconnection agreements for the generation units being developed by TCEH. The collateral is reported in EFCH’s balance sheet in other current assets. In January 2010, Oncor returned $11 million of the collateral and paid $1 million in related accrued interest.

• EFH Corp. files a consolidated federal income tax return; however, EFCH’s 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 EFCH files its own income tax return. As a result, EFCH had income taxes payable to EFH Corp. of $12 million and $50 million as of September 30, 2010 and December 31, 2009, 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, 2010 and December 31, 2009, TCEH had posted a letter of credit in the amount of $14 million and $15 million, respectively, for the benefit of Oncor.

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

• 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 EFCH in the normal course of business.

• As a result of debt repurchase and exchange transactions in November 2009 and the first nine months of 2010 and the May 2010 PIK interest payment on the TCEH Toggle Notes (see Note 4) as of September 30, 2010 and December 31, 2009, EFH Corp. held as an investment $328 million and $64 million, respectively, principal amount of TCEH Senior Notes and as of both September 30, 2010 and December 31, 2009, EFIH held as an investment $79 million principal amount of TCEH Senior Notes. EFH Corp. also held as an investment $20 million of TCEH’s Initial Term Loan Facility as of September 30, 2010 as a result of debt repurchase transactions in June 2010. Interest expense accrued on the notes totaled $11 million and $20 million for the three and nine months ended September 30, 2010. TCEH paid no interest on the notes for the three months ended September 30, 2010. Interest paid by TCEH on the notes for the nine months ended September 30, 2010 totaled $7 million in cash and $2 million in additional TCEH Toggle Notes.

• Goldman, Sachs & Co. acted as an initial purchaser in the issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) in October 2010 as discussed in Note 4 and received fees totaling $1 million.

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

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

See Notes 4 and 5 for guarantees and push-down of certain EFH Corp. debt and Note 10 for allocation of EFH Corp.’s pension and OPEB costs to EFCH.

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13. SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2010		2009		2010		2009
Other income:
Gain on sale of land/water rights	$	—	$	—	$	44	$	—
Gain on sale of interest in natural gas gathering pipeline business		—		—		37		—
Reversal of reserve recorded in purchase accounting (a)		—		23		—		23
Fee received related to interest rate swap/commodity hedge derivative agreement (Note 9)		—		6		—		6
Insurance/litigation settlements		6		—		6		—
Sales tax refund		—		3		5		3
Mineral rights royalty income		—		1		1		2
Other		—		—		2		4
Total other income	$	6	$	33	$	95	$	38
Other deductions:
Gas plant impairment charges	$	—	$	—	$	1	$	—
Severance charges		—		—		2		6
Equity losses – unconsolidated affiliates		—		1		—		5
Other		3		5		9		8
Total other deductions	$	3	$	6	$	12	$	19

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

Interest Expense and Related Charges

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	619		$	642		$	1,881		$	1,930
Accrued interest to be paid with additional toggle notes (Note 4)		58			52			170			153
Unrealized mark-to-market net (gain) loss on interest rate swaps		181			138			542			(527	)
Amortization of interest rate swap losses at dedesignation of hedge accounting		19			56			72			140
Amortization of fair value debt discounts resulting from purchase accounting		4			4			13			12
Amortization of debt issuance costs and discounts		30			30			93			91
Capitalized interest		(6	)		(80	)		(53	)		(252	)
Total interest expense and related charges	$	905		$	842		$	2,718		$	1,547

Restricted Cash

	September 30, 2010				December 31, 2009
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 4)	$	—	$	1,135	$	—	$	1,135
Amounts related to margin deposits held		31		—		1		—
Total restricted cash	$	31	$	1,135	$	1	$	1,135

35

Inventories by Major Category

	September 30, 2010		December 31, 2009
Materials and supplies	$	164	$	156
Fuel stock		197		204
Natural gas in storage		27		33
Total inventories	$	388	$	393

Investments

	September 30, 2010		December 31, 2009
Nuclear decommissioning trust	$	508	$	475
Assets related to employee benefit plans, including employee savings programs, net of distributions		16		18
Land		41		41
Investment in natural gas gathering pipeline business (a)		—		44
Investment in unconsolidated affiliate		6		10
Miscellaneous other		3		3
Total investments	$	574	$	591

(a) A controlling interest in this previously consolidated subsidiary was sold in 2009, and the remaining interests were sold in June 2010.

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

	September 30, 2010
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	219	$	12	$	(2	)	$	229
Equity securities (c)		208		90		(19	)		279
Total	$	427	$	102	$	(21	)	$	508
	December 31, 2009
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	211	$	8	$	(3	)	$	216
Equity securities (c)		195		83		(19	)		259
Total	$	406	$	91	$	(22	)	$	475

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

(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.53% and 4.44% and an average maturity of 7.9 years and 7.8 years as of September 30, 2010 and December 31, 2009, respectively.

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

Debt securities held as of September 30, 2010 mature as follows: $80 million in one to five years, $42 million in five to ten years and $107 million after ten years.

36

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.

	Nine Months Ended September 30,
	2010			2009
Realized gains	$	1		$	1
Realized losses		(1	)		(4	)
Proceeds from sale of securities		937			2,972

Property, Plant and Equipment

As of September 30, 2010 and December 31, 2009, property, plant and equipment of $20.3 billion and $21.0 billion, respectively, is stated net of accumulated depreciation and amortization of $3.8 billion and $2.7 billion, respectively.

Asset Retirement Obligations

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

The following table summarizes the changes to the asset retirement liability, reported in other current liabilities and other noncurrent liabilities and deferred credits in the balance sheet, during the nine months ended September 30, 2010:

Asset retirement liability as of January 1, 2010	$	948
Additions:
Accretion		46
Reductions:
Payments, essentially all mining reclamation		(33	)
Adjustment for new cost estimate (a)		(498	)
Asset retirement liability as of September 30, 2010		463
Less amounts due currently		(35	)
Noncurrent asset retirement liability as of September 30, 2010	$	428

(a) Essentially all of the adjustment relates to the nuclear decommissioning liability, which resulted from a new cost estimate completed in the second quarter 2010. In accordance with regulatory requirements, a new cost estimate is completed every five years. A decline in the liability was driven by lower cost escalation assumptions in the new estimate. The reduction in the liability was offset in part by a reduction in the carrying value of the nuclear facility with the balance offset by an increase in the noncurrent liability to Oncor, which in turn resulted in a regulatory liability on Oncor’s balance sheet. (Also see Note 12.)

37

Other Noncurrent Liabilities and Deferred Credits

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

	September 30, 2010		December 31, 2009
Uncertain tax positions (including accrued interest)	$	1,079	$	1,044
Asset retirement obligations		428		948
Unfavorable purchase and sales contracts		680		700
Retirement plan and other employee benefits		46		48
Other		4		9
Total other noncurrent liabilities and deferred credits	$	2,237	$	2,749

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $7 million and $20 million in the three and nine months ended September 30, 2010, respectively, and $7 million and $21 million in the three and nine months ended September 30, 2009, respectively. Favorable purchase and sales contracts are recorded as intangible assets (see Note 2).

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

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

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2010			2009
Cash payments (receipts) related to:
Interest paid (a)	$	1,491		$	1,603
Capitalized interest		(53	)		(252	)
Interest paid (net of capitalized interest) (a)		1,438			1,351
Income taxes		58			38
Noncash investing and financing activities:
Effect of push down of debt from parent		(1,618	)		—
Effect of Parent’s payment of interest and issuance of toggle notes as consideration for cash interest, net of tax, on pushed down debt		(42	)		87
Noncash construction expenditures (b)		36			72
Capital leases		—			15

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

(b) Represents end-of-period accruals.

See Note 4 for noncash exchanges of debt.

38

14. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

As of September 30, 2010, TCEH and TCEH Finance, as Co-Issuers, had outstanding $3.0 billion 10.25% Senior Notes Due 2015, $2.0 billion 10.25% Senior Notes due 2015 Series B and $2.062 billion Toggle Notes (collectively, the TCEH Senior Notes). The TCEH Senior Notes are unconditionally guaranteed by EFCH 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 EFCH, 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 EFCH’s ability to pay dividends or make investments. See Note 6.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered “ in order to present the condensed consolidating statements of income and of cash flows of EFCH (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors for the three and nine months ended September 30, 2010 and 2009 and the condensed consolidating balance sheets as of September 30, 2010 and December 31, 2009 of the Parent, Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5J, Push Down Basis of Accounting Required in Certain Limited Circumstances, including the effects of the push down of $449 million and $2.313 billion of the EFH Corp. Senior Notes and $386 million and $58 million of the EFH Corp. Senior Secured Notes to the Parent Guarantor and the TCEH Senior Notes and the TCEH Senior Secured Facilities to the Other Guarantors as of September 30, 2010 and December 31, 2009, respectively. 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).

EFCH (parent entity) received no dividends from its consolidated subsidiaries for the three and nine months ended September 30, 2010 and 2009.

39

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended September 30, 2010

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,604		$	3		$	—		$	2,607
Fuel, purchased power costs and delivery fees		—			—			(1,400	)		—			—			(1,400	)
Net gain from commodity hedging and trading activities		—			563			429			—			—			992
Operating costs		—			—			(197	)		—			—			(197	)
Depreciation and amortization		—			—			(345	)		—			—			(345	)
Selling, general and administrative expenses		—			—			(182	)		(1	)		—			(183	)
Franchise and revenue-based taxes		—			—			(24	)		—			—			(24	)
Impairment of goodwill		—			(4,100	)		—			—			—			(4,100	)
Other income		—			—			5			—			1			6
Other deductions		—			—			(3	)		—			—			(3	)
Interest income		—			98			114			—			(189	)		23
Interest expense and related charges		(53	)		(986	)		(481	)		(2	)		617			(905	)
Income (loss) before income taxes		(53	)		(4,425	)		520			—			429			(3,529	)
Income tax (expense) benefit		23			103			(168	)		—			(149	)		(191	)
Equity earnings (losses) of subsidiaries		(3,690	)		632			—			—			3,058			—
Net income (loss)		(3,720	)		(3,690	)		352			—			3,338			(3,720	)
Net (income) loss attributable to noncontrolling interests		—			—			—			—			—			—
Net income (loss) attributable to EFCH	$	(3,720	)	$	(3,690	)	$	352		$	—		$	3,338		$	(3,720	)

40

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 EFCH	$	(72	)	$	(25	)	$	178		$	—	$	(153	)	$	(72	)

41

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Nine Months Ended September 30, 2010

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	6,590		$	9		$	—		$	6,599
Fuel, purchased power costs and delivery fees		—			—			(3,521	)		—			—			(3,521	)
Net gain from commodity hedging and trading activities		—			1,372			900			—			—			2,272
Operating costs		—			—			(623	)		—			—			(623	)
Depreciation and amortization		—			—			(1,027	)		—			—			(1,027	)
Selling, general and administrative expenses		—			—			(544	)		(2	)		—			(546	)
Franchise and revenue-based taxes		—			—			(72	)		—			—			(72	)
Impairment of goodwill		—			(4,100	)		—			—			—			(4,100	)
Other income		—			37			58			—			—			95
Other deductions		—			—			(11	)		(1	)		—			(12	)
Interest income		1			288			332			—			(557	)		64
Interest expense and related charges		(204	)		(2,942	)		(1,394	)		(6	)		1,828			(2,718	)
Income (loss) before income taxes		(203	)		(5,345	)		688			—			1,271			(3,589	)
Income tax (expense) benefit		72			418			(238	)		—			(440	)		(188	)
Equity earnings of subsidiaries		(3,646	)		1,281			—			—			2,365			—
Net income (loss)		(3,777	)		(3,646	)		450			—			3,196			(3,777	)
Net (income) loss attributable to noncontrolling interests		—			—			—			—			—			—
Net income (loss) attributable to EFCH	$	(3,777	)	$	(3,646	)	$	450		$	—		$	3,196		$	(3,777	)

42

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 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 EFCH	$	347		$	493		$	463		$	(2	)	$	(954	)	$	347

43

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2010

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	31		$	(498	)	$	1,700		$	(239	)	$	—		$	994
Cash flows – financing activities:
Repayments of long-term debt		(3	)		(154	)		(86	)		—			—			(243	)
Net short-term borrowings under accounts receivable securitization program		—			—			—			228			—			228
Decrease in other short-term borrowings		—			(873	)		—			—			—			(873	)
Notes/loans from affiliates		34			770			—			—			—			804
Advances from affiliates		—			629			—			—			(629	)		—
Decrease in income tax-related note payable to Oncor		—			—			(27	)		—			—			(27	)
Contributions from noncontrolling interests		—			—			—			24			—			24
Other-net		—			—			28			—			—			28
Cash provided by (used in) financing activities		31			372			(85	)		252			(629	)		(59	)
Cash flows – investing activities:
Net loans to affiliates		(24	)		—			(887	)		—			629			(282	)
Capital expenditures		—			—			(650	)		(26	)		—			(676	)
Nuclear fuel purchases		—			—			(84	)		—			—			(84	)
Proceeds from sale of assets		—			91			50			—			—			141
Proceeds from sale of environmental allowances and credits		—			—			7			—			—			7
Purchases of environmental allowances and credits		—			—			(13	)		—			—			(13	)
Changes in restricted cash		—			—			(31	)		—			—			(31	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			937			—			—			937
Investments in nuclear decommissioning trust fund securities		—			—			(949	)		—			—			(949	)
Other-net		—			(11	)		3			—			—			(8	)
Cash provided by (used in) investing activities		(24	)		80			(1,617	)		(26	)		629			(958	)
Net change in cash and cash equivalents		38			(46	)		(2	)		(13	)		—			(23	)
Cash received from VIE		—			—			—			7			—			7
Cash and cash equivalents – beginning balance		—			77			11			6			—			94
Cash and cash equivalents – ending balance	$	38		$	31		$	9		$	—		$	—		$	78

44

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
Repayments of long-term debt		(2	)		(122	)		(93	)		—			—			(217	)
Decrease in income tax-related note payable to Oncor		7			653			—			41			(727	)		(26	)
Contributions from noncontrolling interests		—			—			—			42			—			42
Debt issuance costs		—			(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:
Net loans to affiliates		—			—			(1,255	)		—			727			(528	)
Capital expenditures and nuclear fuel purchases		—			—			(1,202	)		(61	)		—			(1,263	)
Money market fund redemptions		—			142			—			—			—			142
Reduction of restricted cash related to letter of credit facility		—			115			—			—			—			115
Other changes in restricted cash		—			—			3			—			—			3
Proceeds from sale 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	)
Net proceeds from sale of assets		—			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

45

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of September 30, 2010

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	38		$	31		$	9	$	—		$	78
Restricted cash		—			—			31			—		—			31
Advances to affiliates		3			—			6,356			—		(6,359	)		—
Trade accounts receivable – net		—			2			1,014			885		(657	)		1,244
Income taxes receivable		—			—			177			—		(177	)		—
Accounts receivable from affiliates		—			11			—			—		(11	)		—
Notes receivable from parent		—			1,690			—			—		—			1,690
Inventories		—			—			388			—		—			388
Commodity and other derivative contractual assets		—			785			2,598			—		—			3,383
Accumulated deferred income taxes		3			48			—			—		(4	)		47
Margin deposits related to commodity positions		—			—			196			—		—			196
Other current assets		—			—			40			2		—			42
Total current assets		6			2,574			10,831			896		(7,208	)		7,099
Restricted cash		—			1,135			—			—		—			1,135
Investments		(5,421	)		22,553			608			—		(17,166	)		574
Property, plant and equipment – net		—			—			20,204			105		—			20,309
Goodwill		—			6,152			—			—		—			6,152
Intangible assets – net		—			—			2,437			—		—			2,437
Commodity and other derivative contractual assets		—			1,930			623			—		—			2,553
Accumulated deferred income taxes		—			—			—			1		(1	)		—
Other noncurrent assets, principally unamortized debt issuance costs		13			450			423			6		(414	)		478
Total assets	$	(5,402	)	$	34,794		$	35,126		$	1,008	$	(24,789	)	$	40,737
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	80		$	80		$	228	$	(80	)	$	308
Advances from affiliates		—			6,359			—			—		(6,359	)		—
Long-term debt due currently		9			205			233			—		(205	)		242
Trade accounts payable		—			—			627			662		(657	)		632
Trade accounts and other payables due to affiliates		—			—			253			4		(11	)		246
Notes payable to affiliate		36			770			—			—		—			806
Commodity and other derivative contractual liabilities		—			993			1,906			—		—			2,899
Margin deposits related to commodity positions		—			361			332			—		—			693
Accrued income taxes payable to parent		18			171			—			—		(177	)		12
Accrued taxes other than income		—			—			103			—		—			103
Accumulated deferred taxes		—			—			4			—		(4	)		—
Accrued interest		33			503			371			—		(370	)		537
Other current liabilities		—			6			225			—		(4	)		227
Total current liabilities		96			9,448			4,134			894		(7,867	)		6,705
Accumulated deferred income taxes		87			1			5,720			—		110			5,918
Commodity and other derivative contractual liabilities		—			1,202			220			—		—			1,422
Notes or other liabilities due affiliates		—			—			372			—		—			372
Long-term debt held by affiliate		—			427			—			—		—			427
Long-term debt, less amounts due currently		923			29,083			28,199			—		(28,107	)		30,098
Other noncurrent liabilities and deferred credits		13			54			2,170			—		—			2,237
Total liabilities		1,119			40,215			40,815			894		(35,864	)		47,179
EFCH shareholder’s equity		(6,521	)		(5,421	)		(5,689	)		35		11,075			(6,521	)
Noncontrolling interests in subsidiaries		—			—			—			79		—			79
Total equity		(6,521	)		(5,421	)		(5,689	)		114		11,075			(6,442	)
Total liabilities and equity	$	(5,402	)	$	34,794		$	35,126		$	1,008	$	(24,789	)	$	40,737

46

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of December 31, 2009

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	77		$	11		$	6	$	—		$	94
Restricted cash		—			—			1			—		—			1
Advances to affiliates		3			—			5,470			—		(5,473	)		—
Trade accounts receivable – net		—			2			1,007			—		—			1,009
Notes receivable from parent		—			1,432			—			—		(26	)		1,406
Income taxes receivable from parent		2			—			7			—		(9	)		—
Inventories		—			—			393			—		—			393
Commodity and other derivative contractual assets		—			530			1,809			—		—			2,339
Accumulated deferred income taxes		3			—			7			—		(9	)		1
Margin deposits related to commodity positions		—			—			187			—		—			187
Other current assets		—			1			45			—		—			46
Total current assets		8			2,042			8,937			6		(5,517	)		5,476
Restricted cash		—			1,135			—			—		—			1,135
Receivable from affiliate		—			—			85			—		—			85
Investments		(1,829	)		21,308			581			—		(19,469	)		591
Property, plant and equipment – net		—			—			20,901			79		—			20,980
Goodwill		—			10,252			—			—		—			10,252
Intangible assets – net		—			—			2,593			—		—			2,593
Commodity and other derivative contractual assets		—			921			612			—		—			1,533
Accumulated deferred income taxes		55			139			—			1		(195	)		—
Other noncurrent assets, principally unamortized debt issuance costs		46			536			506			4		(492	)		600
Total assets	$	(1,720	)	$	36,333		$	34,215		$	90	$	(25,673	)	$	43,245
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	953		$	953		$	—	$	(953	)	$	953
Advances from affiliates		—			5,473			—			—		(5,473	)		—
Long-term debt due currently		8			205			294			—		(205	)		302
Trade accounts payable – nonaffiliates		—			—			744			4		—			748
Notes or other liabilities due to affiliates		26			—			200			3		(26	)		203
Commodity and other derivative contractual liabilities		—			690			1,620			—		—			2,310
Margin deposits related to commodity positions		—			151			369			—		—			520
Accrued income taxes payable to parent		—			59			—			—		(9	)		50
Accrued taxes other than income		—			—			75			—		—			75
Accumulated deferred taxes		—			9			—			—		(9	)		—
Accrued interest		46			300			184			—		(181	)		349
Other current liabilities		—			5			336			—		(2	)		339
Total current liabilities		80			7,845			4,775			7		(6,858	)		5,849
Accumulated deferred income taxes		—			—			5,590			—		(123	)		5,467
Commodity and other derivative contractual liabilities		—			717			343			—		—			1,060
Notes or other liabilities due affiliates		—			—			217			—		—			217
Long-term debt, less amounts due currently held by affiliate		—			143			—			—		—			143
Long-term debt, less amounts due currently		2,462			29,401			28,267			—		(28,152	)		31,978
Other noncurrent liabilities and deferred credits		4			58			2,687			—		—			2,749
Total liabilities		2,546			38,164			41,879			7		(35,133	)		47,463
EFCH shareholder’s equity		(4,266	)		(1,831	)		(7,664	)		35		9,460			(4,266	)
Noncontrolling interests in subsidiaries		—			—			—			48		—			48
Total equity		(4,266	)		(1,831	)		(7,664	)		83		9,460			(4,218	)
Total liabilities and equity	$	(1,720	)	$	36,333		$	34,215		$	90	$	(25,673	)	$	43,245

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

The following discussion and analysis of EFCH’s financial condition and results of operations for the three and nine months ended September 30, 2010 and 2009 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

EFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas-based holding company that conducts its operations almost entirely 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, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Key management activities, including commodity risk management, are performed on an integrated basis; consequently, there are no reportable business segments.

Significant Activities and Events

Natural Gas Prices and Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of September 30, 2010, has effectively sold forward approximately 1.25 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 156,000 GWh at an assumed 8.0 market heat rate) for the period from October 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.82 per MMBtu to $7.19 per MMBtu.

These transactions, as well as forward power sales, have effectively hedged an estimated 64% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning October 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the New York Mercantile Exchange (NYMEX) Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for the fourth quarter 2010 and more than 80% for 2011.

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 9% of the positions in the long-term hedging program as of September 30, 2010, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.

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The following table summarizes the natural gas hedges in the long-term hedging program as of September 30, 2010:

Measure

Balance 2010 (a)

2011

2012

2013

2014

Total

Natural gas hedge volumes (b)

mm MMBtu

~84

~315

~454

~285

~112

1,250

Weighted average hedge price (c)

$/MMBtu

~7.82

~7.56

~7.36

~7.19

~7.80

—

Weighted average market price (d)

$/MMBtu

~3.94

~4.44

~5.07

~5.29

~5.42

—

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

(b) Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 112 million MMBtu in 2014.

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

(d) Based on NYMEX Henry Hub prices.

Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain 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, 2010, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.25 billion in pretax unrealized mark-to-market gains or losses.

Unrealized mark-to-market net gains related to the long-term hedging program are as follows:

	Period Ended September 30, 2010
	Three Months			Nine Months
Effect of natural gas market price changes on open positions	$	934		$	2,353
Reversals of previously recorded amounts on positions settled		(263	)		(792	)
Total unrealized effect (pre-tax)	$	671		$	1,561

The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $3.539 billion and $1.978 billion as of September 30, 2010 and December 31, 2009, respectively. See discussion below under “Operating Results” for realized net gains from hedging activities, which amounts are largely related to the long-term hedging program.

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 significant cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program reflects declining forward market natural gas prices. As previously disclosed, forward natural gas prices have generally trended downward since mid-2008 as shown in the table of forward NYMEX Henry Hub natural gas prices below. While the long-term hedging program is designed to mitigate the effect on earnings of low wholesale power prices, due to low natural gas prices, these market conditions are challenging to the long-term profitability of EFCH’s generation assets. Specifically, these lower natural gas prices and the correlated effect in ERCOT on power prices could have a material adverse impact on the overall profitability of EFCH’s generation assets for periods in which it does not have significant hedge positions. A continuation or worsening of these market conditions would limit EFCH’s ability to hedge its wholesale power revenues at sufficient price levels to support its interest payments and debt maturities and could adversely impact EFCH’s ability to refinance its substantial debt due in 2014.

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Also see discussion in Note 2 to Financial Statements regarding the goodwill impairment charge recorded in the three months ended September 30, 2010.

	Forward Market Prices for Calendar Year ($/MMBtu) (a)
Date	2010 (b)		2011		2012		2013		2014
June 30, 2008	$	11.24	$	10.78	$	10.74	$	10.90	$	11.12
September 30, 2008	$	8.58	$	8.54	$	8.41	$	8.30	$	8.30
December 31, 2008	$	7.13	$	7.31	$	7.23	$	7.15	$	7.15
March 31, 2009	$	5.93	$	6.67	$	6.96	$	7.11	$	7.18
June 30, 2009	$	6.06	$	6.89	$	7.16	$	7.30	$	7.43
September 30, 2009	$	6.21	$	6.87	$	7.00	$	7.06	$	7.17
December 31, 2009	$	5.79	$	6.34	$	6.53	$	6.67	$	6.84
March 31, 2010	$	4.27	$	5.34	$	5.79	$	6.07	$	6.36
June 30, 2010	$	4.82	$	5.34	$	5.68	$	5.89	$	6.10
September 30, 2010	$	3.94	$	4.44	$	5.07	$	5.29	$	5.42

(a) Based on NYMEX Henry Hub prices.

(b) For September 30, 2010, June 30, 2010 and March 31, 2010, natural gas prices for 2010 represent the average of forward prices for October through December, July through December and April through December, respectively.

As of September 30, 2010, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility – see discussion below under “Financial Condition – Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of September 30, 2010, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

	Balance 2010 (a)		2011		2012		2013		2014
$1.00/MMBtu change in gas price (b)	$	~2	$	~50	$	~80	$	~295	$	~480
0.1/MMBtu/MWh change in market heat rate (c)	$	—	$	~15	$	~38	$	~43	$	~46
$1.00/gallon change in diesel fuel price	$	~1	$	~1	$	~5	$	~46	$	~40

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

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

(c) Based on Houston Ship Channel natural gas prices as of September 30, 2010.

Debt Issuances, Exchanges and Repurchases — See Note 4 to Financial Statements for discussion of TCEH’s issuance, exchanges and repurchases of notes, EFH Corp.’s issuance of additional notes guaranteed by EFCH and EFH Corp. and EFIH debt exchange and repurchase transactions in March through October 2010.

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TCEH Interest Rate Swap Transactions — As of September 30, 2010, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.30 billion principal amount of its senior secured debt maturing from 2010 to 2014. All of these swaps were entered into prior to January 1, 2010. Taking into consideration these swap transactions, 13% of EFCH’s total long-term debt portfolio as of September 30, 2010 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $16.30 billion principal amount of senior secured debt, including swaps entered into in 2010 related to $2.55 billion principal amount of debt and reflecting the expiration in 2010 of swaps related to an aggregate $2.50 billion principal amount of debt. All of these swaps were entered into prior to July 2010. EFCH may enter into additional interest rate hedges from time to time.

Unrealized mark-to-market net losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $181 million and $542 million for the three and nine months ended September 30, 2010, respectively. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.755 billion and $1.212 billion as of September 30, 2010 and December 31, 2009, respectively, of which $120 million and $194 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 4 to Financial Statements regarding various interest rate swap transactions.

Texas Generation Facilities Development — TCEH has substantially completed a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow and first Oak Grove units achieved substantial completion (as defined in the EPC agreements) in the fourth quarter 2009, and the second Oak Grove unit achieved substantial completion in the second quarter 2010. EFCH began depreciating the units and recognizing revenues and fuel costs for accounting purposes in those respective periods. 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 $3.23 billion was spent as of September 30, 2010. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.8 billion, and the balance was $4.7 billion as of September 30, 2010. See discussion in Note 5 to Financial Statements regarding contingencies related to these units.

Idling of Natural Gas-Fueled Units — In September 2010, after receiving affirmation from ERCOT in April 2010, EFCH mothballed (idled) four of its natural gas-fueled units, totaling 1,856 MW of capacity (1,933 MW installed nameplate capacity). As discussed in the 2009 Form 10-K, in 2009 EFCH retired 10 units, totaling 2,114 MW of capacity (2,226 MW installed nameplate capacity), mothballed three units, totaling 1,081 MW capacity (1,135 MW installed nameplate capacity) and entered into RMR (operational standby) agreements with ERCOT for two units, totaling 630 MW capacity (655 MW installed nameplate capacity).

In September 2010, EFCH notified ERCOT of plans to retire eight currently mothballed natural gas-fueled units, totaling 2,633 MW of capacity (2,771 MW installed nameplate capacity) on December 31, 2010. No impairment is expected to be recorded as a result of the planned retirements. ERCOT may affirm the retirements or request RMR agreements for them.

As of September 30, 2010, TCEH’s operational fleet of natural gas-fueled generation facilities is generally used as peaking resources and consists of 16 units, totaling 2,848 MW installed nameplate capacity, including two units under RMR agreements and excluding eight units operated for unaffiliated parties and 11 mothballed units.

51

Financial Services Reform Legislation — In July 2010, the US Congress enacted, and President Obama signed, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act). The primary purposes of the Financial Reform Act are, among other things, to address systemic risk in the financial system; to establish a Bureau of Consumer Financial Protection with broad powers to enforce consumer protection laws and promulgate rules against unfair, deceptive or abusive practices; to enhance regulation of the derivatives markets, including the requirement for central clearing of over-the-counter derivative instruments and additional capital and margin requirements for certain derivative market participants; and to implement a number of new corporate governance requirements for companies with listed or, in some cases, publicly-traded securities. While the legislation is broad and detailed, substantial portions of the legislation will require rulemaking by federal governmental agencies to either implement the standards set out in the legislation or to adopt new standards. As a result, the full scope and effect of the legislation will likely not be known for several years.

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that EFCH uses to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, end-users that are non-financial entities using the swap to hedge or mitigate commercial risk are exempt from these clearing requirements. The type of asset-backed OTC derivatives that EFCH uses to hedge commodity and interest rate risk should be exempt from the clearing requirements. In addition, existing swaps are grandfathered from the clearing requirements.

The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateral requirements are unclear as to whether an end-user or its counterparty (i.e., swap dealer) is required to post cash collateral, there is a risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. However, the legislative history of the Financial Reform Act suggests that it was not Congress’ intent to require end-users (rather that such requirement applies to swap dealers) to post cash collateral with respect to swaps. If EFCH were required to post cash collateral on its swap transactions, its liquidity would likely be materially impacted, and its ability to enter into OTC derivatives to hedge its commodity and interest rate risks would be significantly limited.

EFCH cannot predict the outcome of the rulemaking to implement the OTC derivative market provisions of the Financial Reform Act. These rulemakings could negatively affect EFCH’s ability to hedge its commodity and interest rate risks. The inability to hedge these risks would likely have a material adverse effect on EFCH’s results of operations, financial condition or cash flows.

Global Climate Change — Several bills have been introduced in the US Congress or advocated by the Obama Administration that are intended to address climate change using different approaches, including most prominently a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade). These bills include the Waxman-Markey bill, known as the American Clean Energy and Security Act of 2009 (Waxman-Markey), the Kerry-Boxer bill, known as the Clean Energy Jobs and American Power Act (Kerry-Boxer) and the Kerry-Lieberman bill, known as the American Power Act (Kerry-Lieberman). 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 was reported out of the US Senate Environment and Public Works Committee, but has not been taken up by the Senate as a whole. Kerry-Lieberman was released by its sponsors in May 2010 when it appeared that progress on passing Kerry-Boxer had stalled.

Recent developments in the US Congress indicate that the prospects for passage of any cap-and-trade legislation in this Congress are not likely. However, if any of them or similar legislation were to be adopted, EFCH’s costs of compliance could be material.

52

In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment and that emissions from motor vehicles contribute to that endangerment. The EPA’s finding required it to begin regulating GHG emissions from motor vehicles and ultimately stationary sources under existing provisions of the federal Clean Air Act. Following its endangerment finding, the EPA took three regulatory actions with respect to the control of GHG emissions. First, in March 2010, the EPA completed a reconsideration of a memorandum issued in December 2008 by then EPA Administrator Stephen Johnson on the issue of when the Clean Air Act’s Prevention of Significant Deterioration (PSD) program would apply to newly identified pollutants such as GHG’s. The EPA determined that the Clean Air Act’s PSD permit requirements would apply when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, the earliest time that PSD permitting requirements would apply to GHG emissions from stationary sources, including EFCH’s power generation facilities, would be January 2011 – the first date that new motor vehicles must meet the new GHG standards. Second, in April 2010, the EPA adopted GHG emission standards for certain new motor vehicles. Third, in June 2010, the EPA finalized its so-called “tailoring rule” that established new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources, including EFCH’s power generation facilities. The EPA’s tailoring rule defines the threshold of GHG emissions for determining applicability of the Clean Air Act’s permitting programs and PSD program at levels greater than the lower emission thresholds contained in the Clean Air Act. In addition, in September 2009, the EPA issued a final rule requiring the reporting, by March 2011, of calendar year 2010 GHG emissions from specified large GHG emissions sources in the US (such reporting rule would apply to EFCH’s lignite-fueled generation facilities).

Recent EPA Actions — The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include coal-fueled generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, in each case that may affect EFCH’s coal-fueled generation facilities.

Each of EFCH’s coal-fueled generation facilities is currently equipped with substantial emissions control equipment. All of EFCH’s coal-fueled generation facilities are equipped with activated carbon injection systems to reduce mercury emissions. Flue gas desulfurization systems designed primarily to reduce sulfur dioxide emissions are installed at Oak Grove Units 1 and 2, Sandow Units 4 and 5, Martin Lake Units 1, 2, and 3, and Monticello Unit 3. Selective catalytic reduction systems designed to reduce nitrogen oxide emissions are installed at Oak Grove Units 1 and 2 and Sandow Unit 4. Selective non-catalytic reduction systems designed to reduce nitrogen oxide emissions are installed at Sandow Unit 5, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Fabric filter systems designed primarily to reduce particulate matter emissions are installed at Oak Grove Units 1 and 2, Sandow Unit 5, Monticello Units 1 and 2, and Big Brown Units 1 and 2. Electrostatic precipitator systems designed primarily to reduce particulate matter emissions are installed at Sandow Unit 4, Martin Lake Units 1, 2, and 3, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Sandow Unit 5 uses a fluidized bed combustion process that facilitates control of nitrogen oxides and sulfur dioxide. Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitator systems also assist in reducing mercury and other emissions.

There is no assurance that the currently-installed emissions control equipment at EFCH’s coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Some of the potential EPA or TCEQ regulatory actions could require EFCH to install significant additional control equipment, resulting in material costs of compliance for its generation units, including capital expenditures and higher operating costs. These costs could result in material adverse effects on EFCH’s financial condition, liquidity and results of operations.

Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions — Following the invalidation of the Clean Air Interstate Rule (CAIR) by the federal courts in July 2008, the EPA was required to revise CAIR to correct the shortcomings identified by the federal courts. In July 2010, the EPA released a proposed rule called the Clean Air Transport Rule (CATR). The CATR, as proposed, would replace CAIR in 2012 and would require no additional emission reductions for Luminant. However, EFCH cannot predict the impact of a final rule on its business, results of operations and financial condition.

The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted State Implementation Plan (SIP) rules in May 2007 to deal with eight-hour ozone standards, which required nitrogen oxide emission reductions from certain of EFCH’s peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposed to further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. Since the EPA projects that SIP rules to address attainment of these new more stringent standards will not be required until December 2013, EFCH cannot yet predict the impact of this action on its generation facilities. In January 2010, the EPA added a new one-hour nitrogen oxide National Ambient Air Quality standard that may require actions within Texas to reduce emissions. The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required by January 2021/2022. In June 2010, the EPA adopted a new one-hour sulfur dioxide national ambient air quality standard that may require action within Texas to reduce sulfur dioxide emissions. The TCEQ will be required to conduct modeling and develop an implementation plan by 2014, pursuant to which compliance will be required by 2017, according to the EPA’s implementation timeline. EFCH cannot predict the impact of the new standards on its business, results of operations or financial condition until the TCEQ adopts (if required) an implementation plan with respect to the standards. If the TCEQ adopts implementation plans that require EFCH to install additional emissions controls, or if the EPA adopts more stringent requirements through any of the number of potential rulemaking activities in which it is or may be engaged, EFCH could incur material capital expenditures and higher operating costs, resulting in material adverse effects on its financial condition, liquidity and results of operations.

The EPA has also agreed, in a federal court consent decree, to publish proposed regulations concerning emissions of mercury and other hazardous air pollutants from electricity generating units by March 2011, and to finalize those regulations late in 2011. EFCH cannot predict the substance of any final EPA regulations on such hazardous air pollutants. However, the EPA has informally indicated that recently proposed regulations regarding hazardous air pollutants from industrial boilers may serve as a template for the forthcoming electricity generating unit regulations. The industrial boiler regulations, if applied to electricity generating units, would likely require significant additions of control equipment. If required, such additions would result in material costs of compliance for EFCH’s generation units, including capital expenditures to install new control equipment and higher operating costs, resulting in material adverse effects on EFCH’s financial condition, liquidity and results of operations.

In October 2010, the EPA proposed to retroactively disapprove a portion of the SIP pursuant to which the state implements its program to achieve the EPA’s National Ambient Air Quality Standards (NAAQS) under the Clean Air Act. In particular, the EPA proposes to retroactively disapprove certain standard permits for pollution control projects that the TCEQ adopted approximately 10 years ago. The EPA asserts that EFCH holds such standard permits for two generation facilities (Big Brown and Stryker Creek). EFCH is investigating the basis for the EPA’s assertion. The EPA has proposed to disapprove this portion of the SIP while acknowledging that emissions covered by these standard permits do not threaten attainment or maintenance of the NAAQS under the Clean Air Act. EFCH believes the TCEQ’s adoption of the standard permit was consistent with the Clean Air Act. However, EFCH cannot predict whether the EPA will take final action to disapprove this portion of the SIP. If the EPA takes final disapproval action, and if that causes EFCH to undertake additional permitting activity and install additional emissions control equipment at its affected generation facilities, EFCH could incur material capital expenditures, resulting in material adverse effects on its financial condition, liquidity and results of operations.

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Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled Generation — Treatment, storage and disposal of solid and hazardous waste are regulated at the federal and state level. In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured, releasing a significant quantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of EFCH’s impoundments, which are significantly smaller than TVA’s and are inspected on a regular basis. EFCH routinely samples groundwater monitoring wells to ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, in May 2010, the EPA released a proposed rule that considers regulating coal combustion residuals as either a hazardous waste or a non-hazardous waste. EFCH is unable to predict the requirements of a final rule; however, the potential cost of compliance could be material.

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RESULTS OF OPERATIONS

Sales Volume and Customer Count Data

	Three Months  Ended September 30,									Nine Months  Ended September 30,
	2010			2009			% Change			2010			2009			% Change
Sales volumes:
Retail electricity sales volumes — (GWh):
Residential		9,473			9,348			1.3			23,040			22,312			3.3
Small business (a)		2,417			2,598			(7.0	)		6,392			6,228			2.6
Large business and other customers		4,294			4,049			6.1			11,738			10,905			7.6
Total retail electricity		16,184			15,995			1.2			41,170			39,445			4.4
Wholesale electricity sales volumes		14,011			10,126			38.4			37,359			30,180			23.8
Net sales (purchases) of balancing electricity to/from ERCOT		302			(38	)		—			572			(304	)		—
Total sales volumes		30,497			26,083			16.9			79,101			69,321			14.1
Average volume (kWh) per residential customer (b)		5,220			4,936			5.8			12,584			11,772			6.9
Weather (North Texas average) — percent of normal (c):
Cooling degree days		107.1	%		97.1	%		10.3			109.9	%		102.2	%		7.5
Heating degree days		—	%		—	%		—			132.1	%		93.7	%		41.0
Customer counts:
Retail electricity customers (end of period and in thousands) (d):
Residential											1,800			1,876			(4.1	)
Small business (a)											228			273			(16.5	)
Large business and other customers											22			23			(4.3	)
Total retail electricity customers											2,050			2,172			(5.6	)

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

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

(c) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over a 10-year period.

(d) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers.

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Revenue and Commodity Hedging and Trading Activities

	Three Months  Ended September 30,						%			Nine Months  Ended September 30,						%
	2010			2009			Change			2010			2009			Change
Operating revenues:
Retail electricity revenues:
Residential	$	1,231		$	1,272			(3.2	)	$	3,007		$	3,048			(1.3	)
Small business (a)		309			366			(15.6	)		839			924			(9.2	)
Large business and other customers		340			330			3.0			931			955			(2.5	)
Total retail electricity revenues		1,880			1,968			(4.5	)		4,777			4,927			(3.0	)
Wholesale electricity revenues (b)		642			380			68.9			1,612			1,043			54.6
Net sales (purchases) of balancing electricity to/from ERCOT		(6	)		(5	)		(20.0	)		(23	)		(50	)		54.0
Amortization of intangibles (c)		14			20			(30.0	)		16			10			60.0
Other operating revenues		77			70			10.0			217			214			1.4
Total operating revenues	$	2,607		$	2,433			7.2		$	6,599		$	6,144			7.4
Net gain from commodity hedging and trading activities:
Unrealized net gains from changes in fair value	$	979		$	136			—		$	2,255		$	1,026
Unrealized net losses representing reversals of previously recognized fair values of positions settled in the current period		(238	)		(116	)		—			(698	)		(257	)		—
Realized net gains on settled positions		251			103			—			715			234			—
Total gain	$	992		$	123			—		$	2,272		$	1,003			—

(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.” (The offsetting differences between contract and market prices are reported in net gain (loss) from commodity hedging and trading activities.) These amounts are as follows:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010		2009
Reported in revenues	$	42		$	(11	)	$	10	$	(135	)
Reported in fuel and purchased power costs		(16	)		(6	)		48		79
Net gain (loss)	$	26		$	(17	)	$	58	$	(56	)

(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,									Nine Months Ended September 30,
	2010			2009			% Change			2010			2009			% Change
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	43		$	30	(e)		43.3		$	116		$	88	(e)		31.8
Lignite/coal		246			175			40.6			678			474			43.0
Total baseload fuel		289			205			41.0			794			562			41.3
Natural gas fuel and purchased power (a)		580			431			34.6			1,294			953			35.8
Amortization of intangibles (b)		45			82	(e)		(45.1	)		125			222	(e)		(43.7	)
Other costs		46			39			17.9			152			145			4.8
Fuel and purchased power costs		960			757			26.8			2,365			1,882			25.7
Delivery fees		440			430			2.3			1,156			1,105			4.6
Total	$	1,400		$	1,187			17.9		$	3,521		$	2,987			17.9
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	8.13		$	5.76	(e)		41.1		$	7.84		$	5.67	(e)		38.3
Lignite/coal (c)		18.24			16.53			10.3			19.18			16.49			16.3
Natural gas fuel and purchased power		54.33			47.99			13.2			49.56			44.06			12.5
Delivery fees per MWh	$	27.13		$	26.68			1.7		$	28.01		$	27.77			0.9
Production and purchased power volumes (GWh):
Nuclear		5,302			5,219			1.6			14,841			15,512			(4.3	)
Lignite/coal		15,445			12,209			26.5			40,743			32,914			23.8
Total baseload generation		20,747			17,428			19.0			55,584			48,426			14.8
Natural gas-fueled generation		763			1,135			(32.8	)		1,598			2,168			(26.3	)
Purchased power		9,905			7,890			25.5			24,505			19,523			25.5
Total energy supply		31,415			26,453			18.8			81,687			70,117			16.5
Less line loss and power imbalances (d)		918			370			—			2,586			796			—
Net energy supply volumes		30,497			26,083			16.9			79,101			69,321			14.1
Baseload capacity factors:
Nuclear		104.4	%		103.1	%		1.3			98.5	%		103.1	%		(4.5	)
Lignite/coal		89.7	%		94.0	%		(4.6	)		82.0	%		85.9	%		(4.5	)
Total baseload		93.2	%		96.6	%		(3.5	)		86.0	%		90.7	%		(5.2	)

(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.

(e) Reflects reclassification to correct amortization.

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Financial Results

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Operating revenues increased $174 million, or 7%, to $2.607 billion in 2010.

Wholesale electricity revenues increased $262 million, or 69%, to $642 million in 2010. A 38% increase in wholesale electricity sales volumes, primarily reflecting production from the new generation units and increased sales to third-party REPs, increased revenue $150 million. An 11% increase in average wholesale electricity prices, reflecting higher natural gas prices at the time underlying contracts were executed, increased revenues by $59 million. The balance of the revenue increase reflected unrealized gains in 2010 compared to unrealized losses in 2009 related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

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

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

Retail electricity revenues decreased $88 million, or 4%, to $1.880 billion and reflected the following:

• Lower average pricing decreased revenues by $111 million reflecting declines in both the business and residential markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

• A 1% increase in sales volumes increased revenues by $23 million. Residential sales volumes increased 1% reflecting greater average consumption driven by hotter weather, partially offset by a 4% decrease in customer count due to competitive activity. Business sales volumes increased 1% reflecting a change in customer mix resulting from contracts executed with new customers.

Fuel, purchased power costs and delivery fees increased $213 million, or 18%, to $1.4 billion in 2010. Higher purchased power costs contributed $131 million to the increase and reflected an increase of 26% in purchased volumes driven by increased unplanned generation unit outages and higher sales to third-party REPs, as well as higher prices driven by higher natural gas prices at the time underlying contracts were executed. Other factors contributing to the increase included $36 million in higher lignite/coal costs at existing plants, driven by higher transportation and commodity costs for purchased coal, $35 million in higher lignite fuel costs related to production from the new generation units, a $13 million increase in nuclear fuel expense reflecting increased prices, a $10 million increase in unrealized losses related to physical derivative commodity purchase contracts, a $10 million increase in delivery costs and a $5 million increase in natural gas costs driven by higher prices. These increases were partially offset by $37 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting and reflected expiration of commodity contracts and consumption of the nuclear fuel.

Overall baseload generation production increased 19% in 2010 driven by the production in 2010 from the new generation units.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the three months ended September 30, 2010 and 2009, which totaled $992 million and $123 million, respectively:

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Three Months Ended September 30, 2010 — Unrealized mark-to-market net gains totaling $741 million included:

• $750 million in net gains related to hedge positions, which includes $980 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 $230 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

• $9 million in net losses related to trading positions, which largely represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $251 million included:

• $235 million in net gains related to positions that primarily hedged electricity revenues recognized in the period largely related to the long-term hedging program, and

• $16 million in net gains related to trading positions.

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 included:

• $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.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $26 million in net gains in 2010 and $17 million in net losses in 2009.

Operating costs increased $36 million, or 22%, to $197 million in 2010. The increase reflected $26 million related to the new generation units. The balance of the increase reflected various base maintenance activities.

Depreciation and amortization increased $42 million, or 14%, to $345 million in 2010. The increase was driven by depreciation of the new generation units and associated mining operations.

SG&A expenses decreased $9 million, or 5%, to $183 million in 2010. The decrease reflected $13 million in lower bad debt expense reflecting 2009 delinquencies due to delays in final bills and disconnects resulting from a system conversion, $5 million in lower marketing expenses and $3 million in lower employee compensation-related expense, partially offset by $12 million of costs allocated from corporate in 2010, principally fees paid to the Sponsor Group and individually insignificant increases in various other expenses.

See Note 2 to Financial Statements for discussion of the $4.1 billion impairment of goodwill recorded in 2010.

Other income totaled $6 million in 2010 and $33 million in 2009. The 2009 amount included a $23 million reversal of a use tax accrual and a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement. See Note 13 to Financial Statements for additional details.

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Interest expense and related charges increased by $63 million to $905 million in 2010 reflecting a $74 million decrease in capitalized interest due to completion of certain new generation facility construction activities and a $43 million increase in unrealized mark-to-market net losses related to interest rate swaps, partially offset by a $37 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges, reflecting values attributed to earlier periods. The remaining $17 million variance was driven by lower average borrowings.

Income tax expense totaled $191 million in 2010 compared to income tax benefit of $36 million on a loss in 2009. Excluding the $4.1 billion nondeductible goodwill impairment charge in 2010, the effective tax rates were 33.5% and 33.3%, respectively. The 2010 effective rate reflected a reversal of interest accrued on uncertain tax positions. The 2009 rate was depressed by the interest accrued on such positions, reflecting the loss position.

Net loss for EFCH increased $3.648 billion to a loss of $3.720 billion in 2010 reflecting the $4.1 billion goodwill impairment charge and increased interest expense, partially offset by an increase in realized and unrealized net gains from commodity hedging and trading activities.

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Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Operating revenues increased $455 million, or 7%, to $6.599 billion in 2010.

Wholesale electricity revenues increased $569 million, or 55%, to $1.612 billion in 2010. A 24% increase in wholesale electricity sales volumes, reflecting production from the new generation units and increased sales to third party REPs, increased revenues by $280 million. A 10% increase in average wholesale electricity prices, reflecting higher natural gas prices at the time the underlying contracts were executed, increased revenues by $145 million. The balance of the revenue increase reflected unrealized gains in 2010 compared to unrealized losses in 2009 related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

Retail electricity revenues decreased $150 million, or 3%, to $4.777 billion and reflected the following:

• Lower average pricing decreased revenues by $366 million reflecting declines in both the business and residential markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

• A 4% increase in sales volumes increased revenues by $216 million reflecting increases in both the business and residential markets. A 6% increase in business markets sales volumes reflected a change in customer mix resulting from contracts executed with new customers. Higher average consumption resulted in a 3% overall increase in residential sales volumes, reflecting colder winter weather and hotter summer weather, partially offset by a decline in residential customer counts.

Fuel, purchased power costs and delivery fees increased $534 million, or 18%, to $3.521 billion in 2010. Higher purchased power costs contributed $295 million to the increase and reflected increased volumes driven by increased planned and unplanned generation unit outages and higher retail demand, as well as increased prices driven by the effect of higher natural gas prices at the time the underlying contracts were executed. Other factors contributing to the increase included $105 million in lignite fuel costs related to production from the new generation units, $99 million in higher lignite/coal costs at existing plants, reflecting higher purchased coal transportation and commodity costs, $51 million in higher delivery fees, reflecting increased retail sales volumes and tariffs, a $31 million decrease in unrealized gains related to physical derivative commodity purchase contracts, a $28 million increase in nuclear fuel expense reflecting increased prices and a $12 million increase in natural gas and fuel oil costs driven by higher prices. These increases were partially offset by $97 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting and reflected expiration of commodity contracts and consumption of the nuclear fuel.

Overall baseload generation production increased 15% in 2010 reflecting a 24% increase in lignite/coal-fueled production, driven by production from new generation units, partially offset by a 4% decrease in nuclear production reflecting an unplanned transformer outage in January 2010 and year-to-year timing differences of planned outages.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the nine months ended September 30, 2010 and 2009, which totaled $2.272 billion and $1.003 billion, respectively:

Nine Months Ended September 30, 2010 — Unrealized mark-to-market net gains totaling $1.557 billion included:

• $1.564 billion in net gains related to hedge positions, which includes $2.232 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 $668 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

• $7 million in net losses related to trading positions, which includes $23 million in net gains from changes in fair value, and $30 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

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Realized net gains totaling $715 million included:

• $666 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, largely related to the long-term hedging program, and

• $49 million in net gains related to trading positions.

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 fair values of 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 fair values of positions settled in the period.

Realized net gains totaling $234 million include:

• $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.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $58 million in net gains in 2010 and $56 million in net losses in 2009.

Operating costs increased $119 million, or 24%, to $623 million in 2010. The increase reflected $71 million in incremental expense related to the new generation units and $26 million in outage-related costs at the Comanche Peak nuclear-fueled plant reflecting year-to-year timing of planned outage maintenance costs and the first quarter 2010 unplanned transformer-related outage. The balance of the increase reflected increased costs related to outages at the legacy lignite/coal operations and various individually insignificant increases.

Depreciation and amortization increased $165 million, or 19%, to $1.027 billion in 2010. The increase reflected $129 million in incremental expense related to the new generation units and associated mining operations. The balance of the increase was primarily driven by equipment additions.

SG&A expenses decreased $9 million, or 2%, to $546 million in 2010. The decrease reflected:

• $23 million in lower transition costs associated with outsourced services and the retail customer information management system implemented in 2009;

• $13 million in lower employee compensation-related expense in 2010; and

• $9 million of accounts receivable securitization program fees that are reported in 2010 as interest expense and related charges (see Note 5 to Financial Statements),

partially offset by:

• $35 million of costs allocated from corporate in 2010, principally fees paid to the Sponsor Group, and

• $4 million in higher marketing expenses in 2010.

See Note 2 to Financial Statements for discussion of the $4.1 billion impairment of goodwill recorded in 2010. The $70 million impairment of goodwill recorded in 2009 resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008 as discussed in Note 3 to Financial Statements in the 2009 Form 10-K.

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Other income totaled $95 million in 2010 and $38 million in 2009. Other income in 2010 included a $44 million gain on the sale of land and related water rights and a $37 million gain associated with the sale of interests in a natural gas gathering pipeline business. The 2009 amount included a $23 million reversal of a use tax accrual. Other deductions totaled $12 million in 2010 and $19 million in 2009 and included a number of individually immaterial expenses. See Note 13 to Financial Statements for additional details.

Interest income increased $25 million, or 64%, to $64 million in 2010 reflecting higher notes receivable balances from affiliates.

Interest expense and related charges increased by $1.171 billion, or 76%, to $2.718 billion in 2010 reflecting a $542 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $527 million net gain in 2009 and a $199 million decrease in capitalized interest due to completion of new generation facility construction activities, partially offset by a $68 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges, reflecting values attributed to earlier periods.

Income tax expense totaled $188 million in 2010 compared to $259 million in 2009. Excluding the $4.1 billion and $70 million nondeductible goodwill impairment charges in 2010 and 2009, respectively, the effective tax rates were 36.8% and 38.3%, respectively. The decrease in the rate reflected the reversal of interest accrued on uncertain tax positions in 2010.

Results for EFCH decreased $4.124 billion in 2010 to a loss of $3.777 billion reflecting the $4.1 billion goodwill impairment charge and increased interest expense, partially offset by an increase in net gains from commodity hedging and trading activities.

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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, 2010 and 2009. The net change in these assets and liabilities, excluding “other activity” as described below, represents the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 9 to Financial Statements). The portfolio consists primarily of economic hedges but also includes trading positions.

	Nine Months  Ended September 30,
	2010			2009
Commodity contract net asset at beginning of period	$	1,718		$	430
Settlements of positions (a)		(642	)		(314	)
Changes in fair value (b)		2,255			1,026
Other activity (c)		39			63
Commodity contract net asset at end of period	$	3,370		$	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) Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”).

(c) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold and physical natural gas exchange transactions. 2010 amount includes $59 million related to net payment of option premiums and $19 million related to settlement of a power sales agreement, partially offset by $35 million for expired option premiums and $4 million in natural gas provided under physical gas exchange transactions. 2009 amount includes $28 million related to net payment of option premiums, $25 million in natural gas provided under physical gas exchange transactions and $15 million related to settlement of a power sales agreement, partially offset by $5 million for expired option premiums.

Unrealized gains and losses related to commodity contracts are summarized as follows:

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2010		2009		2010		2009
Unrealized gains/(losses) related to contracts marked-to-market	$	765	$	3	$	1,613	$	712
Ineffectiveness gains/(losses) related to cash flow hedges (a)		2		—		2		1
Total unrealized gains (losses) related to commodity contracts	$	767	$	3	$	1,615	$	713

(a) Represents the reversal of previously recorded ineffectiveness upon settlement of such dedesignated hedges in 2010.

Following are the components of the net commodity contract asset as of September 30, 2010:

Amount of net asset arising from mark-to-market accounting	$	3,374
Net liability associated with natural gas under physical gas exchange transactions		(4	)
Net commodity contract asset	$	3,370

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Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of September 30, 2010, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract asset as of  September 30, 2010
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(144	)	$	(39	)	$	(1	)	$	—		$	(184	)
Prices provided by other external sources		1,300			1,875			129			—			3,304
Prices based on models		4			(16	)		384			(118	)		254
Total	$	1,160		$	1,820		$	512		$	(118	)	$	3,374
Percentage of total fair value		34	%		54	%		15	%		(3	)%		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 7 to Financial Statements for fair value disclosures and discussion of fair value measurements.

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FINANCIAL CONDITION

Liquidity and Capital Resources

Cash Flows — Cash provided by operating activities for the nine months ended September 30, 2010 and 2009 totaled $994 million and $1.471 billion, respectively. The decrease in cash provided of $477 million was driven by a $667 million effect of the amended accounting standard related to the accounts receivable securitization program (see Note 3 to Financial Statements), under which the $383 million of funding under the program upon the January 1, 2010 adoption is reported as a use of operating cash flows and a source of financing cash flows, with subsequent 2010 activity reported as financing, while the $284 million of funding in 2009 is reported as operating cash flows. The decrease was partially offset by the effect of higher earnings as adjusted for noncash items, reflecting the contribution of new generation units.

Cash used in financing activities increased $346 million as summarized below (see Note 4 to Financial Statements):

	Nine Months Ended September 30,
	2010			2009
Net issuances, repayments and repurchases of borrowings	$	(1,116	)	$	270
Increase in notes/loans from affiliates		804			—
Net short-term borrowings under accounts receivable securitization program		228			—
Decrease in income tax related note payable to Oncor (see Note 12 to Financial Statements)		(27	)		(26	)
Contributions from noncontrolling interests		24			42
Other		28			1
Total provided by (used in) financing activities	$	(59	)	$	287
Cash used in investing activities decreased $525 million as summarized below:
	Nine Months Ended September 30,
	2010			2009
Net (loans to) repayments from affiliates	$	(282	)	$	(528	)
Capital expenditures, including nuclear fuel		(760	)		(1,263	)
Proceeds from sale of assets		141			40
Redemption of investment held in money market fund		—			142
Change in restricted cash		(31	)		118
Other		(26	)		8
Total used in investing activities	$	(958	)	$	(1,483	)

The decline in capital spending for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009 primarily reflected a decrease in spending related to the construction of the now substantially complete new generation facilities.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $245 million and $305 million for the nine months ended September 30, 2010 and 2009, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice, and amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and delivery fees and interest expense and related charges.

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Debt Financing Activity — Activities related to short-term borrowings and long-term debt during the nine months ended September 30, 2010 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt issuance costs):

	Borrowings (a)		Repayments and Repurchases
TCEH	$	110	$	237
EFCH		—		3
EFH Corp (pushed down to EFCH) (b)		409		1,946
Total long-term		519		2,186
Total short-term – TCEH (c)		—		873
Total	$	519	$	3,059

(a) Consists of the following noncash principal increases: $81 million of EFH Corp. Toggle Notes and $110 million of TCEH Toggle Notes issued in May 2010 in payment of accrued interest as discussed below under “Toggle Notes Interest Election” and $328 million of EFH Corp. 10% Notes issued in debt exchanges as discussed in Note 4 to Financial Statements.

(b) Includes $1.946 billion of noncash retirements (including discounts captured on cash repurchases) as a result of 2010 debt repurchase and exchange transactions discussed in Note 4 to Financial Statements.

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

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

EFCH or its affiliates or agents may from time to time purchase EFCH’s or its subsidiaries’ outstanding debt for cash in open market purchases or privately negotiated transactions (including pursuant to a Section 10b-5(1) plan) or via privately negotiated exchange transactions similar to the EFH Corp. private exchange transactions completed in 2010, or it may refinance existing debt. EFCH and/or its affiliates will evaluate any such transactions in light of market prices of the debt, taking into account liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material.

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Available Liquidity — The following table summarizes changes in EFCH’s available liquidity for the nine months ended September 30, 2010.

	Available Liquidity
	September 30, 2010		December 31, 2009		Change
Cash and cash equivalents	$	78	$	94	$	(16	)
TCEH Revolving Credit Facility (a)		2,620		1,721		899
TCEH Letter of Credit Facility		410		399		11
Subtotal	$	3,108	$	2,214	$	894
Short-term investment (b)		—	$	65	$	(65	)
Total liquidity (c)	$	3,108	$	2,279	$	829

(a) As of September 30, 2010 and December 31, 2009, the TCEH Revolving Credit Facility includes $229 million and $141 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender.

(b) December 31, 2009 amount includes $65 million in letters of credit posted related to certain interest rate transactions. Pursuant to the related agreement, the collateral was returned in March 2010. See Note 9 to Financial Statements.

(c) As of September 30, 2010 and December 31, 2009, total liquidity includes $693 million and $520 million, respectively, of cash received for “margin deposits related to commodity positions” and is net of cash totaling $196 million and $187 million, respectively, posted with counterparties as “margin deposits related to commodity positions.”

Note: Available liquidity in the future could benefit from additional exercises of the payment-in-kind (PIK) option on the TCEH Toggle Notes, which for the remaining payment dates from November 2010 through November 2012 would avoid cash interest payments of approximately $423 million.

The $829 million increase in available liquidity reflected a $770 million repayment of borrowings under the TCEH Revolving Credit Facility that was funded by borrowing under a demand note payable to EFH Corp. (See Note 12 to Financial Statements.)

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

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

TCEH made its May 2010 interest payment and will make its November 2010 interest payment on the TCEH Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $110 million in May 2010, including $3 million principal amount paid to EFH Corp., and will further increase the aggregate principal amount of the notes by $102 million in November 2010, including $4 million principal amount paid to EFH Corp. The elections increased liquidity in May 2010 by an amount equal to $103 million and will further increase liquidity in November 2010 by an amount equal to an estimated $95 million, constituting the amounts of cash interest that otherwise would have been payable on the notes in May 2010 and November 2010, respectively.

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Similarly, EFH Corp. made its May 2010 interest payment and will make its November 2010 interest payment on the EFH Corp. Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $162 million in May 2010 and will further increase the aggregate principal amount of the notes by a currently estimated $32 million in November 2010 (excluding $130 million principal amount to be issued to EFIH as holder of $2.166 billion principal amount of EFH Corp. Toggle Notes acquired in the debt exchange completed in August 2010 that is eliminated in consolidation and not subject to push down to EFCH as discussed in Note 4 to Financial Statements). The elections increased liquidity in May 2010 by an amount equal to $152 million and will further increase liquidity in November 2010 by an amount equal to a currently estimated $30 million (excluding $122 million related to notes held by EFIH), constituting the amounts of cash interest that otherwise would have been payable on the notes in May 2010 and November 2010, respectively.

See Note 4 to Financial Statements for discussion of debt repurchase and exchange transactions in 2010 that resulted in TCEH, EFH Corp. and EFIH acquiring portions of the outstanding principal of the EFH Corp. and TCEH Toggle Notes held by unaffiliated parties that are reflected in the amounts related to the May 2010 and November 2010 PIK elections.

Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving credit facility, funds the cash collateral posting requirements for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of this facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the TCEH Commodity Collateral Posting Facility, as of September 30, 2010, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. See Note 4 to Financial Statements for more information about this facility.

As of September 30, 2010, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $193 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $183 million posted as of December 31, 2009;

• $690 million in cash has been received from counterparties, net of $3 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $516 million received, net of $4 million in cash posted, as of December 31, 2009;

• $325 million in letters of credit have been posted with counterparties, as compared to $379 million posted as of December 31, 2009, and

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

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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, 2010, restricted cash collateral held totaled $31 million. See Note 13 to Financial Statements regarding restricted cash.

With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit postings to counterparties. As of September 30, 2010, approximately 450 million MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped TCEH Commodity Collateral Posting Facility supports the collateral posting requirements related to substantially all of these transactions.

Accounts Receivable Securitization Program — TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). As discussed in Note 1 to Financial Statements, in accordance with amended transfers and servicing accounting standards, the trade accounts receivable amounts under the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $228 million and $383 million as of September 30, 2010 and December 31, 2009, respectively. See Note 3 to Financial Statements for a more complete description of the program including amendments to the program in June 2010, the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of EFCH’s financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of September 30, 2010, EFCH was in compliance with all such covenants.

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

Adjusted EBITDA (as used in the maintenance covenant contained in the TCEH Senior Secured Facilities) for the twelve months ended September 30, 2010 totaled $3.916 billion for TCEH. See Exhibits 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, 2010 and 2009.

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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, the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes as of September 30, 2010 and December 31, 2009 and the corresponding maintenance and other covenant threshold levels as of September 30, 2010:

	September 30, 2010		December 31, 2009		Threshold Level as of September 30, 2010
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to Adjusted EBITDA ratio (a)		4.84 to 1.00		4.76 to 1.00		Must not exceed 7.00 to 1.00 (b)
Debt Incurrence Covenants:
EFH Corp. Senior Secured Notes:
EFH Corp. fixed charge coverage ratio		1.3 to 1.0		1.2 to 1.0		At least 2.0 to 1.0
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (Sponsor Group payments):
EFH Corp. leverage ratio		8.5 to 1.0		9.4 to 1.0		Equal to or less than 7.0 to 1.0
EFH Corp. Senior Secured Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (c)		1.6 to 1.0		1.4 to 1.0		At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (c)		1.3 to 1.0		1.2 to 1.0		At least 2.0 to 1.0
EFH Corp. leverage ratio		8.5 to 1.0		9.4 to 1.0		Equal to or less than 7.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0		At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to Adjusted EBITDA ratio		7.9 to 1.0		8.4 to 1.0		Equal to or less than 6.5 to 1.0

(a) In accordance with the terms of the TCEH Senior Secured Facilities and as the result of the new Sandow and first Oak Grove generating units achieving average capacity factors of greater than or equal to 70% for the three months ended March 31, 2010, the maintenance covenant as of September 30, 2010 includes pro forma twelve months Adjusted EBITDA for the units and the proportional amount of outstanding debt under the Delayed Draw Term Loan (see Note 4 to Financial Statements) applicable to the two units.

(b) Threshold level will decrease to a maximum of 6.75 to 1.00 effective December 31, 2010 and 6.50 to 1.00 effective December 31, 2011. Calculation excludes debt that ranks junior to the TCEH Senior Secured Facilities.

(c) 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.

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, 2010, counterparties to those contracts could have required TCEH to post up to an aggregate of $8 million in additional collateral. This amount largely represents the below market terms of these contracts as of September 30, 2010; thus, this amount will vary depending on the value of these contracts on any given day.

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Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of September 30, 2010, 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 $14 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, 2010, TCEH posted letters of credit in the amount of $84 million, which are subject to adjustments. See “Regulatory Matters – Certification of REPs.”

The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $650 million to $900 million. The actual amount (if required) could vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.

ERCOT has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $36 million as of September 30, 2010 (which is subject to weekly adjustments based on settlement activity with ERCOT).

Other arrangements of EFCH 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, EFCH 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 of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the accounts receivable securitization 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 will allow the lenders to accelerate the maturity of outstanding balances ($21.330 billion as of September 30, 2010) under such facilities.

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

Under the terms of a TCEH rail car lease, which had $45 million in remaining lease payments as of September 30, 2010 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

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Under the terms of a TCEH rail car lease, which had $51 million in remaining lease payments as of September 30, 2010 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

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

EFCH 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 EFCH 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 $1.755 billion as of September 30, 2010 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

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 Note 5 and 12 to Financial Statements regarding guarantees and VIEs.

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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REGULATORY MATTERS

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, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the new financial requirements, TXU Energy filed an amended certification, which became effective in March 2010. As a result, TCEH posted letters of credit in March 2010 totaling $84 million with the PUCT securing its payment obligations to TDUs, and is no longer required to reserve liquidity for such purposes. Liquidity reserved as of December 31, 2009 totaled $228 million.

Wholesale Market Design – Nodal Market

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

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

• operate a voluntary day-ahead energy market;

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

• use nodal energy prices for resources;

• provide information for energy trading hubs by aggregating nodes;

• use zonal prices for loads, and

• provide congestion revenue rights (CRRs) (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 instead of across the geographic zones. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. The implementation of a nodal market is scheduled for December 2010. While EFCH cannot predict the ultimate impact of the proposed nodal wholesale market design on its operations or financial results, such change could ultimately have an adverse impact on the profitability and value of EFCH’s business, particularly if such change results in lower revenue due to lower wholesale power prices, increased costs or increased collateral posting requirements with ERCOT.

In 2010, ERCOT began conducting market testing activities in preparation for the December 2010 transition to the nodal market design. These testing activities have included certifying qualified scheduling entities (QSEs) to participate in the day-ahead and real-time markets, conducting market-wide tests of ERCOT’s nodal operation systems to deploy generation resources to maintain grid frequency, holding mock auctions related to CRRs and conducting simulations of day-ahead market operations with market participants. In addition to these operational market testing activities, ERCOT has provided simulated full financial settlement and calculation of simulated credit exposure and collateral requirements for each simulated operating day. EFCH has participated in these activities and is currently fully certified for participating in both the day-ahead market and real-time operations. Additionally, all of EFCH’s operational and mothballed generation assets and its QSEs have completed certification for operation in the nodal market. In October 2010, ERCOT’s board authorized nodal implementation to commence on December 1, 2010.

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Sunset Review — PURA, the PUCT, the RRC, ERCOT, the TCEQ and the Office of Public Utility Counsel (OPUC) will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT, the RRC, ERCOT, the TCEQ or the OPUC), along with an evaluation of the advisability of any changes to that agency’s authorizing legislation (PURA). A Sunset staff report on the PUCT offering various recommendations for consideration by the Sunset Commission was issued in April 2010, and the related Sunset public meeting was conducted in May 2010. The Sunset Commission met in July 2010 and adopted various recommendations regarding the PUCT, ERCOT and the OPUC. A Sunset staff report on the RRC is scheduled to be issued in October 2010 and the related Sunset public meeting is scheduled for November 2010. The Sunset Commission will submit its recommendations for the Texas Legislature’s consideration during the next session, which begins in January 2011. EFCH cannot predict the outcome of the sunset review process.

Mine Safety Disclosures — Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act

Safety is a top priority in all of EFCH’s businesses, and accordingly, it is a key component of EFCH’s focus on operational excellence, its employee performance reviews and employee compensation. EFCH’s health and safety program objectives are to prevent workplace accidents to ensure all employees return home safely and comply with all regulations.

EFCH currently owns and operates 12 surface lignite coal mines in Texas to provide fuel for its electricity generation facilities. These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act) as well as other regulatory agencies such as the RRC. The MSHA inspects US mines, including EFCH’s, on a regular basis and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed to the Federal Mine Safety and Health Review Commission (FMSHRC), which often results in a reduction of the severity and amount and sometimes results in dismissal. The number of citations, orders and proposed assessments vary depending on the size of the mine as well as other factors.

Disclosures related to specific mines pursuant to Section 1503 of the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act sourced from data documented as of October 7, 2010 in the MSHA Data Retrieval System for the three months ended September 30, 2010 (except pending legal actions, which are as of September 30, 2010) are as follows:

Mine (a)	Section 104 S and S Citations (b)		Proposed MSHA Assessments ($ thousands) (c)		Pending Legal Action (d)
Beckville		1		1		1
Big Brown		1		2		1
Kosse		—		1		—
Oak Hill		4		—		1
Sulphur Springs		2		1		2
Tatum		—		—		1
Three Oaks		1		3		—
Winfield South		1		3		1

(a) Excludes mines for which there were no applicable events.

(b) Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.

(c) Total dollar value for proposed assessments received from MSHA for all citations and orders issued in the three months ended September 30, 2010, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.

(d) Pending actions before the FMSHRC involving a coal or other mine.

During the three months ended September 30, 2010, EFCH’s mining operations received no citations, orders or written notices under Sections 104(b), 104(d), 104(e), 107(a) or 110(b)(2) of the Mine Act, and they experienced no fatalities.

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Summary

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Risk Oversight

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

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 EFCH’s businesses.

Commodity Price Risk

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

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

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

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

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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, 2010		Year Ended December 31, 2009
Month-end average Trading VaR:	$	3	$	4
Month-end high Trading VaR:	$	4	$	7
Month-end low Trading VaR:	$	1	$	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, 2010		Year Ended December 31, 2009
Month-end average MtM VaR:	$	450	$	1,050
Month-end high MtM VaR:	$	621	$	1,470
Month-end low MtM VaR:	$	321	$	638

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

	Nine Months  Ended September 30, 2010		Year Ended December 31, 2009
Month-end average EaR:	$	507	$	1,088
Month-end high EaR:	$	662	$	1,511
Month-end low EaR:	$	404	$	676

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

Interest Rate Risk

As of September 30, 2010, the potential reduction of annual pretax earnings due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $41 million, taking into account the interest rate swaps discussed in Note 4 to Financial Statements.

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Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. EFCH maintains credit risk policies with regard to its 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. EFCH 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, EFCH 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 — EFCH’s gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $3.251 billion as of September 30, 2010. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of September 30, 2010 include $885 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $71 million. 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 trade receivables, commodity contracts and hedging and trading activities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of September 30, 2010, the exposure to credit risk from these counterparties totaled $2.366 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $714 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.652 billion increased $423 million in the nine months ended September 30, 2010, reflecting the increase in derivative assets related to the long-term hedging program due to the decline in forward natural gas prices.

Of this $1.652 billion net exposure, essentially all is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and EFCH’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. The company 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, 2010 arising from wholesale trade receivables, commodity contracts and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. See Note 9 to Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

									Gross Exposure by Maturity
	Exposure Before  Credit Collateral			Credit Collateral		Net Exposure			2 years  or less		Between 2-5  years		Greater than 5 years		Total
Investment grade	$	2,333		$	712	$	1,621		$	1,576	$	757	$	—	$	2,333
Noninvestment grade		33			2		31			31		2		—		33
Totals	$	2,366		$	714	$	1,652		$	1,607	$	759	$	—	$	2,366
Investment grade		98.6	%				98.1	%
Noninvestment grade		1.4	%				1.9	%

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

Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented 49% and 29% of the net $1.652 billion exposure. EFCH views exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of EFCH’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, essentially all of the transaction volumes are with counterparties with an A credit rating or better. However, there is current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to EFCH. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by EFCH 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 EFCH 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 EFCH’s business and operations (often, but not always, through the use of words or phrases such as “intends,” “plans,” “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “should,” “projection,” “target,” “goal,” “objective” and “outlook”), are forward-looking statements. Although EFCH 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 Item 1A, “Risk Factors” and the following important factors, among others, that could cause EFCH’s actual results to differ materially from those projected in such forward-looking statements:

• prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, FERC, the NERC, the TRE, the PUCT, the RRC, the NRC, the EPA, the TCEQ and the Commodity Futures Trading Commission 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 fossil-fueled generating facilities;

• operations of mines;

• acquisitions and disposal of assets and facilities;

• development, construction and operation of facilities;

• decommissioning costs;

• present or prospective wholesale and retail competition;

• changes in tax laws and policies;

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

• clearing over the counter derivatives through exchanges and posting of cash collateral therewith;

• legal and administrative proceedings and settlements;

• general industry trends;

• economic conditions, including the impact of a recessionary environment;

• EFCH’s ability to attract and retain profitable customers;

• EFCH’s 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;

• EFCH’s 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, particularly in ERCOT;

• changes in business strategy, development plans or vendor relationships;

• access to adequate transmission facilities to meet changing demands;

• unanticipated changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;

• unanticipated changes in operating expenses, liquidity needs and capital expenditures;

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

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• 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 EFCH by the agreements governing its debt instruments;

• EFCH’s 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 EFCH’s financial instruments;

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

• changes in electricity transmission that allow additional electricity generation to compete with EFCH’s generation assets;

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

• changes in assumptions used to estimate costs of providing employee benefits, including pension and OPEB, and future funding requirements related thereto;

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

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

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• EFCH’s ability to effectively execute its operational strategy, and

• EFCH’s ability to implement cost reduction initiatives.

Any forward-looking statement speaks only as of the date on which it is made, and except as may be required by law, EFCH undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for EFCH to predict all of them; nor can EFCH 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. As such, forward-looking statements should not be unduly relied upon.

INDUSTRY AND MARKET INFORMATION

The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT, the PUCT and NYMEX. EFCH did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from EFCH’s 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 EFCH believes that each of these studies and publications is reliable, EFCH 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 EFCH does not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while EFCH believes that such internal and external research is reliable, it has not been verified by any independent sources, and EFCH 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 EFCH’s management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect as of the end of the current period included in this quarterly report. Based on the evaluation performed, EFCH’s management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this quarterly report, there has been no change in EFCH’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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.

Other than the risk factor presented below, there have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the 2009 Form 10-K and in Item 1A of EFCH’s quarterly report on Form 10-Q for the six months ended June 30, 2010 (June 2010 10-Q), except for information disclosed elsewhere in this Form 10-Q that provides factual updates to risk factors contained in the 2009 Form 10-K and June 2010 10-Q. The risk factor below updates, and should be read in conjunction with, the risk factors disclosed in the 2009 Form 10-K and June 2010 Form 10-Q.

EFCH’s cost of compliance with environmental laws and regulations and its commitments, and the cost of compliance with new environmental laws, regulations or commitments, could materially adversely affect EFCH’s financial condition, liquidity and results of operations.

EFCH is subject to extensive environmental regulation by governmental authorities, including the EPA and the TCEQ. In operating its facilities, EFCH is required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits. EFCH may incur significant additional costs beyond those currently contemplated to comply with these requirements. If EFCH fails to comply with these requirements, EFCH could be subject to civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to EFCH or its facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements.

The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include coal-fueled generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, in each case that may affect EFCH’s coal-fueled generation facilities. There is no assurance that the currently-installed emissions control equipment at EFCH’s coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Some of the potential EPA or TCEQ regulatory actions could require EFCH to install significant additional control equipment, resulting in material costs of compliance for its generation units, including capital expenditures and higher operating costs. These costs could result in material adverse effects on EFCH’s financial condition, liquidity and results of operations.

In conjunction with the building of three new generation units, EFCH has committed to reduce emissions of mercury, nitrogen oxide and sulfur dioxide through the installation of emissions control equipment at both the new and existing lignite-fueled generation units. EFCH may incur significantly greater costs than those contemplated in order to achieve this commitment.

EFH Corp. has formed a Sustainable Energy Advisory Board that advises it in its pursuit of technology development opportunities that, among other things, are designed to reduce its impact on the environment. Any adoption of Sustainable Energy Advisory Board recommendations may cause EFCH to incur significant costs in addition to the costs referenced above.

EFCH may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if EFCH fails to obtain, maintain or comply with any such approval, the operation and/or construction of its facilities could be stopped, curtailed or modified or become subject to additional costs.

In addition, EFCH may be responsible for any on-site liabilities associated with the environmental condition of facilities that it has acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and sales of assets, EFCH may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against EFCH or fail to meet its indemnification obligations to EFCH.

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Item 6. Exhibits

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

Exhibits	Previously Filed With File Number*	As Exhibit
(4)	Instruments Defining the Rights of Security Holders, Including Indentures
4(a)	1-12833 Form 8-K (filed October 8, 2010)	4.1	—	Indenture, dated as of October 6, 2010, among TCEH, TCEH Finance, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
4(b)	1-12833 Form 8-K     (filed October 26, 2010)	4.1	—	First Supplemental Indenture, dated as of October 20, 2010, to the Indenture, dated as of October 6, 2010, among TCEH, TCEH Finance, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
4(c)	1-12833 Form 8-K (filed October 8, 2010)	4.2	—	Registration Rights Agreement, dated as of October 6, 2010, by and among the Exchange Holder, TCEH, TCEH Finance and the Guarantors named therein
4(d)	1-12833 Form 8-K (filed October 26, 2010)	4.2	—	Registration Rights Agreement, dated as of October 20, 2010, by and among the Initial Purchasers, TCEH, TCEH Finance and the Guarantors named therein
4(e)	1-12833 Form 8-K (filed July 30, 2010)	99.1	—	Third Supplemental Indenture, dated as of July 29, 2010, to Indenture dated as of October 31, 2007, relating to EFH Corp.’s 10.875% Senior Notes due 2017 and 11.250%/12.000% Senior Toggle Notes due 2017
10	Material Contracts
10(a)	1-12833 Form 8-K (filed October 8, 2010)	4.3	—	Second Lien Pledge Agreement, dated as of October 6, 2010, among the Issuer, the Subsidiary Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as collateral agent
10(b)	1-12833 Form 8-K (filed October 8, 2010)	4.4	—	Second Lien Security Agreement, dated as of October 6, 2010, among TCEH, TCEH Finance, the Subsidiary Guarantors named therein and The Bank of New York Mellon Trust Company, N.A.
10(c)	1-12833 Form 8-K (filed October 8, 2010)	4.5	—	Intercreditor Agreement, dated as of October 6, 2010, among TCEH, TCEH Finance, the Guarantors, The Bank of New York Mellon Trust Company, N.A., in its capacity as collateral agent under the Indenture, and Citibank, N.A., in its capacity as administrative agent under the TCEH Senior Secured Credit Facilities

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Exhibits	Previously Filed With File Number*	As Exhibit
31	Rule 13a – 14(a)/15d – 14 (a) Certifications.
31(a)			—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications.
32(a)			—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Company, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Company, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99)	Additional Exhibits.
99(a)			—	Condensed Statement of Consolidated Income – Twelve Months Ended September 30, 2010.
99(b)			—	TCEH Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2010 and 2009.

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Exhibits	Previously Filed With File Number*	As Exhibit
99(c)			—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2010 and 2009.

* Incorporated herein by reference.

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SIGNATURE

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

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

Date: October 28, 2010

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