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. 5 TO

MARKET MAKING PROSPECTUS DATED APRIL 27, 2011

THE DATE OF THIS SUPPLEMENT IS NOVEMBER 9, 2011

On October 28, 2011, registrant parent guarantor, Energy Future Competitive Holdings Company, filed the attached

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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011

— OR —

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

Commission File Number 001-34543

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 Ö     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 Ö     No    

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   Ö   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 Ö

Common Stock Outstanding as of October 26, 2011: 2,062,768 Class A shares, without par value and 39,192,594 Class B shares, without par value.

Energy Future Competitive Holdings Company 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, 2011 and 2010		1
	Condensed Statements of Consolidated Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2011 and 2010		1
	Condensed Statements of Consolidated Cash Flows – Nine Months Ended September 30, 2011 and 2010		2
	Condensed Consolidated Balance Sheets – September 30, 2011 and December 31, 2010		3
	Notes to Condensed Consolidated Financial Statements		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		49
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		72
Item 4.	Controls and Procedures		78
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings		78
Item 1A.	Risk Factors		78
Item 6.	Exhibits		81
SIGNATURE			83

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 quarterly 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 “we,” “our,” “us” 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, or otherwise reflected in, their respective parent company’s financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the relevant 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.

2010 Form 10-K	EFCH’s Annual Report on Form 10-K for the year ended December 31, 2010
Adjusted EBITDA	Adjusted EBITDA means EBITDA adjusted to exclude noncash 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. We are 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 certain covenants contained in the debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with US GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
CFTC	US Commodity Futures Trading Commission
CPNPC	Refers to Comanche Peak Nuclear Power Company LLC, which was formed by subsidiaries of TCEH (holding an 88% equity interest) and Mitsubishi Heavy Industries Ltd. (MHI) (holding a 12% equity interest) for the purpose of developing two new nuclear generation units and obtaining a combined operating license from the NRC for the units.
CSAPR	Refers to the final Cross-State Air Pollution Rule issued by the EPA in July 2011.
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).

ii

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.
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.
EPA	US Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas
FERC	US Federal Energy Regulatory Commission
GAAP	generally accepted accounting principles
GWh	gigawatt-hours
IRS	US Internal Revenue Service
kWh	kilowatt-hours
Lehman	Refers to certain subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code in 2008.
LIBOR	London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
Luminant	Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.
Merger	The transaction referred to in the Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which was completed on October 10, 2007

iii

MMBtu	million British thermal units
Moody’s	Moody’s Investors Services, Inc. (a credit rating agency)
MW	megawatts
MWh	megawatt-hours
NERC	North American Electric Reliability Corporation
NOx	nitrogen oxide
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
Securities Act	Securities Act of 1933, as amended
SG&A	selling, general and administrative
SO2	sulfur dioxide
Sponsor Group	Refers collectively to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. that have an ownership interest in Texas Holdings. (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 and TCEH Delayed Draw Term Loan Facility (collectively, the TCEH Term Loan Facilities), TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 6 to Financial Statements for details of these facilities.
TCEH Senior Secured Notes	Refers to TCEH’s 11.5% Senior Secured Notes due October 1, 2020.
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.
Texas Holdings Group	Refers to Texas Holdings and its direct and indirect subsidiaries other than Oncor Holdings and its subsidiaries.
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)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Operating revenues	$	2,321		$	2,607		$	5,672		$	6,599
Fuel, purchased power costs and delivery fees		(1,058	)		(1,400	)		(2,726	)		(3,521	)
Net gain from commodity hedging and trading activities		270			992			365			2,272
Operating costs		(207	)		(197	)		(670	)		(623	)
Depreciation and amortization		(371	)		(345	)		(1,097	)		(1,027	)
Selling, general and administrative expenses		(192	)		(183	)		(529	)		(546	)
Franchise and revenue-based taxes		(21	)		(24	)		(64	)		(72	)
Impairment of goodwill (Note 4)		–			(4,100	)		–			(4,100	)
Other income (Note 14)		4			6			43			95
Other deductions (Note 14)		(478	)		(3	)		(568	)		(12	)
Interest income		20			23			65			64
Interest expense and related charges (Note 14)		(1,394	)		(905	)		(3,091	)		(2,718	)
Loss before income taxes		(1,106	)		(3,529	)		(2,600	)		(3,589	)
Income tax (expense) benefit		382			(191	)		894			(188	)
Net loss	$	(724	)	$	(3,720	)	$	(1,706	)	$	(3,777	)

See Notes to Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Net loss	$	(724	)	$	(3,720	)	$	(1,706	)	$	(3,777	)
Other comprehensive income, net of tax effects – derivative value net loss related to hedged transactions recognized during the period and reported in net loss (net of tax benefit of $2, $7, $9 and $25)		4			13			15			49
Comprehensive loss	$	(720	)	$	(3,707	)	$	(1,691	)	$	(3,728	)

See Notes to Financial Statements.

1

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(millions of dollars)
Cash flows — operating activities:
Net loss	$	(1,706	)	$	(3,777	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation and amortization		1,291			1,231
Deferred income tax expense (benefit) – net		(1,313	)		430
Impairment of emissions allowances (Note 3)		418			–
Severance charges (Note 3)		49			–
Impairment of assets related to mining operations (Note 3)		9			–
Impairment of goodwill (Note 4)		–			4,100
Unrealized net (gain) loss from mark-to-market valuations of commodity positions		247			(1,615	)
Unrealized net loss from mark-to-market valuations of interest rate swaps (Note 14)		879			542
Effect of Parent’s payment of interest on pushed-down debt		62			202
Interest expense on toggle notes payable in additional principal (Notes 6 and 14)		122			170
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 14)		171			178
Third-party fees related to debt amendment and extension transactions (Note 14) (reported as financing)		86			–
Bad debt expense (Note 5)		42			88
Accretion expense related to asset retirement and mining reclamation obligations		36			33
Stock-based incentive compensation expense		3			5
Net gain on sale of assets		(2	)		(81	)
Other, net		7			6
Changes in operating assets and liabilities:
Impact of accounts receivable securitization program (Note 5)		–			(383	)
Margin deposits – net		277			164
Other operating assets and liabilities		371			(299	)
Cash provided by operating activities		1,049			994
Cash flows — financing activities:
Notes due to affiliates		–			804
Issuances of long-term debt		1,750			–
Repayments/repurchases of long-term debt (Note 6)		(985	)		(243	)
Net short-term borrowings under accounts receivable securitization program (Note 5)		115			228
Decrease in other short-term borrowings (Note 6)		(1,126	)		(873	)
Decrease in income tax-related note payable to Oncor		(28	)		(27	)
Contributions from noncontrolling interests (Note 8)		13			24
Debt amendment, exchange and issuance costs, including third-party fees expensed		(843	)		–
Other, net		(1	)		28
Cash used in financing activities		(1,105	)		(59	)
Cash flows — investing activities:
Capital expenditures		(361	)		(676	)
Nuclear fuel purchases		(125	)		(84	)
Notes due from affiliates		527			(282	)
Proceeds from sales of assets		49			141
Reduction of restricted cash related to TCEH letter of credit facility		188			–
Other changes in restricted cash		(50	)		(31	)
Proceeds from sales of environmental allowances and credits		2			7
Purchases of environmental allowances and credits		(12	)		(13	)
Proceeds from sales of nuclear decommissioning trust fund securities		2,385			937
Investments in nuclear decommissioning trust fund securities		(2,398	)		(949	)
Other, net		6			(8	)
Cash provided by (used in) investing activities		211			(958	)
Net change in cash and cash equivalents		155			(23	)
Effect of consolidation of VIE		–			7
Cash and cash equivalents — beginning balance		47			94
Cash and cash equivalents — ending balance	$	202		$	78

See Notes to Financial Statements.

2

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	202		$	47
Restricted cash (Note 14)		84			33
Trade accounts receivable — net (includes $731 and $612 in pledged amounts related to a VIE (Notes 2 and 5))		1,014			991
Notes receivable from parent (Note 13)		1,404			1,921
Inventories (Note 14)		358			395
Commodity and other derivative contractual assets (Note 11)		2,465			2,640
Accumulated deferred income taxes		5			–
Margin deposits related to commodity positions		59			166
Other current assets		44			37
Total current assets		5,635			6,230
Restricted cash (Note 14)		947			1,135
Investments (Note 14)		588			602
Property, plant and equipment — net (Note 14)		19,351			20,155
Goodwill (Note 4)		6,152			6,152
Identifiable intangible assets — net (Note 4)		1,847			2,371
Commodity and other derivative contractual assets (Note 11)		1,496			2,071
Other noncurrent assets, principally unamortized debt amendment and issuance costs		1,039			428
Total assets	$	37,055		$	39,144
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (includes $211 and $96 related to a VIE (Notes 2 and 6))	$	211		$	1,221
Advances from parent		7			–
Long-term debt due currently (Note 6)		453			658
Trade accounts payable		555			669
Trade accounts and other payables to affiliates		244			210
Notes payable to parent (Note 13)		49			46
Commodity and other derivative contractual liabilities (Note 11)		1,673			2,164
Margin deposits related to commodity positions		801			631
Accumulated deferred income taxes		–			4
Accrued income taxes payable to parent (Note 13)		371			21
Accrued taxes other than income		103			130
Accrued interest		577			326
Other current liabilities		265			250
Total current liabilities		5,309			6,330
Accumulated deferred income taxes		4,689			6,000
Commodity and other derivative contractual liabilities (Note 11)		1,725			869
Notes or other liabilities due affiliates (Note 13)		336			384
Long-term debt held by affiliates (Note 13)		342			343
Long-term debt, less amounts due currently (Note 6)		29,997			29,131
Other noncurrent liabilities and deferred credits (Note 14)		2,259			2,236
Total liabilities		44,657			45,293
Commitments and Contingencies (Note 7)
Equity (Note 8):
EFCH shareholder’s equity		(7,702	)		(6,236	)
Noncontrolling interests in subsidiaries		100			87
Total equity		(7,602	)		(6,149	)
Total liabilities and equity	$	37,055		$	39,144

See Notes to Financial Statements.

3

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, Texas-based holding company. We conduct our operations almost entirely through our 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 and sourcing of electricity, are performed on an integrated basis; consequently, there are no reportable business segments.

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

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 our 2010 Form 10-K. 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. All acquisitions of outstanding debt for cash, including notes that had been issued in lieu of cash interest, are presented in the financing activities section of the statement of cash flows. 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 2010 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 were made to previous estimates or assumptions during the current year.

4

2. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. Accounting standards require consolidation of a VIE if we have (a) the power to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (primary beneficiary). Our VIEs consist of equity investments in certain of our subsidiaries and the accounts receivable securitization program discussed below. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.

Consolidated VIEs

See discussion in Note 5 regarding the VIE related to our accounts receivable securitization program that is consolidated under the accounting standards because EFCH (as the owner of TXU Energy) is the primary beneficiary of TXU Receivables Company, which is owned and controlled by our parent, EFH Corp.

We also consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our 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 8).

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

Assets:	September 30, 2011		December 31, 2010		Liabilities:	September 30, 2011		December 31, 2010
Cash and cash equivalents	$	9	$	9	Short-term borrowings (a)	$	211	$	96
Accounts receivable (a)		731		612	Trade accounts payable		2		3
Property, plant and equipment		130		112	Other current liabilities		8		1
Other assets, including $2 million of current assets in both periods		7		8
Total assets	$	877	$	741	Total liabilities	$	221	$	100

(a) As a result of accounting guidance related to transfers of financial assets, the balance sheet as of September 30, 2011 and December 31, 2010 reflects $731 million and $612 million, respectively, of pledged accounts receivable and $211 million and $96 million, respectively, of short-term borrowings (see Note 5).

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

5

3. EFFECTS OF NEW EPA RULE

In July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR). Compliance with the new rule would require significant additional reductions of sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions from our fossil-fueled generation units. In order to meet the emissions reduction requirements by the dates mandated, we determined it would be necessary to idle two of our lignite/coal-fueled generation units at our Monticello facility by the end of 2011, switch the fuel we use at three lignite/coal-fueled generation units from a blend of Texas lignite and Wyoming Powder River Basin coal to 100 percent Powder River Basin coal, cease lignite mining operations that serve our Big Brown and Monticello generation facilities in the first quarter 2012 and construct upgraded scrubbers at five of our lignite/coal-fueled generation units. The action plan to cease operations at the mines required an evaluation of the remaining useful lives and recoverability of recorded values of tangible and intangible assets related to the mines. This evaluation resulted in the recording of accelerated depreciation and amortization expense related to mine assets totaling $22 million in the third quarter 2011. Also, in the third quarter 2011, we recorded asset impairments totaling $9 million related to capital projects in progress at the mines.

Additionally, because of emissions allowance limitations under the CSAPR, we would have excess SO₂ emissions allowances under the Clean Air Act’s existing acid rain cap-and-trade program, and market values of such allowances are estimated to be de minimis. Accordingly, we recorded a noncash impairment charge of $418 million (before deferred income tax benefit) related to our existing SO₂ emissions allowance intangible assets in the third quarter 2011. SO₂ emissions allowances granted to us were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger in October 2007.

Finally, employee severance charges totaling $49 million were accrued in the third quarter 2011 based upon our existing severance policy. The charges are associated with the elimination of approximately 500 positions as a result of the actions we determined would be necessary with respect to our generation and mining operations discussed above.

The emissions allowances and other impairments and severance charges are reported in other deductions.

In August 2011, we petitioned the EPA to reconsider the CSAPR provisions and stay the effectiveness of those provisions, in each case as applied to Texas. In September 2011, we filed a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) challenging the CSAPR as it applies to Texas. In that legal proceeding, we also filed a motion to stay the effective date of the CSAPR as applied to Texas. As of October 27, 2011, no actions have been taken by the EPA or the D.C. Circuit Court to stay the CSAPR effective date.

In October 2011, the EPA published proposed revisions to the CSAPR. We are currently evaluating the revisions, which if adopted by the EPA as proposed, may reduce the adverse effects on our operations discussed above.

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4. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides the goodwill balances as of September 30, 2011 and December 31, 2010. There were no changes to the goodwill balances in the three or nine months ended September 30, 2011. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges	$	18,322
Accumulated impairment charges		(12,170	)
Balance as of September 30, 2011 and December 31, 2010	$	6,152

As discussed in Note 3, the issuance of the CSAPR by the EPA resulted in an evaluation of its effects and the development of a plan of action to meet the rule’s requirements. These actions are expected to have material financial effects, including significant environmental capital expenditures, lower wholesale revenues and higher operating costs. In the third quarter 2011, we evaluated the consequences of the CSAPR on the carrying value of goodwill. In accordance with accounting rules, we estimated the enterprise value of the business and the fair market values of its operating assets and liabilities and determined that the implied goodwill amount exceeded recorded goodwill. Accordingly, no goodwill impairment was recorded.

This determination involved significant assumptions and judgments. The calculations supporting the estimates of the enterprise value of our business 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 annual impairment testing required by accounting rules remains scheduled for December 1, 2011. We cannot predict the likelihood or amount of any future impairment. See discussion of CSAPR-related charges related to other assets and severance costs in Note 3.

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

Identifiable Intangible Assets

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

	September 30, 2011						December 31, 2010
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	332	$	131	$	463	$	293	$	170
Favorable purchase and sales contracts		548		280		268		548		257		291
Capitalized in-service software		227		72		155		202		50		152
Environmental allowances and credits (a)		571		372		199		986		304		682
Mining development costs (a)		132		36		96		47		17		30
Total intangible assets subject to amortization	$	1,941	$	1,092		849	$	2,246	$	921		1,325
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization) (b)						43						91
Total intangible assets					$	1,847					$	2,371

(a) Amounts impaired have been removed from the table as of the impairment date (see Note 3).

(b) In June 2011, we sold certain mineral interests for $43 million in cash net of closing-related costs. No gain or loss was recorded on the transaction.

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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	2011		2010		2011		2010
Retail customer relationship	Depreciation and amortization	$	13	$	20	$	39	$	59
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees		6		1		23		25
Capitalized in-service software	Depreciation and amortization		8		6		22		17
Environmental allowances and credits	Fuel, purchased power costs and delivery fees		25		25		68		69
Mining development costs	Depreciation and amortization		13		3		19		8
Total amortization expense		$	65	$	55	$	171	$	178

See discussion in Note 3 regarding impairment of emissions allowances and accelerated depreciation and amortization expenses related to mine assets, including mining development costs intangible assets, recorded in the third quarter 2011.

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	Amortization Expense
2011	$237
2012	125
2013	107
2014	92
2015	84

5. 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, we consolidate TXU Receivables Company in accordance with amended consolidated accounting standards. 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 accounting standards effective January 1, 2010, 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 previous accounting rules, we did not consolidate TXU Receivables Company, and the activity was accounted for as a sale of accounts receivable, which resulted in the funding being recorded as a reduction of accounts receivable.

The maximum funding amount currently available under the accounts receivable securitization program is $350 million. Program funding increased from $96 million as of December 31, 2010 to $211 million as of September 30, 2011. Under the terms of the program, available funding as of September 30, 2011 was reduced by $37 million of customer deposits held by the originator because TCEH’s credit ratings were lower than Ba3/BB-.

8

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, totaled $520 million and $516 million as of September 30, 2011 and December 31, 2010, 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 and are reported as interest expense and related charges. 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,
	2011	2010	2011	2010
Program fees	$    2	$    2	$    6	$    7
Program fees as a percentage of average funding (annualized)	4.4%	4.8%	6.1%	3.3%

Activities of TXU Receivables Company were as follows:

	Nine Months Ended September 30,
	2011			2010
Cash collections on accounts receivable	$	3,836		$	4,828
Face amount of new receivables purchased		(3,955	)		(4,867	)
Discount from face amount of purchased receivables		8			9
Program fees paid to funding entities		(6	)		(7	)
Servicing fees paid to Service Co. for recordkeeping and collection services		(2	)		(2	)
Increase in subordinated notes payable		4			194
Financing cash flows used by (provided to) originator under the program	$	(115	)	$	155

Under the previous accounting rules, changes in funding under the program were reported as operating cash flows. The accounting rules effective January 1, 2010 required that the amount of funding under the program as of the adoption date ($383 million) be reported as a use of operating cash flows and a source of financing cash flows, with all subsequent changes in funding 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, 2011, 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. We expect that the level of cash flows would normalize in approximately 16 to 30 days.

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Trade Accounts Receivable

	September 30, 2011			December 31, 2010
Wholesale and retail trade accounts receivable, including $731 and $612 in pledged retail receivables	$	1,047		$	1,055
Allowance for uncollectible accounts		(33	)		(64	)
Trade accounts receivable — reported in balance sheet	$	1,014		$	991

Gross trade accounts receivable as of September 30, 2011 and December 31, 2010 included unbilled revenues of $305 million and $297 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Nine Months Ended September 30,
	2011			2010
Allowance for uncollectible accounts receivable as of beginning of period	$	64		$	81
Increase for bad debt expense		42			88
Decrease for account write-offs		(47	)		(97	)
Reversal of reserve related to counterparty bankruptcy (Note 14)		(26	)		—
Allowance for uncollectible accounts receivable as of end of period	$	33		$	72

Affiliated Receivables

Receivables from affiliates are measured at historical cost and primarily consist of notes receivable for cash loaned to EFH Corp. for debt principal and interest payments and other general corporate purposes of EFH Corp. TCEH reviews economic conditions, counterparty credit scores and historical payment activity to assess the overall collectability of its affiliated receivables. Notes receivable from EFH Corp. totaled $1.404 billion and $1.921 billion as of September 30, 2011 and December 31, 2010, respectively. There were no credit loss allowances as of September 30, 2011 or December 31, 2010. See Note 13 for additional information about related party transactions.

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6. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

As of September 30, 2011, outstanding short-term borrowings totaled $211 million under the accounts receivable securitization program discussed in Note 5.

As of December 31, 2010, outstanding short-term borrowings totaled $1.221 billion, which included $1.125 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 3.80%, excluding certain customary fees, and $96 million under the accounts receivable securitization program.

Credit Facilities

Credit facilities with cash borrowing and/or letter of credit availability as of September 30, 2011 are presented below. The facilities are all senior secured facilities of TCEH. See “Amendment and Extension of TCEH Senior Secured Facilities” and the following sections below for discussion of amendments, extensions and repayments of the facilities in April 2011.

		As of September 30, 2011
Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)	October 2013	$	645	$	–	$	–	$	645
TCEH Revolving Credit Facility (a)	October 2016		1,409		–		–		1,409
TCEH Letter of Credit Facility (b)	October 2014		42		–		42		–
TCEH Letter of Credit Facility (b)	October 2017		1,020		–		1,020		–
Subtotal TCEH		$	3,116	$	–	$	1,062	$	2,054
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. As of September 30, 2011, borrowings under the facility maturing October 2013 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. As of September 30, 2011, borrowings under the facility maturing October 2016 bear interest at LIBOR plus 4.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 1.00% 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 that supports issuances of letters of credit. In April 2011, $188 million of the cash borrowings were repaid as discussed under “Issuance of TCEH 11.5% Senior Secured Notes” below, and in August 2011, an equivalent amount was removed from restricted cash and used to repay borrowings under the TCEH Revolving Credit Facility, lowering letter of credit availability by the same amount unless additional funds are added to restricted cash. The use of the $188 million to repay revolver borrowings reduced our borrowing costs and did not affect available liquidity. Letters of credit totaling $742 million issued as of September 30, 2011 are supported by the restricted cash, and the remaining letter of credit availability totals $205 million.

(c) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 140 million MMBtu as of September 30, 2011. As of September 30, 2011, there were no borrowings under this facility.

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Long-Term Debt

As of September 30, 2011 and December 31, 2010, long-term debt consisted of the following:

	September 30, 2011			December 31, 2010
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
0.142% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.350% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.142% 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)		(122	)		(132	)
Senior Secured Facilities:
3.726% TCEH Term Loan Facilities maturing October 10, 2014 (e)(f)(g)		3,809			19,949
3.739% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		42			1,250
0.193% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (h)		—			—
4.750% TCEH Term Loan Facilities maturing October 10, 2017 (e)(f)(g)		15,370			—
4.739% TCEH Letter of Credit Facility maturing October 10, 2017 (f)		1,020			—
Other:
10.25% Fixed Senior Notes due November 1, 2015 (g)		2,046			2,046
10.25% Fixed Senior Notes due November 1, 2015, Series B (g)		1,442			1,442
10.50 / 11.25% Senior Toggle Notes due November 1, 2016		1,485			1,406
11.50% Senior Secured Notes due October 1, 2020		1,750			—
15.00% Senior Secured Second Lien Notes due April 1, 2021		336			336
15.00% Senior Secured Second Lien Notes due April 1, 2021, Series B		1,235			1,235
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		28			42
Capital lease obligations		66			76
Other		3			3
Unamortized discount		(11	)		—
Unamortized fair value discount (d)		(2	)		(2	)
Total TCEH	$	30,037		$	29,191

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	September 30, 2011			December 31, 2010
EFCH (parent entity)
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	46		$	46
8.254% Fixed Notes due in quarterly installments through December 31, 2021		43			46
1.054% 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)		(9	)		(10	)
Subtotal		89			91
EFH Corp. debt pushed down (i)
10.875% EFH Corp. Fixed Senior Notes due November 1, 2017		98			179
11.25/12.00% EFH Corp. Senior Toggle Notes due November 1, 2017		182			285
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			328
Subtotal – EFH Corp. debt pushed down		666			850
Total EFCH		755			941
Total EFCH consolidated		30,792			30,132
Less amount due currently		(453	)		(658	)
Less amount held by affiliates		(342	)		(343	)
Total long-term debt	$	29,997		$	29,131

(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. We expect to repurchase the $415 million principal amount subject to mandatory tender and remarketing in November 2011.

(b) Interest rates in effect as of September 30, 2011. 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, 2011. 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 an aggregate $18.65 billion principal amount to October 2014 and up to an aggregate $12.6 billion principal amount from October 2014 through October 2017.

(f) Interest rates in effect as of September 30, 2011.

(g) As discussed below and in Note 13, principal amounts of notes/term loans totaling $342 million and $343 million as of September 30, 2011 and December 31, 2010, respectively, were held by EFH Corp. and EFIH.

(h) Interest rate in effect as of September 30, 2011, excluding a quarterly maintenance fee of $11 million. See “Credit Facilities” above for more information.

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

Debt Amounts Due Currently

Amounts due currently (within twelve months) as of September 30, 2011 total $453 million and consist of $415 million principal amount of TCEH pollution control revenue bonds (PCRBs) subject to mandatory tender and remarketing in November 2011, which we expect to repurchase in November 2011, and $38 million of scheduled installment payments on capital leases and debt securities.

Debt Repayments

Repayments of long-term debt in the nine months ended September 30, 2011 totaled $985 million and included $958 million of long-term debt borrowings under the TCEH Senior Secured Facilities as discussed immediately below, $17 million of principal payments at scheduled maturity dates and $10 million of contractual payments under capitalized lease obligations.

13

Amendment and Extension of TCEH Senior Secured Facilities

Borrowings under the TCEH Senior Secured Facilities totaled $20.241 billion as of September 30, 2011 (including $19 million held by EFH Corp.). In April 2011, (i) the Credit Agreement governing the TCEH Senior Secured Facilities was amended, (ii) the maturity dates of approximately 80% of the borrowings under the term loans (initial term loans and delayed draw term loans) and deposit letter of credit loans under the TCEH Senior Secured Facilities and approximately 70% of the commitments under the TCEH Revolving Credit Facility were extended, (iii) borrowings totaling $1.604 billion under the TCEH Senior Secured Facilities were repaid from proceeds of issuance of $1.750 billion principal amount of TCEH 11.5% Senior Secured Notes as discussed below and (iv) the amount of commitments under the TCEH Revolving Credit Facility was reduced by $646 million.

The amendment to the Credit Agreement included, among other things, amendments to certain covenants contained in the TCEH Senior Secured Facilities (including the financial maintenance covenant), as well as acknowledgement by the lenders that (i) the terms of the intercompany notes receivable (as described below) from EFH Corp. payable to TCEH complied with the TCEH Senior Secured Facilities, including the requirement that these loans be made on an “arm’s-length” basis, and (ii) no mandatory repayments were required to be made by TCEH relating to “excess cash flows,” as defined under covenants of the TCEH Senior Secured Facilities, for fiscal years 2008, 2009 and 2010.

As amended, the maximum ratios for the secured debt to Adjusted EBITDA financial maintenance covenant are 8.00 to 1.00 for test periods through December 31, 2014, and decline over time to 5.50 to 1.00 for the test periods ending March 31, 2017 and thereafter. In addition, (i) up to $1.5 billion principal amount of TCEH senior secured first lien notes (including $906 million of the TCEH Senior Secured Notes discussed below), to the extent the proceeds are used to repay term loans and deposit letter of credit loans under the TCEH Senior Secured Facilities and (ii) all senior secured second lien debt will be excluded for the purposes of the secured debt to Adjusted EBITDA financial maintenance covenant.

The amendment contained certain provisions related to intercompany loans to EFH Corp. payable to TCEH on demand that arise from cash loaned for (i) debt principal and interest payments (P&I Note) and (ii) other general corporate purposes of EFH Corp. (SG&A Note). TCEH also agreed in the Amendment:

• not to make any further loans to EFH Corp. under the SG&A Note (as of September 30, 2011, the outstanding balance of the SG&A Note was $233 million, reflecting the repayment discussed below);

• that borrowings outstanding under the P&I Note will not exceed $2.0 billion in the aggregate at any time (as of September 30, 2011, the outstanding balance of the P&I Note was $1.171 billion), and

• that the sum of (i) the outstanding indebtedness (including guarantees) issued by EFH Corp. or any subsidiary of EFH Corp. (including EFIH) secured by a second-priority lien on the equity interests that EFIH owns in Oncor Holdings (EFIH Second-Priority Debt) and (ii) the aggregate outstanding amount of the SG&A Note and P&I Note will not exceed, at any time, the maximum amount of EFIH Second-Priority Debt permitted by the indenture governing the EFH Corp. 10% Notes as in effect on April 7, 2011.

Further, in connection with the amendment, in April 2011 the following actions were completed related to the intercompany loans:

• EFH Corp. repaid $770 million of borrowings under the SG&A Note (using proceeds from TCEH’s repayment of the $770 million TCEH borrowed from EFH Corp. in January 2011 under a demand note), and

• EFIH and EFCH guaranteed, on an unsecured basis, the remaining balance of the SG&A Note (consistent with the existing EFIH and EFCH unsecured guarantees of the P&I Note and the EFH Corp. Senior Notes discussed below).

14

Pursuant to the extension of the TCEH Senior Secured Facilities in April 2011:

• the maturity of $15.370 billion principal amount of first lien term loans held by accepting lenders (including $19 million of term loans held by EFH Corp.) was extended from October 10, 2014 to October 10, 2017 and the interest rate with respect to the extended term loans was increased from LIBOR plus 3.50% to LIBOR plus 4.50%;

• the maturity of $1.020 billion principal amount of first lien deposit letter of credit loans held by accepting lenders was extended from October 10, 2014 to October 10, 2017 and the interest rate with respect to the extended deposit letter of credit loans was increased from LIBOR plus 3.50% to LIBOR plus 4.50%, and

• the maturity of $1.409 billion of the commitments under the TCEH Revolving Credit Facility held by accepting lenders was extended from October 10, 2013 to October 10, 2016, the interest rate with respect to the extended revolving commitments was increased from LIBOR plus 3.50% to LIBOR plus 4.50% and the undrawn fee with respect to such commitments was increased from 0.50% to 1.00%.

Upon the effectiveness of the extension, TCEH paid an up-front extension fee of 350 basis points on extended term loans and extended deposit letter of credit loans.

Each of the extended loans described above includes a “springing maturity” provision pursuant to which (i) in the event that more than $500 million aggregate principal amount of the TCEH 10.25% Notes due in 2015 (other than notes held by EFH Corp. or its controlled affiliates as of March 31, 2011 to the extent held as of the determination date) or more than $150 million aggregate principal amount of the TCEH Toggle Notes due in 2016 (other than notes held by EFH Corp. or its controlled affiliates as of March 31, 2011 to the extent held as of the determination date), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (ii) TCEH’s total debt to Adjusted EBITDA ratio (as defined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at the applicable determination date, then the maturity date of the extended loans will automatically change to 90 days prior to the maturity date of the applicable notes.

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 subsidiary of TCEH. The TCEH Senior Secured Facilities, along with the TCEH Senior Secured Notes and certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Swap Transactions” below, are secured on a first priority basis by (i) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (ii) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013 with respect to $645 million of commitments and until October 2016 with respect to $1.409 billion of commitments; there were no borrowings outstanding as of September 30, 2011. The TCEH Commodity Collateral Posting Facility will mature in December 2012.

Accounting and Income Tax Effects of the Amendment and Extension

Based on application of the accounting rules, including analyses of discounted cash flows, the amendment and extension transactions were determined not to be an extinguishment of debt. Accordingly, no gain was recognized, and transaction costs totaling $699 million, consisting of consent payments to loan holders, were capitalized. Amounts capitalized will be amortized to interest expense through the maturity dates of the respective loans. Net third party fees related to the amendment and extension totaling $86 million were expensed (see Note 14 under “Other Income and Deductions”).

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The transactions were determined to be a significant modification of debt for federal income tax purposes, resulting in taxable cancellation of debt income of approximately $2.5 billion. The income will be reversed as deductions in future years (through 2017), and consequently a deferred tax asset has been recorded. The effect of the income on federal income taxes payable related to 2011 is expected to be largely offset by current year operating losses, including the impact of bonus depreciation, and utilization of approximately $650 million in operating loss carryforwards. The transactions resulted in a cash charge under the Texas margin tax of $13 million (reported as income tax expense).

Issuance of TCEH 11.5% Senior Secured Notes

In April 2011, TCEH and TCEH Finance issued $1.750 billion principal amount of 11.5% Senior Secured Notes due 2020, and used the proceeds, net of issuance fees and a $12 million discount, to:

• repay $770 million principal amount of term loans under the TCEH Senior Secured Facilities (representing amortization payments that otherwise would have been paid from March 2011 through September 2014, including $1 million of term loans held by EFH Corp.);

• repay $188 million principal amount of deposit letter of credit loans under the TCEH Senior Secured Facilities;

• repay $646 million of borrowings under the TCEH Revolving Credit Facility (with commitments under the facility being reduced by the same amount), and

• fund $99 million of the $785 million of total transaction costs associated with the amendment and extension of the TCEH Senior Secured Facilities discussed above, with the remainder of the transaction costs paid with cash on hand, including the proceeds from EFH Corp.’s payment on the SG&A Note discussed above.

The TCEH Senior Secured Notes mature in October 2020, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1, at a fixed rate of 11.5% per annum. The notes are unconditionally guaranteed on a joint and several basis by EFCH and each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and the guarantees are secured on a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent such assets and equity interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), subject to certain exceptions and permitted liens.

The TCEH Senior Secured Notes were issued in a private placement and are not registered under the Securities Act. The 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 and second-priority debt of TCEH to the extent of the value of the TCEH Collateral and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated 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 Notes by the Guarantors are effectively senior to any unsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. The guarantees are effectively subordinated to all debt of the Guarantors secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt.

The indenture for the TCEH Senior Secured Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, TCEH’s and its restricted subsidiaries’ ability to:

• make restricted payments, including certain investments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets, and

• engage in certain transactions with affiliates.

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The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur under the indenture, the trustee or the holders of at least 30% of aggregate principal amount of all outstanding TCEH Senior Secured Notes may declare the principal amount on all such notes to be due and payable immediately.

Until April 1, 2014, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the TCEH Senior Secured Notes from time to time at a redemption price of 111.5% of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEH may redeem the notes at any time prior to April 1, 2016 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 the notes, in whole or in part, at any time on or after April 1, 2016, 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 the notes at 101% of their principal amount, plus accrued interest.

Issuance of EFIH 11% Senior Secured Second Lien Notes in Exchange for EFH Corp. Debt

In April 2011, EFIH and EFIH Finance issued $406 million principal amount of 11% Senior Secured Second Lien Notes due 2021 in exchange for $428 million of EFH Corp. debt consisting of $163 million principal amount of EFH Corp. 10.875% Notes due 2017, $229 million principal amount of EFH Corp. Toggle Notes due 2017 and $36 million principal amount of EFH Corp. 5.55% Series P Senior Notes due 2014. EFIH intends to hold the acquired securities as an investment. Prior to the exchange, 50% of the outstanding EFH Corp. 10.875% Notes and Toggle Notes had been pushed down to EFCH for reporting purposes.

Push Down of EFH Corp. Debt

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 of EFH Corp. (parent) that is fully and unconditionally guaranteed on a joint and several basis by EFIH and us is subject to push down in accordance with SEC Staff Accounting Bulletin Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected in our financial statements. Merger-related debt of EFH Corp. held as an investment by its subsidiaries is not subject to push down.

The amount reflected on our balance sheet as pushed down debt ($666 million and $850 million as of September 30, 2011 and December 31, 2010, respectively, as shown in the long-term debt table above) represents 50% of the EFH Corp. Merger-related debt we have 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 debt is the responsibility of EFH Corp., we record the settlement of such amounts as noncash capital contributions from EFH Corp.

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The tables below present, as of September 30, 2011 and December 31, 2010, an analysis of the total outstanding principal amount of EFH Corp. debt that we and EFIH have guaranteed (fully and unconditionally on a joint and several basis), as (i) amounts that EFIH held as an investment, (ii) amounts subject to push down to our balance sheet and (iii) amounts held by third parties that are not Merger-related, which consist of the $405 million principal amount of EFH Corp. 10% Senior Secured Notes. Our guarantee of the EFH Corp. debt is not secured, and the EFIH guarantee of the EFH Corp. Senior Notes is not secured. The EFIH guarantee of the EFH Corp. 10% and 9.75% Notes is secured by EFIH’s pledge of 100% of the membership interests and other investments it owns in Oncor Holdings (the EFIH Collateral).

September 30, 2011
Security	Held by EFIH		Subject to Push Down		Not Merger- Related		Total Guaranteed
EFH Corp. 10% Senior Secured Notes	$	–	$	656	$	405	$	1,061
EFH Corp. 9.75% Senior Secured Notes		–		115		–		115
EFH Corp. 10.875% Senior Notes		1,591		196		–		1,787
EFH Corp. 11.25/12.00% Senior Toggle Notes		2,676		363		–		3,039
Subtotal	$	4,267	$	1,330	$	405		6,002
EFH Corp. P&I and SG&A demand note payable to TCEH (Note 13)								1,404
Total							$	7,406

December 31, 2010
Security	Held by EFIH		Subject to Push Down		Not Merger- Related		Total Guaranteed
EFH Corp. 10% Senior Secured Notes	$	–	$	656	$	405	$	1,061
EFH Corp. 9.75% Senior Secured Notes		–		115		–		115
EFH Corp. 10.875% Senior Notes		1,428		359		–		1,787
EFH Corp. 11.25/12.00% Senior Toggle Notes		2,296		571		–		2,867
Subtotal	$	3,724	$	1,701	$	405		5,830
EFH Corp. P&I demand note payable to TCEH (Note 13)								916
Total							$	6,746

October 2011 EFH Corp. Debt Exchange – In a private exchange in October 2011, EFH Corp. issued $53 million principal amount of new EFH Corp. 11.25%/12.00% Toggle Notes due 2017 in exchange for $65 million principal amount of EFH Corp. 5.55% Series P Senior Notes due 2014. The new EFH Corp. Toggle Notes, which are subject to push down to our balance sheet, have substantially the same terms and conditions and are subject to the same indenture as the existing EFH Corp. Toggle Notes. Concurrent with the exchange, EFIH issued a dividend to EFH Corp. of $53 million principal amount of EFH Corp. Toggle Notes, that had been held by EFIH as an investment following prior debt exchange transactions and EFH Corp. retired the notes.

Information Regarding Other Significant Outstanding Debt

TCEH 10.25% Senior Notes (including Series B) and 10.50/11.25% Senior Toggle Notes (collectively, the TCEH Senior Notes) — The TCEH 10.25% Notes mature in November 2015, with interest payable in cash semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.25% per annum. The Toggle Notes mature in November 2016, with interest payable semi-annually in arrears on May 1 and November 1 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, TCEH may elect to pay interest on the Toggle 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 Senior Notes had a total principal amount as of September 30, 2011 of $4.973 billion (including $323 million principal amount held by EFH Corp. and EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by 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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TCEH 15% Senior Secured Second Lien Notes (including Series B) — These notes mature in April 2021, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1 at a fixed rate of 15% per annum, and had a total principal amount of $1.571 billion as of September 30, 2011. The notes are unconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities. 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 Facilities, subject to certain exceptions (including the elimination of the pledge of equity interests of any Subsidiary Guarantor to the extent that separate financial statements would be required to be filed with the SEC for such Subsidiary Guarantor under Rule 3-16 of Regulation S-X) and permitted liens. The guarantee from EFCH is not secured.

The TCEH Senior Secured Second Lien Notes were initially issued in private placements and have not been registered under the Securities Act. In September 2011, TCEH satisfied certain transferability conditions with respect to $336 million principal amount of the TCEH Senior Secured Second Lien Notes. As a result of the satisfaction of these conditions, such notes are now freely transferable without restriction by persons that are not affiliates of TCEH under the Securities Act. TCEH agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the remaining 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 remaining TCEH Senior Secured Second Lien Notes unless such notes meet certain transferability conditions (as described in the related registration rights agreement). Because the registration statement was not filed and declared effective and the transferability condition was not satisfied with respect to such remaining notes within 365 days after the original issue date (a Registration Default), the annual interest rate on the remaining notes has increased by 25 basis points for the period during which the Registration Default continues. Once the Registration Default is cured, the interest rate on the remaining notes will revert to the original level. We expect to satisfy the transferability conditions, and cure the Registration Default, with respect to the remaining TCEH Senior Secured Second Lien Notes in the fourth quarter 2011.

Interest Rate Swap Transactions

As of September 30, 2011, TCEH has entered into a series of interest rate swaps that effectively fix the interest rates at between 5.5% and 9.3% on $18.65 billion principal amount of its senior secured debt to October 2014 and on up to $12.6 billion principal amount of its senior secured debt from October 2014 to October 2017. Swaps related to an aggregate $2.60 billion principal amount of debt expired or were terminated in the nine months ended September 30, 2011, and swaps related to an aggregate $5.45 billion principal amount of debt maturing from 2012 to 2014 (growing to $10.58 billion over time, primarily as existing swaps expire) and $12.6 billion principal amount of debt maturing from 2014 to 2017 were entered into in the nine months ended September 30, 2011.

As of September 30, 2011, 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 $10.25 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 0.1260%. In the nine months ended September 30, 2011, interest rate basis swaps related to an aggregate $4.95 billion principal amount of TCEH senior secured term loans expired, and no additional basis swaps were entered into by TCEH.

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 the swaps are reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $619 million and $879 million of net loss in the three and nine months ended September 30, 2011, respectively, and $181 million and $542 million of net loss in the three and nine months ended September 30, 2010, respectively. The cumulative unrealized mark-to-market net liability related to the swaps totaled $2.299 billion as of September 30, 2011, of which $81 million (pre-tax) was reported in accumulated other comprehensive income.

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7. COMMITMENTS AND CONTINGENCIES

Guarantees

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

Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. As of September 30, 2011, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled $13 million. These leased assets consist primarily of rail cars. The average life of the residual value guarantees under the lease portfolio is approximately five years.

See Note 6 above for discussion of guarantees and security for certain of our debt securities, as well as EFCH guarantees of certain EFH Corp. debt.

Letters of Credit

As of September 30, 2011, TCEH had outstanding letters of credit under its credit facilities totaling $742 million as follows:

• $355 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions and collateral postings with ERCOT;

• $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);

• $76 million to support TCEH’s REP’s financial requirements with the PUCT, and

• $103 million for miscellaneous credit support requirements.

Long-Term Contractual Obligations and Commitments

In the nine months ended September 30, 2011, we entered into contractual obligations in the normal course of business totaling approximately $280 million for transportation of coal in 2015 and 2016 and $100 million to purchase nuclear fuel in periods after 2015.

Litigation Related to Generation Facilities

In October 2009, the US Court of Appeals for the Fifth Circuit issued a decision in the case of Comer v. Murphy Oil USA reversing the district court’s dismissal of the case and holding that certain Mississippi residents had standing to pursue state law nuisance, negligence and trespass claims for injuries purportedly suffered because the defendants’ emissions of greenhouse gases (GHGs) allegedly increased the destructive force of Hurricane Katrina. The Fifth Circuit subsequently agreed to rehear the case, but then dismissed the appeal in its entirety when several judges recused themselves in the case. The Fifth Circuit’s order dismissing the appeal and vacating the earlier panel’s decision had the effect of reinstating the district court’s original dismissal of the case. In January 2011, the US Supreme Court rejected the plaintiffs’ request that their appeal be reinstated in the Fifth Circuit. In May 2011, the plaintiffs in the Comer case filed a new lawsuit in the United States District Court for the Southern District of Mississippi against EFH Corp. and numerous other defendants (Comer II). The Comer II complaint reasserts that the defendants’ emissions of GHGs have contributed to global warming and led to severe weather consequences. The plaintiffs assert claims for public and private nuisance, trespass and negligence, and they seek to have their case certified as a class action. In July 2011, EFH Corp. was dismissed from the case.

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In November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak Grove Management Company LLC’s (Oak Grove) (a wholly-owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System (TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in the Travis County, Texas District Court. Plaintiffs seek a reversal of the TCEQ’s order and a remand back to the TCEQ for further proceedings. In addition to this administrative appeal, in November 2010, two other petitions were filed in Travis County, Texas District Court by Sustainable Energy and Economic Development Coalition and Paul and Lisa Rolke, respectively, who were non-parties to the administrative hearing before the State Office of Administrative Hearings, challenging the TCEQ’s decision to renew and amend Oak Grove’s TPDES permit and asking the District Court to remand the matter to the TCEQ for further proceedings. Although we cannot predict the outcome of these proceedings, we believe that the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and that the application for and the processing of Oak Grove’s TPDES permit renewal and amendment by the TCEQ were in accordance with applicable law. There can be no assurance that the outcome of these matters would not result in an adverse impact on our financial condition, results of operations or liquidity.

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. While we are unable to estimate any possible loss or predict the outcome of the litigation, we believe that the Sierra Club’s claims are without merit, and we intend to vigorously defend this litigation. The litigation is currently stayed by the court. 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. Subsequently, in December 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 Monticello generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

Regulatory Reviews

In June 2008, the EPA issued an initial 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. We are cooperating with the EPA and responding in good faith to the EPA’s request, but we are unable to predict the outcome of this matter.

Other Proceedings

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

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8. EQUITY

Dividend Restrictions

There are no restrictions on our ability to use our retained earnings or net income to make distributions on our equity. However, EFCH relies on distributions or loans from TCEH to meet its cash requirements, including funding of dividends. 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 dividend on their common stock unless at the time, and after giving effect to such distribution, TCEH’s 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, 2011, the ratio was 8.3 to 1.0.

In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and TCEH Senior Secured Second Lien Notes generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and the indentures governing such notes. See discussion in Note 6 regarding amendments to the TCEH Senior Secured Facilities affecting intercompany loans from TCEH to EFH Corp.

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

Noncontrolling Interests

As discussed in Note 2, we consolidate a joint venture formed for the purpose of developing two new nuclear generation units, which results in a noncontrolling interests component of equity. Net loss attributable to the noncontrolling interests was immaterial for the nine months ended September 30, 2011 and 2010.

Equity

The following table presents the changes to equity for the nine months ended September 30, 2011:

	EFCH Shareholder’s Equity
	Common Stock		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total Equity
Balance as of December 31, 2010	$	7,151	$	(13,319	)	$	(68	)	$	87	$	(6,149	)
Net loss		–		(1,706	)		–			–		(1,706	)
Effect of stock-based incentive compensation plans		4		–			–			–		4
Net effect of cash flow hedges		–		–			15			–		15
Investment by noncontrolling interests		–		–			–			13		13
Effect of debt push-down from EFH Corp. (a)		221		–			–			–		221
Balance as of September 30, 2011	$	7,376	$	(15,025	)	$	(53	)	$	100	$	(7,602	)

(a) Represents the effect of net reduction of debt pushed down from EFH Corp. of $184 million (Note 6) and related interest and income tax effects.

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The following table presents the changes to equity for 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 loss		–			(3,777	)		–			–		(3,777	)
Effect of stock-based incentive compensation plans		7			–			–			–		7
Net effect of cash flow hedges		–			–			49			–		49
Effect of consolidation of TXU Receivables
Company (Note 2)		–			–			–			7		7
Investment by noncontrolling interests		–			–			–			24		24
Effect 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 (Note 6) from EFH Corp. of $1.536 billion and related interest and income tax effects.

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9. FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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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, 2011, 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	$	475	$	3,419	$	47	$	20	$	3,961
Interest rate swaps		–		–		–		–		–
Nuclear decommissioning trust – equity securities (c)		183		111		–		–		294
Nuclear decommissioning trust – debt securities (c)		–		238		–		–		238
Total assets	$	658	$	3,768	$	47	$	20	$	4,493
Liabilities:
Commodity contracts	$	522	$	500	$	57	$	20	$	1,099
Interest rate swaps		–		2,299		–		–		2,299
Total liabilities	$	522	$	2,799	$	57	$	20	$	3,398

(a) Level 3 assets and liabilities consist primarily of a complex wind generation purchase contract, physical power call options, congestion revenue rights transactions as discussed below and ancillary service agreements, each due to unobservable inputs in the valuation.

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

(c) The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 14.

As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	727	$	3,575	$	401	$	2	$	4,705
Interest rate swaps		–		6		–		–		6
Nuclear decommissioning trust – equity securities (c)		192		121		–		–		313
Nuclear decommissioning trust – debt securities (c)		–		223		–		–		223
Total assets	$	919	$	3,925	$	401	$	2	$	5,247
Liabilities:
Commodity contracts	$	875	$	672	$	59	$	2	$	1,608
Interest rate swaps		–		1,425		–		–		1,425
Total liabilities	$	875	$	2,097	$	59	$	2	$	3,033

(a) Level 3 assets and liabilities consist primarily of a complex wind generation purchase contract, certain natural gas positions (collars) in the long-term hedging program, physical power call options, congestion revenue rights transactions as discussed below and ancillary service agreements, each due to unobservable inputs in the valuation.

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

(c) The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 14.

In conjunction with ERCOT’s transition to a nodal wholesale market structure effective December 2010, we have entered into certain derivative transactions (primarily congestion revenue rights 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 transaction and pricing information becomes available for these pricing locations, we expect more of the valuation inputs to become observable.

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

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 6 for discussion of interest rate swaps.

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

There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the three and nine months ended September 30, 2011 or 2010. See the table below for discussion of transfers between Level 2 and Level 3.

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, 2011 and 2010:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Balance as of beginning of period	$	23		$	169		$	342		$	81
Total realized and unrealized gains (losses) included in net income (loss)		30			118			(18	)		182
Purchases, issuances and settlements (a):
Purchases		5			21			69			94
Issuances		(4	)		(11	)		(7	)		(52	)
Settlements		(60	)		(34	)		(47	)		(35	)
Transfers into Level 3 (b)		–			(11	)		–			(10	)
Transfers out of Level 3 (b)		(4	)		2			(349	)		(6	)
Net change (c)		(33	)		85			(352	)		173
Balance as of end of period	$	(10	)	$	254		$	(10	)	$	254
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period		12			116			(3	)		199

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

(b) Includes transfers due to changes in the observability of significant inputs. Transfers in and out occur at the end of each quarter, which is when the assessments are performed. Significant transfers out occurred during the first quarter 2011 for natural gas collars for 2014; these derivatives are now categorized as Level 2 due to an increase in option market trading activity in forward periods. Significant transfers out occurred during the third quarter 2011 for 2014 coal contracts, these derivatives are now categorized as Level 2 due to increased liquidity in forward periods.

(c) Substantially all changes in values of commodity contracts are reported in the income statement in net gain from commodity hedging and trading activities. Activity excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.

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10. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments attributable to EFCH (including pushed down debt) as of September 30, 2011 and December 31, 2010 were as follows:

	September 30, 2011				December 31, 2010
	Carrying     Amount		Fair     Value  (a)		Carrying     Amount		Fair     Value  (a)
On balance sheet liabilities:
Long-term debt (including current maturities) (b)	$	30,726	$	19,647	$	30,056	$	22,437
Off balance sheet liabilities:
Financial guarantees	$	–	$	4	$	—	$	9

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

(b) Excludes capital leases.

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

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11. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term commodity hedging program and the hedging of interest costs on our long-term debt. See Note 9 for a discussion of the fair value of all derivatives.

Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is largely 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 lignite/coal - and nuclear-fueled generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 6 for additional information about 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, uranium 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 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 (with the column totals representing the net positions of the contracts) as reported in the balance sheets as of September 30, 2011 and December 31, 2010:

	September 30, 2011
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	2,465		$	–	$	–		$	–		$	2,465
Noncurrent assets		1,488			–		8			–			1,496
Current liabilities		(1	)		–		(1,019	)		(653	)		(1,673	)
Noncurrent liabilities		(11	)		–		(68	)		(1,646	)		(1,725	)
Net assets (liabilities)	$	3,941		$	–	$	(1,079	)	$	(2,299	)	$	563

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	December 31, 2010
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	2,637		$	3	$	—		$	—		$	2,640
Noncurrent assets		2,068			3		—			—			2,071
Current liabilities		(2	)		—		(1,542	)		(620	)		(2,164	)
Noncurrent liabilities		—			—		(64	)		(805	)		(869	)
Net assets (liabilities)	$	4,703		$	6	$	(1,606	)	$	(1,425	)	$	1,678

As of September 30, 2011 and December 31, 2010, 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 $744 million and $479 million in net liabilities as of September 30, 2011 and December 31, 2010, respectively. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

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)	2011			2010			2011			2010
Commodity contracts (Net gain from commodity hedging and trading activities) (a)	$	323		$	979		$	494		$	2,255
Interest rate swaps (Interest expense and related charges) (b)		(796	)		(350	)		(1,390	)		(1,048	)
Net gain (loss)	$	(473	)	$	629		$	(896	)	$	1,207

(a) Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.

(b) Includes amounts reported as unrealized mark-to-market net gain/loss as well as the net effect on interest paid/accrued, both reported in “Interest Expense and Related Charges” (see Note 14).

The following table presents the pre-tax effect on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges. There were no amounts recognized in OCI for the three or nine months ended September 30, 2011 or 2010.

Derivative type (income statement presentation of loss reclassified from accumulated OCI into income)	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Interest rate swaps (interest expense and related charges)	$	(6	)	$	(19	)	$	(23	)	$	(72	)
Interest rate swaps (depreciation and amortization)		—			(1	)		(1	)		(1	)
Commodity contracts (operating revenues)		—			—			—			(1	)
Total	$	(6	)	$	(20	)	$	(24	)	$	(74	)

There were no transactions designated as cash flow hedges during the three and nine months ended September 30, 2011 and 2010.

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Accumulated other comprehensive income related to cash flow hedges as of September 30, 2011 and December 31, 2010 totaled $53 million and $68 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $9 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income as of September 30, 2011 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

Derivative Volumes – The following table presents the gross notional amounts of derivative volumes as of September 30, 2011 and December 31, 2010:

	September 30, 2011		December 31, 2010
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed	$	31,255	$	15,800	Million US dollars
Basis	$	10,250	$	15,200	Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		1,891		2,681	Million MMBtu
Locational basis swaps		740		1,092	Million MMBtu
All other		893		887	Million MMBtu
Electricity		118,876		143,776	GWh
Congestion Revenue Rights (b)		33,119		15,782	GWh
Coal		4		6	Million tons
Fuel oil		65		109	Million gallons
Uranium		1		–	Million pounds

(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 approximately 800 million MMBtu and 1.0 billion MMBtu as of September 30, 2011 and December 31, 2010, respectively.

(b) Represents gross forward purchases associated with instruments used to hedge price differences between settlement points in the new nodal wholesale market design implemented by ERCOT.

Credit Risk-Related Contingent Features of Derivatives

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if TCEH’s credit rating is downgraded by one or more credit rating agency; 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, 2011 and December 31, 2010, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $287 million and $408 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $62 million and $65 million as of September 30, 2011 and December 31, 2010, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of September 30, 2011 and December 31, 2010, the remaining related liquidity requirement would have totaled $12 million and $18 million, respectively, after reduction for net accounts receivable and derivative assets under netting arrangements.

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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, 2011 and December 31, 2010, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $2.568 billion and $1.747 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, 2011 and December 31, 2010 to reduce the liquidity exposure. 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, 2011 and December 31, 2010, the remaining related liquidity requirement would have totaled $1.430 billion and $647 million, respectively, after reduction for derivative assets under netting arrangements but before consideration of the amount of assets under the liens. See Note 6 for a description of other obligations that are supported by asset liens.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.855 billion and $2.155 billion as of September 30, 2011 and December 31, 2010, respectively. These amounts are 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, 2011, total credit risk exposure to all counterparties related to derivative contracts totaled $4.207 billion (including associated accounts receivable). The net exposure to those counterparties totaled $991 million as of September 30, 2011 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 $589 million. As of September 30, 2011, the credit risk exposure to the banking and financial sector represented 95% 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 $401 million. The largest net exposure to a single counterparty, assuming setoff provisions in the event of a default across all EFH Corp. consolidated subsidiaries, totaled $223 million as of September 30, 2011.

Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because a significant majority of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.

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

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

Our subsidiaries are participating employers in the EFH Retirement Plan, a defined benefit pension plan sponsored by EFH Corp. Our subsidiaries 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 OPEB costs applicable to us totaled $13 million and $11 million for the three months ended September 30, 2011 and 2010, respectively, and $39 million and $29 million for the nine months ended September 30, 2011 and 2010, respectively. Amounts allocated to us are settled with EFH Corp. in cash.

The discount rates reflected in net pension and OPEB costs in 2011 are 5.50% and 5.55%, respectively. The expected rates of return on pension and OPEB plan assets reflected in the 2011 cost amounts are 7.7% and 7.1%, respectively.

13. RELATED–PARTY TRANSACTIONS

The following represent our significant related-party transactions.

• TCEH’s retail operations pay electricity delivery fees to Oncor. Amounts expensed for these fees totaled $309 million and $798 million for the three and nine months ended September 30, 2011, respectively, and $317 million and $839 million for the three and nine months ended September 30, 2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheet as of September 30, 2011 and December 31, 2010 reflects amounts due currently to Oncor totaling $175 million and $143 million, respectively, (included in trade accounts and other payables to affiliates) primarily related to these electricity delivery fees.

• Oncor’s bankruptcy-remote financing subsidiary has issued securitization bonds to recover generation-related regulatory assets through a transition surcharge to its customers. Oncor’s incremental income taxes related to the transition surcharges it collects are being reimbursed by TCEH. Therefore, the balance sheet reflects a noninterest bearing note payable to Oncor of $188 million ($40 million current portion included in trade accounts and other payables to affiliates) and $217 million ($39 million current portion included in trade accounts and other payables to affiliates) as of September 30, 2011 and December 31, 2010, respectively. TCEH’s payments on the note totaled $10 million for both of the three month periods ended September 30, 2011 and 2010 and $28 million and $27 million for the nine months ended September 30, 2011 and 2010, respectively.

• TCEH reimburses Oncor for interest expense on Oncor’s bankruptcy-remote financing subsidiary’s securitization bonds. This interest expense, which is paid on a monthly basis, totaled $8 million and $24 million for the three and nine months ended September 30, 2011, respectively, and $9 million and $28 million for the three and nine months ended September 30, 2010, respectively.

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• 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. As of September 30, 2011 and December 31, 2010, the notes consisted of:

	September 30, 2011		December 31, 2010
Note related to debt principal and interest payments	$	1,171	$	916
Note related to general corporate purposes		233		1,005
Total	$	1,404	$	1,921

The principal and interest related demand note has been guaranteed by EFIH and EFCH on a pari passu basis with the EFH Corp. Senior Notes since the Merger. In connection with the amendment to the TCEH Senior Secured Facilities discussed in Note 6, the note related to net borrowings for general corporate purposes is also now guaranteed by EFIH and EFCH on the same basis as the principal and interest related demand note, and $770 million of the note was repaid in April 2011. The average daily balance of the notes totaled $1.388 billion and $1.552 billion for the three and nine months ended September 30, 2011, respectively, and $1.649 billion and $1.516 billion for the three and nine months ended September 30, 2010, respectively. The notes carry interest at a rate based on the one-month LIBOR rate plus 5.00%, and interest income totaled $18 million and $62 million for the three and nine months ended September 30, 2011, respectively, and $22 million and $61 million for the three and nine months ended September 30, 2010, respectively.

• In April 2011, TCEH settled a $770 million note payable to EFH Corp. on demand using borrowings under the TCEH Revolving Credit Facility (see Note 6). The note arose in February 2010 to repay borrowings under the facility. The note was settled in December 2010, and the amount was reborrowed in January 2011. The average daily balance of the note was $246 million for the nine months ended September 30, 2011 and was $770 million and $607 million for the three and nine months ended September 30, 2010, respectively. The note carried interest at a rate based on the one-month LIBOR rate plus 3.50%, and interest expense totaled $7 million for the nine months ended September 30, 2011 and $7 million and $17 million for the three and nine months ended September 30, 2010, respectively. 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 $49 million and $46 million as of September 30, 2011 and December 31, 2010, respectively. The note carries interest at a rate based on the one-month LIBOR rate plus 5.00%.

• Our subsidiaries pay a subsidiary of EFH Corp. for information technology, financial, accounting and other administrative services at cost. These costs, which are primarily reported in SG&A expenses, totaled $55 million and $155 million for the three and nine months ended September 30, 2011, respectively, and $48 million and $141 million for the three and nine months ended September 30, 2010, respectively.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in investments on our balance sheet, is funded by a delivery fee surcharge billed to REPs by Oncor and remitted monthly to TCEH (totaling $5 million and $13 million for the three and nine months ended September 30, 2011, respectively, and $5 million and $12 million for the three and nine months ended September 30, 2010, respectively), with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported as notes or other liabilities due affiliates on our balance sheet. Income and expenses associated with the trust fund and the decommissioning liability 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, 2011 and December 31, 2010, the excess of the trust fund balance over the decommissioning liability resulted in a payable to Oncor totaling $188 million and $206 million, respectively, included in notes or other liabilities due affiliates in the balance sheet.

• TCEH had posted cash collateral totaling $4 million as of December 31, 2010 to Oncor related to interconnection agreements for the generation units developed by TCEH. The collateral was returned in April 2011. The collateral was reported in our December 31, 2010 balance sheet in other current assets.

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• EFH Corp. files a consolidated federal income tax return; however, our 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 we file our own corporate income tax return. As a result, we had income taxes payable to EFH Corp. of $371 million and $21 million as of September 30, 2011 and December 31, 2010, respectively. We made income tax net payments to EFH Corp. totaling $75 million and $58 million for the nine months ended September 30, 2011 and 2010, 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, 2011 and December 31, 2010, TCEH had posted letters of credit in the amount of $13 million and $14 million, respectively, for the benefit of Oncor.

• Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred, two or more rating agencies downgrade Oncor’s credit ratings below investment grade.

• In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with us and/or provided financial advisory services to us, in each case in the normal course of business, and participated on terms similar to nonaffiliated lenders in the April 2011 amendment and extension of the TCEH Senior Secured Facilities discussed in Note 6.

• In the nine months ended September 30, 2011, fees paid to Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, related to debt issuances and exchanges totaled $26 million, described as follows: (i) Goldman acted as a joint lead arranger and joint book-runner in the April 2011 amendment and extension of the TCEH Senior Secured Facilities discussed in Note 6 and received fees totaling $17 million; (ii) Goldman also acted as a joint book-running manager and initial purchaser in the issuance of $1.750 billion principal amount of TCEH Senior Secured Notes as part of the April 2011 amendment and extension and received fees totaling $9 million. Affiliates of KKR and TPG Capital, L.P. served as advisors to these transactions and each received $5 million as compensation for their services. In January 2010, Goldman acted as an initial purchaser in the issuance of $500 million principal amount of EFH Corp. 10% Notes for which it received fees totaling $3 million.

• As a result of debt repurchase and exchange transactions in 2009, 2010 and 2011, EFH Corp. and EFIH held as investments TCEH debt securities as follows (principal amounts):

	September 30, 2011		December 31, 2010
TCEH Senior Notes:
Held by EFH Corp.	$	244	$	244
Held by EFIH	$	79	$	79
TCEH Term Loan Facilities:
Held by EFH Corp.	$	19	$	20

Interest expense on the notes totaled $8 million and $25 million for the three and nine months ended September 30, 2011, respectively, and $11 million and $20 million for the three and nine months ended September 30, 2010, respectively.

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

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

34

See Notes 6 and 7 for guarantees and push-down of certain EFH Corp. debt, Note 12 for allocation of EFH Corp. pension and OPEB costs to us and Note 14 for discussion of stock-based compensation.

14. SUPPLEMENTARY FINANCIAL INFORMATION

Stock-Based Compensation

In December 2010, in consideration of the desire to enhance retention incentives, EFH Corp. offered employee grantees of all stock options (excluding named executive officers and a limited number of other employees) the right to exchange their vested and unvested options for restricted stock units payable in shares (at a ratio of two options for each stock unit). The restricted stock units vest as shares of common stock of EFH Corp. in September 2014. The exchange offer closed in late February 2011, and substantially all eligible employees accepted the offer, which resulted in the issuance of 6.5 million restricted stock units in exchange for 11.1 million time-based options (including 3.5 million that were vested) and 1.9 million performance-based options (including 1.4 million that were vested). In addition, restricted stock units issued as compensation to management employees and directors totaled 0.1 million and 0.6 million in the three and nine months ended September 30, 2011, respectively.

In October 2011, in consideration of the desire to enhance retention incentives, EFH Corp. offered its named executive officers and a limited number of other officers (including certain of our officers) the right to exchange their vested and unvested options for restricted stock units payable in shares on terms largely consistent with offers made in December 2010 to other employee grantees of stock options. The restricted stock units vest as shares of common stock of EFH Corp. upon the earlier of September 2014 or a change in control as defined in the exchange offer, or on a prorated basis upon certain other defined events, such as termination without cause or resignation for good reason. The maximum number of options to be exchanged for restricted stock units on a two-for-one basis is 22.3 million. The exchange offer is expected to close in November 2011.

Expense recognized for restricted stock units payable in shares totaled $1.0 million and $2.6 million for the three and nine months ended September 30, 2011, respectively. Expense recognized for options granted totaled $0.6 million and $1.7 million for the three and nine months ended September 30, 2011, respectively, and $1.7 million and $6.8 million for the three and nine months ended September 30, 2010, respectively. In addition, with respect to restricted stock units payable in cash, a credit of $0.9 million was recorded in the nine months ended September 30, 2011 and a credit of $1.6 million was recorded in the nine months ended September 30, 2010 as a result of the change in value of EFH Corp. shares.

35

Other Income and Deductions

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Other income:
Settlement of counterparty bankruptcy claims (a)	$	–	$	–	$	21	$	–
Property damage claim		–		–		7		–
Franchise tax refund		–		–		6		–
Gain on sale of land/water rights		–		–		–		44
Gain on sale of interest in natural gas gathering pipeline business		–		–		–		37
Insurance/litigation settlements		–		6		–		6
Sales tax refund		2		–		2		5
Mineral rights royalty income		1		–		2		1
Other		1		–		5		2
Total other income	$	4	$	6	$	43	$	95
Other deductions:
Impairment of emissions allowances (Note 3)	$	418	$	–	$	418	$	–
Severance charges (Note 3)		49		–		49		2
Impairment of assets related to mining operations (Note 3)		9		–		9		–
Net third party fees paid in connection with the amendment and extension of the TCEH Senior Secured Facilities (Note 6)		–		–		86		–
Gas plant impairment charges		–		–		–		1
Other		2		3		6		9
Total other deductions	$	478	$	3	$	568	$	12

(a) Represents net cash received as a result of the settlement of bankruptcy claims against a hedging/trading counterparty. A reserve of $26 million was established in 2008 related to amounts then due from the counterparty.

Interest Expense and Related Charges

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	685		$	619		$	1,945		$	1,881
Accrued interest to be paid with additional toggle notes		42			58			122			170
Unrealized mark-to-market net loss on interest rate swaps (Note 6)		619			181			879			542
Amortization of interest rate swap losses at dedesignation of hedge accounting		5			19			22			72
Amortization of fair value debt discounts resulting from purchase accounting		5			4			11			13
Amortization of debt issuance, amendment and extension costs and discounts (a)		46			30			136			93
Capitalized interest		(8	)		(6	)		(24	)		(53	)
Total interest expense and related charges	$	1,394		$	905		$	3,091		$	2,718

(a) Includes write-off in the second quarter 2011 of $16 million of previously deferred fees as a result of the amendment and extension transactions in April 2011 (see Note 6).

Restricted Cash

	September 30, 2011				December 31, 2010
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 6)	$	—	$	947	$	—	$	1,135
Amounts related to margin deposits held		84		—		33		—
Total restricted cash	$	84	$	947	$	33	$	1,135

36

Inventories by Major Category

	September 30, 2011		December 31, 2010
Materials and supplies	$	173	$	162
Fuel stock		152		198
Natural gas in storage		33		35
Total inventories	$	358	$	395

Investments

	September 30, 2011		December 31, 2010
Nuclear decommissioning trust	$	532	$	536
Assets related to employee benefit plans, including employee savings programs, net of distributions		10		17
Land		41		41
Investment in unconsolidated affiliate		1		5
Miscellaneous other		4		3
Total investments	$	588	$	602

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 change in receivables from/payables due to Oncor, reflecting changes in Oncor’s regulatory asset/liability. A summary of investments in the fund follows:

	September 30, 2011
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	229	$	11	$	(2	)	$	238
Equity securities (c)		226		93		(25	)		294
Total	$	455	$	104	$	(27	)	$	532

	December 31, 2010
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	221	$	6	$	(4	)	$	223
Equity securities (c)		213		115		(15	)		313
Total	$	434	$	121	$	(19	)	$	536

(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 4.24% and 4.61% and an average maturity of 6.0 years and 8.8 years as of September 30, 2011 and December 31, 2010, 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, 2011 mature as follows: $107 million in one to five years, $50 million in five to ten years and $81 million after ten years.

37

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011			2010
Realized gains	$	—	$	—	$	1		$	1
Realized losses		—		—		(2	)		(1	)
Proceeds from sale of securities		601		134		2,385			937

Property, Plant and Equipment

As of September 30, 2011 and December 31, 2010, property, plant and equipment of $19.4 billion and $20.2 billion, respectively, is stated net of accumulated depreciation and amortization of $5.2 billion and $4.1 billion, respectively. See Note 3 for discussion of accelerated lignite mining asset depreciation recorded in the third quarter 2011 as a result of the EPA’s issuance of the CSAPR.

Asset Retirement and Mining Reclamation 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 these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in the balance sheet, during the nine months ended September 30, 2011:

	Nuclear Plant		Mining and Other			Total
Liability as of January 1, 2011	$	329	$	164		$	493
Additions:
Accretion		14		22			36
Reductions:
Payments		–		(54	)		(54	)
Liability as of September 30, 2011		343		132			475
Less amounts due currently		–		32			32
Noncurrent liability as of September 30, 2011	$	343	$	100		$	443

Other Noncurrent Liabilities and Deferred Credits

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

	September 30, 2011		December 31, 2010
Uncertain tax positions (including accrued interest)	$	1,096	$	1,059
Asset retirement and mining reclamation obligations		443		452
Unfavorable purchase and sales contracts		653		673
Retirement plan and other employee benefits		48		44
Other		19		8
Total other noncurrent liabilities and deferred credits	$	2,259	$	2,236

The conclusion of all issues contested by EFH Corp. with the IRS from the 1997 through 2002 audit, including IRS Joint Committee review, is expected to occur before the end of 2012. Upon such conclusion, we expect to reduce the liability for uncertain tax positions by approximately $85 million with an offsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes.

38

The EFH Corp. IRS audit for the years 2003 through 2006 was concluded in June 2011. A significant number of proposed adjustments are in appeals with the IRS. The results of the audit did not affect management’s assessment of issues for purposes of determining the liability for uncertain tax positions. Other than the items discussed immediately above, we do not expect the total amount of liabilities recorded related to uncertain tax positions to significantly increase or decrease within the next 12 months.

Unfavorable Purchase and Sales Contracts – The amortization of unfavorable purchase and sales contracts totaled $7 million in both the three months ended September 30, 2011 and 2010 and $20 million in both the nine months ended September 30, 2011 and 2010. See Note 4 for intangible assets related to favorable purchase and sales contracts.

The estimated amortization of unfavorable purchase and sales contracts for each of the five fiscal years from December 31, 2010 is as follows:

Year	Amount
2011	$	27
2012		27
2013		26
2014		25
2015		25

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2011			2010
Cash payments (receipts) related to:
Interest paid (a)	$	1,630		$	1,491
Capitalized interest		(24	)		(53	)
Interest paid (net of capitalized interest) (a)		1,606			1,438
Income taxes		75			58
Noncash investing and financing activities:
Effect of push down of debt from parent		(196	)		(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		28			(124	)
Principal amount of TCEH Toggle Notes issued in lieu of cash interest (Note 6)		79			110
Construction expenditures (b)		33			36
Contribution related to EFH Corp. stock-based compensation		4			7

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

(b) Represents end-of-period accruals.

39

15. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

As of September 30, 2011, TCEH and TCEH Finance, as Co-Issuers, had outstanding $4.973 billion aggregate principal amount of 10.25% Senior Notes Due 2015, 10.25% Senior Notes due 2015 Series B and Toggle Notes (collectively, the TCEH Senior Notes) and $1.571 billion aggregate principal amount of 15% Senior Secured Second Lien Notes due 2021 and 15% Senior Secured Second Lien Notes due 2021 (Series B) (collectively, the TCEH Senior Secured Second Lien Notes). The TCEH Senior Notes and the TCEH Senior Secured Second Lien 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 and the TCEH Senior Secured Second Lien Notes. The guarantees of the TCEH Senior Notes 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. The guarantees of the TCEH Senior Secured Second Lien Notes 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 Facilities, the TCEH Senior Secured Notes issued in April 2011 (see Note 6) 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. All other subsidiaries of EFCH, either direct or indirect, do not guarantee the TCEH Senior Notes or TCEH Senior Secured Second Lien Notes (collectively the Non-Guarantors). The indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes contain certain restrictions, subject to certain exceptions, on EFCH’s ability to pay dividends or make investments. See Note 8.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income and of cash flows of EFCH (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors for the three and nine months ended September 30, 2011 and 2010 and the condensed consolidating balance sheets as of September 30, 2011 and December 31, 2010 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 $280 million and $464 million of the EFH Corp. Senior Notes as of September 30, 2011 and December 31, 2010, respectively, and $386 million of the EFH Corp. Senior Secured Notes to the Parent and the TCEH Senior Notes, TCEH Senior Secured Notes, TCEH Senior Secured Second Lien Notes and TCEH Senior Secured Facilities to the Other Guarantors as of both September 30, 2011 and December 31, 2010. TCEH Finance’s sole function is to be the co-issuer of the certain TCEH debt securities; therefore, it has no other independent assets, liabilities or operations (see Note 6).

EFCH (parent entity) received no dividends/distributions from its consolidated subsidiaries in the three or nine months ended September 30, 2011 or 2010.

40

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended September 30, 2011

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	–		$	–		$	2,321		$	3		$	(3	)	$	2,321
Fuel, purchased power costs and delivery fees		–			–			(1,058	)		–			–			(1,058	)
Net gain (loss) from commodity hedging and trading activities		–			275			(5	)		–			–			270
Operating costs		–			–			(207	)		–			–			(207	)
Depreciation and amortization		–			–			(371	)		–			–			(371	)
Selling, general and administrative expenses		–			–			(194	)		(1	)		3			(192	)
Franchise and revenue-based taxes		–			–			(21	)		–			–			(21	)
Other income		–			–			4			–			–			4
Other deductions		–			–			(478	)		–			–			(478	)
Interest income		–			98			185			–			(263	)		20
Interest expense and related charges		(22	)		(1,552	)		(607	)		(2	)		789			(1,394	)
Loss before income taxes		(22	)		(1,179	)		(431	)		–			526			(1,106	)
Income tax benefit		7			400			163			–			(188	)		382
Equity earnings (losses) of subsidiaries		(709	)		70			–			–			639			–
Net loss	$	(724	)	$	(709	)	$	(268	)	$	–		$	977		$	(724	)

41

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	)

42

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Nine Months Ended September 30, 2011

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	–		$	–		$	5,672		$	8		$	(8	)	$	5,672
Fuel, purchased power costs and delivery fees		–			–			(2,726	)		–			–			(2,726	)
Net gain (loss) from commodity hedging and trading activities		–			460			(95	)		–			–			365
Operating costs		–			–			(670	)		–			–			(670	)
Depreciation and amortization		–			–			(1,097	)		–			–			(1,097	)
Selling, general and administrative expenses		–			–			(534	)		(3	)		8			(529	)
Franchise and revenue-based taxes		–			–			(64	)		–			–			(64	)
Other income		6			(16	)		53			–			–			43
Other deductions		–			(87	)		(481	)		–			–			(568	)
Interest income		–			281			497			–			(713	)		65
Interest expense and related charges		(72	)		(3,500	)		(1,688	)		(5	)		2,174			(3,091	)
Loss before income taxes		(66	)		(2,862	)		(1,133	)		–			1,461			(2,600	)
Income tax benefit		20			969			400			–			(495	)		894
Equity earnings (losses) of subsidiaries		(1,660	)		233			–			–			1,427			–
Net loss	$	(1,706	)	$	(1,660	)	$	(733	)	$	–		$	2,393		$	(1,706	)

43

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	)

44

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2011

(millions of dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(1	)	$	(804	)	$	1,975		$	(121	)	$	–		$	1,049
Cash flows – financing activities:
Notes due to affiliates		4			1,935			–			7			(1,946	)		–
Issuances of long-term debt		–			1,750			–			–			–			1,750
Repayments/repurchases of long-term debt		(3	)		(957	)		(25	)		–			–			(985	)
Net short-term borrowings under accounts receivable securitization program		–			–			–			115			–			115
Decrease in other short-term borrowings		–			(1,126	)		–			–			–			(1,126	)
Decrease in income tax-related note payable to Oncor		–			–			(28	)		–			–			(28	)
Contributions from noncontrolling interests		–			–			–			13			–			13
Debt amendment, exchange and issuance costs		–			(843	)		–			–			–			(843	)
Other, net		–			–			(1	)		–			–			(1	)
Cash provided by (used in) financing activities		1			759			(54	)		135			(1,946	)		(1,105	)
Cash flows – investing activities:
Capital expenditures		–			–			(348	)		(13	)		–			(361	)
Nuclear fuel purchases		–			–			(125	)		–			–			(125	)
Notes/loans (to) from affiliates		–			–			(1,419	)		–			1,946			527
Proceeds from sales of assets		–			–			49			–			–			49
Reduction of restricted cash related to TCEH letter of credit facility		–			188			–			–			–			188
Other changes in restricted cash		–			–			(50	)		–			–			(50	)
Proceeds from sales of environmental allowances and credits		–			–			2			–			–			2
Purchases of environmental allowances and credits		–			–			(12	)		–			–			(12	)
Proceeds from sales of nuclear decommissioning trust fund securities		–			–			2,385			–			–			2,385
Investments in nuclear decommissioning trust fund securities		–			–			(2,398	)		–			–			(2,398	)
Other-net		–			–			6			–			–			6
Cash provided by (used in) investing activities		–			188			(1,910	)		(13	)		1,946			211
Net change in cash and cash equivalents		–			143			11			1			–			155
Cash and cash equivalents – beginning balance		–			23			15			9			–			47
Cash and cash equivalents – ending balance	$	–		$	166		$	26		$	10		$	–		$	202

45

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/repurchases of long-term borrowings		(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 due to affiliates		34			1,399			–			–			(629	)		804
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:
Capital expenditures		–			–			(650	)		(26	)		–			(676	)
Nuclear fuel purchases		–			–			(84	)		–			–			(84	)
Net loans to affiliates		(24	)		–			(887	)		–			629			(282	)
Changes in restricted cash		–			–			(31	)		–			–			(31	)
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	)
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	)
Effect of consolidation of VIE		–			–			–			7			–			7
Cash and cash equivalents – beginning balance		–			77			11			6			–			94
Cash and cash equivalents – ending balance	$	38		$	31		$	9		$	–		$	–		$	78

46

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of September 30, 2011

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	–		$	166		$	26		$	10	$	–		$	202
Restricted cash		–			–			84			–		–			84
Advances to affiliates		–			–			8,202			–		(8,202	)		–
Trade accounts receivable – net		–			4			799			731		(520	)		1,014
Income taxes receivable		–			–			305			–		(305	)		–
Accounts receivable from affiliates		–			13			–			–		(13	)		–
Notes receivable from parent		–			1,404			–			–		–			1,404
Inventories		–			–			358			–		–			358
Commodity and other derivative contractual assets		–			1,192			1,273			–		–			2,465
Accumulated deferred income taxes		1			24			–			–		(20	)		5
Margin deposits related to commodity positions		–			–			59			–		–			59
Other current assets		–			–			42			1		1			44
Total current assets		1			2,803			11,148			742		(9,059	)		5,635
Restricted cash		–			947			–			–		–			947
Investments		(6,786	)		22,870			622			–		(16,118	)		588
Property, plant and equipment – net		–			–			19,221			130		–			19,351
Goodwill		–			6,152			–			–		–			6,152
Identifiable intangible assets – net		–			–			1,847			–		–			1,847
Commodity and other derivative contractual assets		–			1,357			139			–		–			1,496
Accumulated deferred income taxes		–			657			–			1		(658	)		–
Other noncurrent assets, principally unamortized issuance costs		7			1,011			945			5		(929	)		1,039
Total assets	$	(6,778	)	$	35,797		$	33,922		$	878	$	(26,764	)	$	37,055
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	–		$	–		$	–		$	211	$	–		$	211
Notes/advances from affiliates		9			8,193			–			7		(8,202	)		7
Long-term debt due currently		9			415			29			–		–			453
Trade accounts payable		–			–			553			522		(520	)		555
Trade accounts and other payables to affiliates		–			–			254			3		(13	)		244
Notes payable to parent/affiliate		49			–			–			–		–			49
Commodity and other derivative contractual liabilities		–			884			789			–		–			1,673
Margin deposits related to commodity positions		–			601			200			–		–			801
Accumulated deferred income taxes		–			–			20			–		(20	)		–
Accrued income taxes payable to parent		6			670			–			–		(305	)		371
Accrued taxes other than income		–			–			103			–		–			103
Accrued interest		25			551			415			–		(414	)		577
Other current liabilities		–			4			264			–		(3	)		265
Total current liabilities		98			11,318			2,627			743		(9,477	)		5,309
Accumulated deferred income taxes		67			–			4,463			–		159			4,689
Commodity and other derivative contractual liabilities		–			1,684			41			–		–			1,725
Notes or other liabilities due affiliates		–			–			336			–		–			336
Long-term debt held by affiliates		–			342			–			–		–			342
Long-term debt, less amounts due currently		746			29,183			28,591			–		(28,523	)		29,997
Other noncurrent liabilities and deferred credits		13			57			2,190			–		(1	)		2,259
Total liabilities		924			42,584			38,248			743		(37,842	)		44,657
EFCH shareholder’s equity		(7,702	)		(6,787	)		(4,326	)		35		11,078			(7,702	)
Noncontrolling interests in subsidiaries		–			–			–			100		–			100
Total equity		(7,702	)		(6,787	)		(4,326	)		135		11,078			(7,602	)
Total liabilities and equity	$	(6,778	)	$	35,797		$	33,922		$	878	$	(26,764	)	$	37,055

47

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of December 31, 2010

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	–		$	23		$	15		$	9	$	–		$	47
Restricted cash		–			–			33			–		–			33
Advances to affiliates		–			–			6,783			–		(6,783	)		–
Trade accounts receivable – net		–			4			891			612		(516	)		991
Income taxes receivable		–			–			59			–		(59	)		–
Accounts receivable from affiliates		–			3			–			–		(3	)		–
Notes receivable from parent		–			1,921			–			–		–			1,921
Inventories		–			–			395			–		–			395
Commodity and other derivative contractual assets		–			696			1,944			–		–			2,640
Accumulated deferred income taxes		3			–			–			–		(3	)		–
Margin deposits related to commodity positions		–			–			166			–		–			166
Other current assets		–			–			35			2		–			37
Total current assets		3			2,647			10,321			623		(7,364	)		6,230
Restricted cash		–			1,135			–			–		–			1,135
Investments		(5,145	)		22,632			635			–		(17,520	)		602
Property, plant and equipment – net		–			–			20,043			112		–			20,155
Goodwill		–			6,152			–			–		–			6,152
Identifiable intangible assets – net		–			–			2,371			–		–			2,371
Commodity and other derivative contractual assets		–			1,760			311			–		–			2,071
Accumulated deferred income taxes		–			–			–			1		(1	)		–
Other noncurrent assets, principally unamortized issuance costs		11			403			377			6		(369	)		428
Total assets	$	(5,131	)	$	34,729		$	34,058		$	742	$	(25,254	)	$	39,144
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	–		$	1,125		$	1,125		$	96	$	(1,125	)	$	1,221
Notes/advances from affiliates		8			6,774			–			1		(6,783	)		–
Long-term debt due currently		9			621			233			–		(205	)		658
Trade accounts payable		–			–			666			519		(516	)		669
Trade accounts and other payables to affiliates		–			–			210			3		(3	)		210
Notes payable to parent/affiliate		46			–			–			–		–			46
Commodity and other derivative contractual liabilities		–			918			1,246			–		–			2,164
Margin deposits related to commodity positions		–			341			290			–		–			631
Accrued income taxes payable to parent		–			79			–			1		(59	)		21
Accrued taxes other than income		–			–			130			–		–			130
Accrued interest		26			298			185			–		(183	)		326
Other current liabilities		–			8			253			–		(7	)		254
Total current liabilities		89			10,164			4,338			620		(8,881	)		6,330
Accumulated deferred income taxes		70			376			5,655			–		(101	)		6,000
Commodity and other derivative contractual liabilities		–			831			38			–		–			869
Notes or other liabilities due affiliates		–			–			384			–		–			384
Long-term debt held by affiliate		–			343			–			–		–			343
Long-term debt, less amounts due currently		934			28,106			27,550			–		(27,459	)		29,131
Other noncurrent liabilities and deferred credits		12			55			2,169			–		–			2,236
Total liabilities		1,105			39,875			40,134			620		(36,441	)		45,293
EFCH shareholder’s equity		(6,236	)		(5,146	)		(6,076	)		35		11,187			(6,236	)
Noncontrolling interests in subsidiaries		–			–			–			87		–			87
Total equity		(6,236	)		(5,146	)		(6,076	)		122		11,187			(6,149	)
Total liabilities and equity	$	(5,131	)	$	34,729		$	34,058		$	742	$	(25,254	)	$	39,144

48

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

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2011 and 2010 should be read in conjunction with our consolidated financial statements and the notes to those statements.

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

Business

EFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. We conduct our operations almost entirely through our 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 and sourcing of electricity, 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, 2011, has effectively sold forward approximately 800 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 100,000 GWh at an assumed 8.0 market heat rate) at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.

These transactions, as well as forward power sales, have effectively hedged an estimated 47% of the natural gas price exposure related to TCEH’s expected generation output, including the effects of the CSAPR as discussed below, through December 31, 2015 (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 generally 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the NYMEX Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged approximately 90% of the Houston Ship Channel versus Henry Hub pricing point risk for 2011.

The company has entered into related put and call transactions (referred to as collars), primarily for 2014, that effectively hedge natural gas prices within a range. These transactions represented 19% of the positions in the long-term hedging program as of September 30, 2011, 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.

49

The following table summarizes the natural gas hedges in the long-term hedging program as of September 30, 2011:

	Measure	Balance 2011 (a)	2012	2013	2014	2015	Total
Natural gas hedge volumes (b)	mm MMBtu	~57	~331	~259	~149	—	~796
Weighted average hedge price (c)	$/MMBtu	~7.60	~7.36	~7.19	~7.80	—	—
Weighted average market price (d)	$/MMBtu	~3.80	~4.24	~4.80	~5.13	~5.39	—

(a) Balance of 2011 is from October 1, 2011 through December 31, 2011.

(b) Where collars are reflected, the volumes are based on the notional position of the derivatives to represent protection against downward price movements. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 120 million MMBtu in 2014.

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

(d) Based on NYMEX Henry Hub prices.

Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of September 30, 2011, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $800 million in pretax unrealized mark-to-market gains or losses.

Net gain related to the long-term hedging program, which is reported in net gain from commodity hedging and trading activities, was as follows:

	Three Months Ended September 30,				Nine Months  Ended September 30,
	2011		2010		2011			2010
Realized net gain	$	290	$	262	$	911		$	791
Unrealized net gain (loss) including reversals of previously recorded amounts on positions settled		102		671		(299	)		1,561
Total	$	392	$	933	$	612		$	2,352

The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $2.844 billion and $3.143 billion as of September 30, 2011 and December 31, 2010, respectively.

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.

50

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. 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 electricity prices, depressed forward natural gas prices are challenging to the long-term profitability of our generation assets. Specifically, these lower natural gas prices and the correlated effect in ERCOT on wholesale electricity prices could have a material impact on the overall profitability of our generation assets for periods in which we have less significant hedge positions (i.e., beginning in 2013). In addition, a continuation or worsening of these market conditions would limit our ability to hedge our wholesale electricity revenues at sufficient price levels to support our interest payments and debt maturities and could adversely impact our ability to refinance our long-term debt, a portion of which begins to mature in 2014.

	Forward Market Prices for Calendar Year ($/MMBtu) (a)
Date	2011 (b)		2012		2013		2014		2015
June 30, 2008	$	10.78	$	10.74	$	10.90	$	11.12	$	11.36
September 30, 2008	$	8.54	$	8.41	$	8.30	$	8.30	$	8.44
December 31, 2008	$	7.31	$	7.23	$	7.15	$	7.15	$	7.21
March 31, 2009	$	6.67	$	6.96	$	7.11	$	7.18	$	7.25
June 30, 2009	$	6.89	$	7.16	$	7.30	$	7.43	$	7.57
September 30, 2009	$	6.87	$	7.00	$	7.06	$	7.17	$	7.31
December 31, 2009	$	6.34	$	6.53	$	6.67	$	6.84	$	7.05
March 31, 2010	$	5.34	$	5.79	$	6.07	$	6.36	$	6.68
June 30, 2010	$	5.34	$	5.68	$	5.89	$	6.10	$	6.37
September 30, 2010	$	4.44	$	5.07	$	5.29	$	5.42	$	5.60
December 31, 2010	$	4.55	$	5.08	$	5.33	$	5.49	$	5.64
March 31, 2011	$	4.57	$	5.06	$	5.41	$	5.73	$	6.08
June 30, 2011	$	4.47	$	4.84	$	5.16	$	5.42	$	5.70
September 30, 2011	$	3.80	$	4.24	$	4.80	$	5.13	$	5.39

(a) Based on NYMEX Henry Hub prices.

(b) For March 31, June 30 and September 30, 2011, natural gas prices for 2011 represent the average of forward prices for April through December, July through December and October through December, respectively.

As of September 30, 2011, more than 90% 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, 2011, 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 basis, generally 12 months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

	Balance 2011(a)		2012		2013		2014		2015
$1.00/MMBtu change in gas price (b)	$	~3	$	~15	$	~245	$	~395	$	~550
0.1/MMBtu/MWh change in market heat rate (c)	$	~1	$	~13	$	~33	$	~40	$	~43
$1.00/gallon change in diesel fuel price	$	~1	$	~7	$	~45	$	~46	$	~46

(a) Balance of 2011 is from November 1, 2011 through December 31, 2011.

(b) Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas generally 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, 2011.

51

Disclosures in the above paragraphs related to hedged generation output and commodity price sensitivities take into account the expected effects on our operations of the CSAPR as issued in July 2011. See “Recent EPA Actions – Cross-State Air Pollution Rule” below for discussion of the EPA’s proposed revisions to the CSAPR.

Liability Management Program — As of September 30, 2011, EFCH had $31.1 billion principal amount of debt outstanding, including short-term borrowings and $666 million pushed down from EFH Corp. EFH Corp. has implemented a liability management program designed to improve its balance sheet by reducing debt and extending debt maturities through debt exchanges, repurchases and amendments.

Amendments to the TCEH Senior Secured Facilities completed in April 2011 resulted in the extension of $16.4 billion in loan maturities under the TCEH Term Loan Facilities and the TCEH Letter of Credit Facility from October 2014 to October 2017 and $1.4 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016.

See Note 6 to Financial Statements for further discussion of the transactions completed under our liability management program in 2011.

Wholesale Market Design – Nodal Market — In accordance with a rule adopted by the PUCT in 2003, ERCOT developed a new wholesale market, using a stakeholder process, designed to assign congestion costs to the market participants causing the congestion. The nodal market design was implemented December 1, 2010. Under this new market design, ERCOT:

• establishes nodes, which are metered locations across the ERCOT grid, for purposes of more granular price determination;

• operates a voluntary “day-ahead electricity market” for forward sales and purchases of electricity and other related transactions, in addition to the existing “real-time market” that primarily functions to balance power consumption and generation;

• establishes hub trading prices, which represent the average of certain node prices within four major geographic regions, at which participants can hedge or trade power under bilateral contracts;

• establishes pricing for load-serving entities based on weighted-average node prices within new geographical load zones, and

• provides congestion revenue rights, which are instruments auctioned by ERCOT that allow market participants to hedge price differences between settlement points.

ERCOT previously had a zonal wholesale market structure consisting of four geographic zones. The new location-based congestion-management market is referred to as a “nodal” market because wholesale pricing differs across the various nodes on the transmission grid instead of across the geographic zones. There are over 500 nodes in the ERCOT market. The nodal market design was implemented in conjunction with transmission improvements designed to reduce current congestion. We are fully certified to participate in both the “day-ahead” and “real-time markets.” Additionally, all of our operational generation assets and our qualified scheduling entities are certified and operate in the nodal market. While the initial implementation of the nodal market has not had a material impact on our profitability, we cannot predict the ultimate impact of the market design on our operations or financial results, and it could ultimately have an adverse impact on the profitability and value of our competitive business and/or our liquidity, particularly if such change ultimately results in lower revenue due to lower wholesale power prices, increased costs to service end-user electricity demand or increased collateral posting requirements with ERCOT. The opening of the nodal market resulted in an increase of approximately $200 million in the amount of letters of credit posted with ERCOT to support our market participation.

As discussed above, the nodal market design includes the establishment of a “day-ahead market” and hub trading prices to facilitate hedging and trading of electricity by participants. Under the previous zonal market, volumes under our nontrading bilateral purchase and sales contracts, including contracts intended as hedges, were scheduled as physical power with ERCOT and, therefore, reported gross as wholesale revenues or purchased power costs. In conjunction with the transition to the nodal market, unless the volumes represent physical deliveries to retail and wholesale customers or purchases from counterparties, these contracts are reported on a net basis in the income statement in net gain (loss) from commodity hedging and trading activities. As a result of these changes, reported wholesale revenues and purchased power costs (and the associated volumes) in 2011 will be materially less than amounts reported in prior periods.

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TCEH Interest Rate Swap Transactions — As of September 30, 2011, TCEH has entered into a series of interest rate swaps that effectively fix the interest rates at between 5.5% and 9.3% on $18.65 billion principal amount of its senior secured debt to October 2014 and on up to $12.6 billion principal amount of its senior secured debt from October 2014 to October 2017. Swaps related to an aggregate $2.60 billion principal amount of debt expired or were terminated in the nine months ended September 30, 2011, and swaps related to an aggregate $5.45 billion principal amount of debt maturing from 2012 to 2014 (growing to $10.58 billion over time, primarily as existing swaps expire) and up to $12.6 billion principal amount of debt maturing from 2014 to 2017 were entered into in the same period. Taking into consideration these swap transactions, as of September 30, 2011, 4% of our long-term debt portfolio was exposed to variable interest rate risk through September 2014 and 11% for October 2014 through October 2017. We may enter into additional interest rate hedges from time to time.

As of September 30, 2011, TCEH has also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $10.25 billion principal amount of senior secured debt. Swaps related to an aggregate $4.95 billion principal amount of debt expired in the nine months ended September 30, 2011.

Unrealized mark-to-market net gains and losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $619 million and $879 million of net loss in the three and nine months ended September 30, 2011, respectively, and $181 million and $542 million of net loss in 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 $2.299 billion and $1.419 billion as of September 30, 2011 and December 31, 2010, respectively, of which $81 million and $105 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 6 to Financial Statements regarding interest rate swap transactions.

Recent EPA Actions — Cross-State Air Pollution Rule — In 2005, the EPA issued a final rule (the Clean Air Interstate Rule or CAIR) intended to implement the provisions of the Clean Air Act Section 110(a)(2)(D)(i)(I) (CAA Section 110) requiring states to reduce emissions of sulfur dioxide (SO₂) and nitrogen oxide (NO_x) that significantly contribute to other states failing to attain or maintain compliance with the EPA’s National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone. In 2008, the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) invalidated CAIR, but allowed the rule to continue until the EPA issued a final replacement rule. In August 2010, the EPA issued for comment a proposed replacement rule for CAIR called the Clean Air Transport Rule (CATR), similarly intended to implement CAA Section 110. As proposed, the CATR did not include Texas in its annual SO₂ or NO_x programs to address alleged downwind fine particulate matter effects.

In July 2011, the EPA issued the final replacement rule for CAIR (as finally issued, the Cross-State Air Pollution Rule (CSAPR)). Unlike the CATR, the CSAPR includes Texas in its annual SO₂ and NO_x emissions reduction programs, as well as the seasonal NO_x emissions reduction program. These programs require significant additional reductions of SO₂ and NO_x emissions from fossil-fueled generation units in covered states (including Texas) and institute a limited “cap and trade” system as an additional compliance tool to achieve reductions the EPA contends are necessary to implement CAA Section 110. Compliance with the CSAPR’s annual emissions reduction programs is required beginning January 1, 2012, and compliance with the CSAPR’s seasonal emissions reduction program is required beginning May 1, 2012.

In August 2011, we petitioned the EPA to reconsider and stay the effectiveness of the CSAPR, in each case as applied to Texas. The EPA has not yet formally responded to our petition. We cannot predict whether we will be successful in, or when (if ever) the EPA will respond to, our petition.

In September 2011, we filed a petition for review in the D.C. Circuit Court challenging the CSAPR and a motion to stay the effective date of the CSAPR, in each case as applied to Texas. The briefing on our stay motion is complete, and we await the D.C. Circuit Court’s ruling on our motion. We cannot predict (i) whether we will be successful in our legal challenge to the CSAPR or our motion to stay the effective date of the CSAPR, or (ii) when the D.C. Circuit Court will rule on our motion.

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As adopted in July 2011, the CSAPR requires our fossil-fueled generation units to (i) reduce their annual SO₂ and NO_x emissions by approximately 137,000 tons (64 percent) and 9,200 tons (22 percent), respectively, compared to 2010 actual levels, each beginning on January 1, 2012 and (ii) reduce their seasonal NOx emissions by approximately 3,400 tons (19 percent), compared to 2010 actual levels, beginning on May 1, 2012, which is the start of the ozone season.

The CSAPR establishes a “cap and trade” system as an additional compliance tool. The system includes three trading programs — one for annual SO₂ emissions and one each for seasonal and annual NO_x emissions — that allow for limited trading of allowances among sources covered by the programs. An allowance represents a ton of emissions of SO₂ or NO_x and sources are required to surrender to the EPA one allowance for every ton of emissions they emit in a given compliance period. The CSAPR allocates to each covered state (including Texas) a number of allowances for each of the three programs, and those allowances are then allocated among emission sources within the state. Generally speaking, to the extent a source’s emissions exceed the number of allowances it has been allocated, the source may buy additional allowances from other sources that it can surrender to the EPA in order to comply with the CSAPR. Sources included in the seasonal and annual NO_x programs are allowed to trade allowances with any other sources in those programs. The SO₂ trading program, however, divides States into Group 1 and Group 2, and permits sources to trade SO₂ allowances only with other sources in the same Group. Texas is in Group 2, which is composed of seven states. We believe that there might not be sufficient liquidity in the system for the purchase of allowances to constitute a significant element of our near-term strategy to comply with the CSAPR as originally adopted. Further, we believe that the state assurance levels contained in the current CSAPR (i.e., the level of emissions permitted in a state that, to the extent exceeded, must be offset with allowances on a three to one basis — one allowance for exceeding the applicable emissions limit and two allowances for exceeding the assurance level) could prevent using allowances to offset emissions above our generation fleet’s pro rata portion of the Texas assurance level as a viable near-term compliance strategy.

Due to the short timeframe for compliance with the emissions limitations contained in the CSAPR, the permitting, engineering, procurement and construction of new environmental control equipment to comply with the CSAPR will not be feasible to achieve compliance beginning on January 1, 2012.

In September 2011, we announced a compliance plan to satisfy the requirements of the final CSAPR issued in July 2011. Under our compliance plan, we would:

• idle Units 1 and 2 at our Monticello generation facility (approximately 1,200 MW);

• switch the fuel we use in Unit 3 at our Monticello generation facility (approximately 750 MW) and Units 1 and 2 at our Big Brown generation facility (approximately 1,200 MW) from a blend of Texas lignite and Powder River Basin coal to 100 percent Powder River Basin coal (in conjunction with the permitting, engineering, procurement and construction of a baghouse and installation of dry sorbent injection systems at Big Brown Units 1 and 2 and the permitting, engineering, procurement and construction of an upgraded scrubber at Monticello Unit 3);

• cease lignite mining operations at our Big Brown/Turlington, Winfield and Thermo mines that serve our Big Brown and Monticello generation facilities, and

• permit, engineer, procure, and construct upgraded scrubbers to reduce SO₂ emissions from Units 1, 2, and 3 at our Martin Lake generation facility and Unit 4 at our Sandow generation facility.

If the CSAPR is implemented in its current form on January 1, 2012, we expect the unit idling would occur immediately prior to January 1, 2012, the fuel switching and cessation of lignite mining operations would occur immediately prior to and during the first quarter of 2012, and the completion of the scrubber upgrades would occur by the end of 2012. These actions would reduce, in the near term, our total peak generation capacity by approximately 1,300 MW in the aggregate in order to comply with the current CSAPR emissions limitations (1,200 MW due to the unit idling and additional capacity reductions of approximately 100 MW due to the other actions of the compliance plan described above). We also intend to continue to seek to identify and pursue options that might allow us to restore levels of generation at the units affected by the actions described above.

We expect that the actions described in the four bullets above would result in material capital expenditures. Capital expenditures by the end of 2012 related to these actions are expected to be approximately $260 million (in addition to the $75 million of environmental capital expenditures related to our generation units planned for 2011, as previously disclosed in our 2010 Form 10-K). We estimate expenditures of more than $1.5 billion before the end of the decade in environmental control equipment would be required to comply with regulatory requirements, including the CSAPR as originally adopted. We also expect these actions would result in revenue decreases, due to lower wholesale power sales volumes caused by the reduced generation, as well as increased fuel costs. In connection with these actions, we expect the effect of reduced generation combined with increased fuel costs associated with the transition from a blend of lignite and Powder River Basin coal to 100 percent Powder River Basin coal at our Big Brown and Monticello generation facilities, among other things, would result in approximately $260 million of lower Adjusted EBITDA (as defined in the restricted payments covenant in the EFH Corp. Senior Secured Notes indentures) in the year ended December 31, 2012 (based on ERCOT North Hub 7x24 power prices as of March 31, 2011). We estimate that approximately 65 percent of the 2012 Adjusted EBITDA impact would be associated with the increased fuel costs, with the remainder due to lower generation. Cash impacts associated with fuel switching in 2012 would be expected to be partially mitigated by approximately $100 million of lower capital expenditures at the affected lignite mining and plant locations. In addition, if the CSAPR as originally adopted is implemented on January 1, 2012, we estimate that approximately 500 jobs at our generation and mining facilities would ultimately be eliminated in connection with these actions. See Note 3 to Financial Statements for discussion of emissions allowances impairments and other impairments, accelerated mining asset depreciation and severance charges recorded in the third quarter 2011 as a result of the CSAPR.

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The implementation and timing of our compliance plan may change upon a reconsideration or stay of the CSAPR by the EPA, a stay of the CSAPR by the D.C. Circuit Court, or revisions to the CSAPR.

Proposed Revisions to the Cross-State Air Pollution Rule — On October 6, 2011, the EPA released proposed revisions to the CSAPR (the Proposed Revisions), including revisions to the SO₂ and NO_x emissions limits for Texas sources. If adopted as a final rule, the Proposed Revisions would require our fossil-fueled generation units to reduce (i) their annual SO₂ and NO_x emissions by approximately 112,000 tons (52 percent) and 8,000 tons (19 percent), respectively, compared to 2010 actual levels, each beginning on January 1, 2012, and (ii) their seasonal NO_x emissions by approximately 2,700 tons (15 percent), compared to 2010 actual levels, beginning on May 1, 2012. The CSAPR’s emissions limitations as modified by the Proposed Revisions would be less onerous than the emissions limitations set forth in the CSAPR as issued in July 2011. In the Proposed Revisions, the EPA did not propose to revise the January 1, 2012 timeframe for beginning compliance with the emissions limitations contained in the CSAPR.

The EPA is scheduled to hold a public hearing to discuss the Proposed Revisions on October 28, 2011, and the Proposed Revisions are subject to public comment until November 28, 2011. We cannot predict whether, when, or in what form the Proposed Revisions will be adopted as a final rule. It is possible that any revisions to the CSAPR finally adopted could be different than the Proposed Revisions.

If the Proposed Revisions are adopted as a final rule, we expect that some of the actions described in our compliance plan above may no longer be required, and the costs of compliance with the CSAPR and the related adverse effects on our operations, liquidity and financial results may be reduced. Pending adoption of any revisions to the CSAPR and the other EPA actions described below in “Other EPA Actions,” we are continuing to evaluate the CSAPR, the Proposed Revisions, alternatives for compliance, and the expected effects on our operations, liquidity, and financial results.

Unless specifically noted otherwise, disclosures in this quarterly report on Form 10-Q, including the discussion of “Natural Gas Prices and Long-Term Hedging Program” above and discussion of “Liquidity and Capital Resources” below, include the anticipated effects of the CSAPR as issued in July 2011, but do not include any effects of the Proposed Revisions.

Other EPA Actions — In 2005, the EPA published a final rule requiring reductions of mercury emissions from lignite/coal-fueled generation plants. The Clean Air Mercury Rule (CAMR) was based on a nationwide cap and trade approach. The mercury reductions were required to be phased in between 2010 and 2018. In March 2008, the US Court of Appeals for the D.C. Circuit (the D.C. Circuit Court) vacated CAMR. In February 2009, the US Supreme Court refused to hear the appeal of the D.C. Circuit Court’s ruling. The EPA agreed in a consent decree submitted for court approval to propose Maximum Achievable Control Technology (MACT) rules by March 2011 and finalize those rules by November 2011, as subsequently postponed to December 2011. In March 2011, the EPA issued for comment a proposed rule for coal and oil-fueled electric generation units (Utility MACT). Once finalized, this rule could require substantial control equipment retrofits on our lignite/coal-fueled generation units within three to four years of the effective date of the rule, which as previously disclosed could require material capital expenditures. We cannot predict the substance of the final Utility MACT rule, or its impact on our facilities, financial condition, liquidity or results of operations.

Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits for these activities from the TCEQ for our present operations. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were published by the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuit brought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it was suspending the regulations pending further rulemaking. The US Supreme Court issued a decision in April 2009 reversing the federal court’s decision, in part, and finding that the EPA permissibly used cost-benefit analysis in the Section 316(b) regulations. In the absence of regulations, the EPA has instructed the states implementing the Section 316(b) program to use their best professional judgment in reviewing applications and issuing permits under Section 316(b). In April 2010, the EPA entered into a settlement agreement that requires it to propose new rules under Section 316(b) by March 2011 and to finalize those rules by July 2012. In March 2011, the EPA issued for comment the proposed regulations. Although the proposed rule does not mandate a certain control technology, it does require site-specific assessments of technology feasibility on a case-by-case basis at the state level. Compliance with this rule would be required beginning eight years following promulgation. We cannot predict the substance of the final regulations or the impact they may have on our financial condition, liquidity or results of operations.

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RESULTS OF OPERATIONS

Sales Volume and Customer Count Data

	Three Months  Ended September 30,						% Change			Nine Months  Ended September 30,						% Change
	2011			2010						2011			2010
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential		9,586			9,473			1.2			22,362			23,040			(2.9	)
Small business (a)		2,116			2,417			(12.5	)		5,688			6,392			(11.0	)
Large business and other customers		3,445			4,294			(19.8	)		9,955			11,738			(15.2	)
Total retail electricity		15,147			16,184			(6.4	)		38,005			41,170			(7.7	)
Wholesale electricity sales volumes (b)		7,336			14,313			(48.7	)		24,961			37,931			(34.2	)
Total sales volumes		22,483			30,497			(26.3	)		62,966			79,101			(20.4	)
Average volume (kWh) per residential customer (c)		5,698			5,220			9.2			13,044			12,584			3.7
Weather (North Texas average) – percent of normal (d):
Cooling degree days		129.2	%		107.1	%		20.6			134.2	%		109.9	%		22.1
Heating degree days		–			–			–			110.5	%		132.1	%		(16.4	)
Customer counts:
Retail electricity customers (end of period and in thousands) (e):
Residential											1,658			1,800			(7.9	)
Small business (a)											190			228			(16.7	)
Large business and other customers											20			22			(9.1	)
Total retail electricity customers											1,868			2,050			(8.9	)

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

(b) Includes net amounts related to sales and purchases of balancing energy in the “real-time market.”

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

(d) 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.

(e) 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,				% Change			Nine Months  Ended September 30,					% Change
	2011		2010					2011			2010
Operating revenues:
Retail electricity revenues:
Residential	$	1,185	$	1,231		(3.7	)	$	2,759		$	3,007		(8.2	)
Small business (a)		264		309		(14.6	)		719			839		(14.3	)
Large business and other customers		277		340		(18.5	)		781			931		(16.1	)
Total retail electricity revenues		1,726		1,880		(8.2	)		4,259			4,777		(10.8	)
Wholesale electricity revenues (b) (c)		513		636		(19.3	)		1,193			1,589		(24.9	)
Amortization of intangibles (d)		11		14		(21.4	)		16			16		–
Other operating revenues		71		77		(7.8	)		204			217		(6.0	)
Total operating revenues	$	2,321	$	2,607		(11.0	)	$	5,672		$	6,599		(14.0	)
Net gain from commodity hedging and trading activities:
Realized net gains on settled positions	$	135	$	251		(46.2	)	$	625		$	715		(12.6	)
Unrealized net gains (losses)		135		741		(81.8	)		(260	)		1,557		–
Total	$	270	$	992		(72.8	)	$	365		$	2,272		(83.9	)

(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 we deem “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,
	2011		2010			2011		2010
Reported in revenues	$	1	$	42		$	1	$	10
Reported in fuel and purchased power costs		2		(16	)		12		48
Net gains	$	3	$	26		$	13	$	58

(c) Includes net amounts related to sales and purchases of balancing energy in the “real-time market.”

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

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Production, Purchased Power and Delivery Cost Data

	Three Months  Ended September 30,						% Change			Nine Months  Ended September 30,						% Change
	2011			2010						2011			2010
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	40		$	43			(7.0	)	$	119		$	116			2.6
Lignite/coal		283			246			15.0			771			678			13.7
Total nuclear and lignite/coal		323			289			11.8			890			794			12.1
Natural gas fuel and purchased power (a)		147			580			(74.7	)		361			1,294			(72.1	)
Amortization of intangibles (b)		42			45			(6.7	)		110			125			(12.0	)
Other costs		107			46			–			255			152			67.8
Fuel and purchased power costs		619			960			(35.5	)		1,616			2,365			(31.7	)
Delivery fees		439			440			(0.2	)		1,110			1,156			(4.0	)
Total	$	1,058		$	1,400			(24.4	)	$	2,726		$	3,521			(22.6	)
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
Nuclear fuel	$	8.14		$	8.13			0.1		$	8.14		$	7.84			3.8
Lignite/coal (c)		19.86			18.24			8.9			19.83			19.18			3.4
Natural gas fuel and purchased power (d)		62.60			49.37			26.8			54.07			45.29			19.4
Delivery fees per MWh	$	28.91		$	27.13			6.6		$	29.13		$	28.01			4.0
Production and purchased power volumes (GWh):
Nuclear		4,956			5,302			(6.5	)		14,546			14,841			(2.0	)
Lignite/coal		16,473			15,445			6.7			45,096			40,743			10.7
Total nuclear- and lignite/coal-fueled generation		21,429			20,747			3.3			59,642			55,584			7.3
Natural gas-fueled generation		737			763			(3.4	)		1,133			1,598			(29.1	)
Purchased power (e)		317			8,987			(96.5	)		2,191			21,919			(90.0	)
Total energy supply volumes		22,483			30,497			(26.3	)		62,966			79,101			(20.4	)
Capacity factors:
Nuclear		97.6	%		104.4	%		(6.5	)		96.5	%		98.5	%		(2.0	)
Lignite/coal		93.1	%		89.7	%		3.8			86.8	%		82.0	%		5.9
Total		94.1	%		93.2	%		1.0			89.0	%		86.0	%		3.5

(a) See note (b) on previous page.

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

(c) Includes 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) Excludes volumes related to line loss and power imbalances.

(e) Includes amounts related to line loss and power imbalances.

As discussed above under “Significant Activities and Events,” the nodal wholesale market design implemented by ERCOT in December 2010 resulted in operational changes that facilitate hedging and trading of power. As part of ERCOT’s transition to a nodal wholesale market, volumes under nontrading bilateral purchase and sales contracts are no longer scheduled as physical power with ERCOT. As a result of these changes in market operations, reported wholesale revenues and purchased power costs in 2011 will be materially less than amounts reported in prior periods. Effective with the nodal market implementation, if volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues. Conversely, if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record additional purchased power costs. The resulting additional wholesale revenues or purchased power costs are offset in net gain from commodity hedging and trading activities.

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Financial Results — Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Operating revenues decreased $286 million, or 11%, to $2.321 billion in 2011.

Retail electricity revenues decreased $154 million, or 8%, to $1.726 billion and reflected the following:

• A 6% decrease in sales volumes decreased revenues by $121 million and was driven by declines in both the large and small business markets. Business volumes decreased 17% reflecting reduced contract signings driven by competitive activity. Residential volumes increased 1% reflecting 9% higher average consumption driven by warmer weather largely offset by an 8% decline in customer count driven by competitive activity.

• Lower average pricing decreased revenues by $33 million reflecting declining prices in both the residential and small business markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

Wholesale electricity revenues decreased $123 million, or 19%, to $513 million in 2011. The decrease reflects the nodal market change described above, partially offset by higher production from the new lignite-fueled generation units. The change in wholesale revenues also reflected $41 million in lower unrealized gains related to physical derivative sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

Fuel, purchased power costs and delivery fees decreased $342 million, or 24%, to $1.058 billion in 2011. Purchased power costs decreased $403 million driven by the effect of the nodal market described above. The decrease also reflects $18 million related to unrealized amounts associated with physical derivative commodity purchase contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above. These decreases were partially offset by $37 million in higher lignite/coal costs reflecting higher prices for purchased coal and increased generation.

A 7% increase in lignite/coal-fueled production was driven by the newly constructed generation facilities, while nuclear-fueled production decreased 7% due to an unplanned outage.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities, which totaled $270 million and $992 million in net gains for the three months ended September 30, 2011 and 2010, respectively:

	Three Months Ended September 30, 2011
	Net  Realized Gains		Net  Unrealized Gains		Total
Hedging positions	$	100	$	124	$	224
Trading positions		35		11		46
Total	$	135	$	135	$	270

	Three Months Ended September 30, 2010
	Net Realized Gains		Net Unrealized Gains (Losses)			Total
Hedging positions	$	235	$	750		$	985
Trading positions		16		(9	)		7
Total	$	251	$	741		$	992

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 $3 million and $26 million in net gains in 2011 and 2010, respectively (as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above).

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Operating costs increased $10 million, or 5%, to $207 million in 2011. The increase reflected $6 million in higher nuclear maintenance costs driven by a planned refueling outage in October 2011 and $5 million in higher maintenance expenses at legacy lignite/coal-fueled units reflecting projects to comply with the CSAPR effective January 1, 2012.

Depreciation and amortization increased $26 million, or 8%, to $371 million in 2011. The increase reflected $22 million of accelerated depreciation in 2011 resulting from the revised estimated useful lives for mine assets due to the planned mine closures needed to comply with the CSAPR effective January 1, 2012 (see Note 3 to Financial Statements) and $4 million in increased depreciation primarily for lignite/coal-fueled generation facilities resulting from additions and replacements.

SG&A expenses increased $9 million, or 5%, to $192 million in 2011. The increase reflected $16 million in higher employee-related expense and $6 million higher information technology and other services costs, partially offset by a $13 million reduction in retail bad debt expense reflecting improved collection initiatives and customer mix.

In 2010, a $4.1 billion impairment of goodwill was recorded as discussed in Note 4 to Financial Statements.

Other income totaled $4 million in 2011 and $6 million in 2010. See Note 14 to Financial Statements.

Other deductions totaled $478 million in 2011 and $3 million in 2010. Other deductions in 2011 included a $418 million impairment charge for excess SO₂ emissions allowances due to emissions allowance limitations under the CSAPR. Additionally, issuance of the new rule resulted in $49 million in employee severance charges associated with the idling of two generation units and the cessation of certain mining operations and a $9 million impairment of mining assets. See Notes 3 and 14 to Financial Statements.

Interest expense and related charges increased $489 million, or 54%, to $1.394 billion in 2011 reflecting a $438 million increase in unrealized mark-to-market net losses related to interest rate swaps, $48 million driven by higher average rates reflecting debt exchanges and amendments and $17 million in higher amortization of debt issuance and amendment costs and discounts, partially offset by $14 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting.

Income tax benefit totaled $382 million on a pretax loss in 2011 compared to income tax expense totaling $191 million on a pretax gain in 2010 before the $4.1 billion nondeductible goodwill impairment charge. The effective rate was 34.5% and 33.5% in 2011 and 2010, respectively, excluding the goodwill impairment charge. The increase in the effective rate was driven by the reversal in 2010 of interest accrued on uncertain tax positions.

After-tax loss declined $2.996 billion to $724 million in 2011 reflecting the $4.1 billion goodwill impairment charge in 2010, partially offset by lower gains from commodity hedging and trading activities, higher interest expense driven by unrealized mark-to-market net losses related to interest rate swaps and charges and expenses resulting from the issuance of the CSAPR.

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Financial Results — Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Operating revenues decreased $927 million, or 14%, to $5.672 billion in 2011.

Retail electricity revenues decreased $518 million, or 11%, to $4.259 billion and reflected the following:

• An 8% decrease in sales volumes decreased revenues by $367 million and was driven by declines in the large and small business and residential markets. Business volumes decreased 14% reflecting reduced contract signings driven by competitive activity. Residential volumes decreased 3% reflecting an 8% decline in customer count driven by competitive activity, partially offset by a 4% increase in average consumption driven by warmer weather.

• Lower average pricing decreased revenues by $151 million reflecting declining prices in the residential and large and small business markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

Wholesale electricity revenues decreased $396 million, or 25%, to $1.193 billion in 2011. The decrease is primarily attributable to the nodal market change described above, partially offset by higher production from the new lignite-fueled generation units.

Fuel, purchased power costs and delivery fees decreased $795 million, or 23%, to $2.726 billion in 2011. Purchased power costs decreased $933 million driven by the effect of the nodal market described above. Delivery fees declined $46 million reflecting lower retail volumes. These decreases were partially offset by $93 million in higher coal/lignite costs driven by higher prices for purchased coal and increased generation and $36 million in lower unrealized gains related to physical derivative commodity purchase contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

An 11% increase in lignite/coal-fueled production was driven by increased production from the newly constructed generation facilities, while nuclear-fueled production decreased 2% due to unplanned outages in 2011.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities, which totaled $365 million and $2.272 billion in net gains for the nine months ended September 30, 2011 and 2010, respectively:

	Nine Months Ended September 30, 2011
	Net Realized Gains		Net Unrealized Gains (Losses)			Total
Hedging positions	$	567	$	(276	)	$	291
Trading positions		58		16			74
Total	$	625	$	(260	)	$	365

	Nine Months Ended September 30, 2010
	Net Realized Gains		Net Unrealized Gains (Losses)			Total
Hedging positions	$	666	$	1,564		$	2,230
Trading positions		49		(7	)		42
Total	$	715	$	1,557		$	2,272

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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 $13 million and $58 million in net gains in 2011 and 2010, respectively (as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above).

Operating costs increased $47 million, or 8%, to $670 million in 2011. The increase reflected $25 million in higher nuclear maintenance costs reflecting an increase in scope and two planned refueling outages in 2011 as compared to one planned refueling outage in 2010, $17 million in incremental expense related to new generation units and $10 million in implementation costs for new technology systems and process improvements for generation facilities, partially offset by $9 million in lower maintenance costs at natural gas-fueled facilities reflecting the retirement of nine units in 2010.

Depreciation and amortization increased $70 million, or 7%, to $1.097 billion in 2011. The increase reflected $30 million in increased depreciation primarily for lignite/coal-fueled generation facilities resulting from additions and replacements, $30 million in incremental depreciation from a new generation unit placed in service in May 2010 and $22 million of accelerated depreciation in 2011 resulting from the revised estimated useful lives for mine assets due to the planned mine closures needed to comply with the CSAPR effective January 1, 2012 (see Note 3 to Financial Statements). These increases were partially offset by decreased amortization of intangible assets (see Note 4 to Financial Statements).

SG&A expenses decreased $17 million, or 3%, to $529 million in 2011. The decrease was driven by $46 million in lower retail bad debt expense reflecting improved collection initiatives and customer mix, partially offset by $21 million in higher employee-related expense and $6 million in higher information technology and other services costs.

In 2010, a $4.1 billion impairment of goodwill was recorded as discussed in Note 4 to Financial Statements.

Other income totaled $43 million in 2011 and $95 million in 2010. Other income in 2011 included $21 million related to the settlement of bankruptcy claims against a counterparty, $7 million for a property damage claim and $6 million from a franchise tax refund related to prior years. Other income in 2010 included a $44 million gain on the sale of land and related water rights, a $37 million gain associated with the sale of interests in a natural gas gathering pipeline business, $6 million in insurance/litigation settlements and a $5 million refund of sales taxes related to prior years. See Note 14 to Financial Statements.

Other deductions totaled $568 million in 2011 and $12 million in 2010. Other deductions in 2011 resulting from the issuance of the CSAPR included a $418 million impairment charge for excess SO₂ emissions allowances due to emissions allowance limitations under the CSAPR, $49 million in employee severance charges associated with the idling of two generation units and the cessation of certain mining operations and a $9 million impairment of mining assets. Other deductions in 2011 also included $86 million in third party fees related to the amendment and extension of the TCEH Senior Secured Facilities. See Notes 3, 6 and 14 to Financial Statements.

Interest expense and related charges increased $373 million, or 14%, to $3.091 billion in 2011 reflecting a $337 million increase in unrealized mark-to-market net losses related to interest rate swaps, $41 million in higher amortization of debt issuance and amendment costs and discounts, $29 million in lower capitalized interest and $16 million driven by higher average rates reflecting debt exchanges and amendments, partially offset by $50 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting.

Income tax benefit totaled $894 million on a pretax loss in 2011 compared to income tax expense totaling $188 million on a pretax gain in 2010 before the $4.1 billion nondeductible goodwill impairment charge. The effective rate was 34.4% and 36.8% in 2011 and 2010, respectively, excluding the goodwill impairment charge. The decrease in the rate was driven by the effect of mark-to-market losses on hedging and derivative transactions on a pretax loss in 2011 compared to mark-to-market gains on pretax income in 2010, partially offset by the reversal in 2010 of interest accrued on uncertain tax positions.

After-tax loss declined $2.071 billion in 2011 reflecting the $4.1 billion goodwill impairment charge in 2010, partially offset in 2011 by lower gains from commodity hedging and trading activities, higher interest expense driven by unrealized mark-to-market net losses related to interest rate swaps and charges and expenses resulting from the issuance of the CSAPR.

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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, 2011 and 2010. The net change in these assets and liabilities, excluding “other activity” as described below, represents $247 million in unrealized net losses in 2011 and $1.613 billion in unrealized net gains in 2010 arising from mark-to-market accounting for positions in the commodity contract portfolio. The portfolio consists primarily of economic hedges but also includes trading positions.

	Nine Months Ended September 30,
	2011			2010
Commodity contract net asset as of beginning of period	$	3,097		$	1,718
Settlements of positions (a)		(741	)		(642	)
Changes in fair value of positions in the portfolio (b)		494			2,255
Other activity (c)		12			39
Commodity contract net asset as of end of period	$	2,862		$	3,370

(a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.

(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”). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.

(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.

Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values as of September 30, 2011, 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, 2011
Source of fair value	Less than 1  year			1-3 years			4-5 years		Excess of 5  years		Total
Prices actively quoted	$	(35	)	$	(12	)	$	–	$	–	$	(47	)
Prices provided by other external sources		1,487			1,327			105		–		2,919
Prices based on models		5			(15	)		–		–		(10	)
Total	$	1,457		$	1,300		$	105	$	–	$	2,862
Percentage of total fair value		51%			45%			4%		–%		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 hub) generally extend through 2013 and over-the-counter quotes for natural gas generally extend through 2016, depending upon delivery point. The “prices based on models” category contains the value of all non-exchange-traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 9 to Financial Statements for fair value disclosures and discussion of fair value measurements.

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FINANCIAL CONDITION

Liquidity and Capital Resources

Cash Flow — Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010 — Cash provided by operating activities increased $55 million to $1.049 billion in 2011. The increase reflected the effect of amended accounting standards related to the accounts receivable securitization program (see Note 5 to Financial Statements), under which the $383 million of funding under the program at the January 1, 2010 adoption was reported as a use of operating cash flows and a source of financing cash flows. Excluding this accounting effect, cash provided by operating activities declined $328 million, which reflected a low wholesale power price environment, the effects of a severe winter storm in February 2011, and higher cash interest payments, partially offset by the contribution from the new lignite-fueled generation units.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $194 million and $204 million for the nine months ended September 30, 2011 and 2010, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice, and amortization of intangible net assets 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.

Cash used in financing activities totaled $1.105 billion in 2011 and $59 million in 2010. Activity in 2011 reflected the amendment and extension of the TCEH Senior Secured Facilities as discussed in Note 6 to Financial Statements. Activity in 2010 reflected net repayment of borrowings, partially offset by a $383 million source of financing cash flows due to an accounting change related to the accounts receivable securitization program as discussed above. Activity in 2010 also reflected borrowings by TCEH from EFH Corp. under demand notes totaling $770 million from which the proceeds were used to repay borrowings under the TCEH Revolving Credit Facility.

See Note 6 to Financial Statements for further detail of short-term borrowings and long-term debt.

Cash provided by investing activities totaled $211 million in 2011 and cash used in investing activities totaled $958 million in 2010. Investing cash flows in 2011 reflected net repayments on notes receivable from affiliates totaling $527 million and investing cash flows in 2010 reflected net loans to affiliates totaling $282 million. Capital expenditures decreased $315 million to $361 million in 2011 reflecting a decrease in spending related to the construction of the new generation facilities.

Debt Financing Activity — Activities related to short-term borrowings and long-term debt during the nine months ended September 30, 2011 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

	Borrowings (a)		Repayments and Repurchases (b)
TCEH	$	1,829	$	(982	)
EFCH		–		(3	)
EFH Corp (pushed down to EFCH).		11		(195	)
Total long-term		1,840		(1,180	)
Total short-term – TCEH (c)		–		(1,125	)
Total	$	1,840	$	(2,305	)

(a) Includes $90 million of noncash principal increases consisting of $79 million of TCEH Toggle Notes and $11 million of EFH Toggle Notes in payment of accrued interest as discussed below under “Toggle Notes Interest Election.”

(b) Includes $195 million of noncash retirements as a result of EFH Corp. debt exchanged as discussed in Note 6 to Financial Statements.

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

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See Note 6 to Financial Statements for further detail of long-term debt and other financing arrangements, including $453 million of debt due currently (within 12 months) as of September 30, 2011.

We regularly monitor the capital and bank credit markets for liability management opportunities that we believe will improve our balance sheet, including capturing debt discount and extending debt maturities. As a result, we may engage, from time to time, in liability management transactions. Future activities under the liability management program may include the purchase of our outstanding debt for cash in open market purchases or privately negotiated refinancing and exchange transactions (including pursuant to a Section 10b-5(1) plan) or via public or private exchange or tender offers.

In evaluating whether to undertake any liability management transaction, including any refinancing, we will take into account liquidity requirements, prospects for future access to capital, contractual restrictions, the market price of our outstanding debt and other factors. Any liability management transaction, including any refinancing, may occur on a stand-alone basis or in connection with, or immediately following, other liability management transactions.

Available Liquidity — The following table summarizes changes in available liquidity since December 31, 2010.

	Available Liquidity
	September 30, 2011		December 31, 2010		Change
Cash and cash equivalents	$	202	$	47	$	155
TCEH Revolving Credit Facility (a)		2,054		1,440		614
TCEH Letter of Credit Facility		205		261		(56	)
Total liquidity (b)	$	2,461	$	1,748	$	713

(a) In connection with the April 2011 amendment and extension of the TCEH Senior Secured Facilities, this facility now has a limit of $2.054 billion, and there were no borrowings as of September 30, 2011. Lehman is no longer a participant in the facility.

(b) As of September 30, 2011 and December 31, 2010, total liquidity includes $742 million and $465 million, respectively, of net receipts of margin deposits from counterparties related to commodity positions (net of $59 million and $166 million, respectively, posted with counterparties).

Available liquidity increased $713 million since December 31, 2010 and $759 million since June 30, 2011, reflecting third quarter cash flows substantially used to repay borrowings under the TCEH Revolving Credit Facility and a $185 million reduction in letters of credit posted with counterparties.

See Note 6 to Financial Statements for discussion of transactions in April 2011 related to the TCEH Senior Secured Facilities that resulted in an amendment to the terms of the facilities, three-year extensions of $17.8 billion of maturities of borrowings/commitments, repayment of $1.6 billion of borrowings and the reduction of $646 million of revolving credit commitments.

Toggle Notes Interest Election — EFH Corp. and TCEH have the option every six months at their discretion, ending with the interest 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. 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.

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TCEH made its May 2011 interest payment and will make its November 2011 and May 2012 interest payments on the TCEH Toggle Notes by using the PIK feature of those notes. During the applicable interest periods, the interest rate on the notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by $79 million in May 2011 and is expected to further increase the aggregate principal amount of the notes by $84 million in November 2011. The election increased liquidity in May 2011 by an amount equal to $74 million and is expected to further increase liquidity in November 2011 by an amount equal to an estimated $78 million, constituting the amounts of cash interest that otherwise would have been payable on the notes.

Similarly, EFH Corp. made its May 2011 interest payment and will make its November 2011 and May 2012 interest payments 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 $21 million in May 2011 (excluding $151 million principal amount issued to EFIH as holder of $2.525 billion principal amount of EFH Corp. Toggle Notes) and is expected to further increase the aggregate principal amount of the notes by $22 million in November 2011 (excluding $161 million principal amount expected to be issued to EFIH). The election increased liquidity in May 2011 by an amount equal to $19 million (excluding $142 million related to notes held by EFIH) and is expected to further increase liquidity in November 2011 by an amount equal to a currently estimated $20 million (excluding $151 million related to notes held by EFIH), constituting the amounts of cash interest that otherwise would have been payable on the notes. See Note 6 to Financial Statements for discussion of debt exchange transactions in April 2011 that resulted in EFIH acquiring $428 million principal amount of EFH Corp. debt, including $229 million principal amount of EFH Corp. Toggle Notes that are reflected in the amounts related to the May and November 2011 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 (CCP facility), an uncapped senior secured revolving credit facility that matures in December 2012, 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 the CCP 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 CCP facility, as of September 30, 2011, more than 90% 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. Due to declines in forward natural gas prices, no amounts were borrowed against the CCP facility as of September 30, 2011 and December 31, 2010. See Note 6 to Financial Statements for more information about the TCEH Senior Secured Facilities, which include the CCP facility.

Exchange cleared 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. Cash collateral received from counterparties is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or 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, 2011, restricted cash collateral held totaled $84 million. See Note 14 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, 2011, approximately 250 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 CCP facility supports the collateral posting requirements related to the majority of these transactions.

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As of September 30, 2011, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $56 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $165 million posted as of December 31, 2010;

• $798 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 $630 million received, net of $1 million in cash posted, as of December 31, 2010;

• $355 million in letters of credit have been posted with counterparties, as compared to $473 million posted as of December 31, 2010, and

• $71 million in letters of credit have been received from counterparties, as compared to $25 million received as of December 31, 2010.

Income Tax Refunds/Payments — Income tax payments related to the Texas margin tax are expected to total approximately $35 million, and net payments of federal income taxes are expected to total approximately $75 million in the next 12 months. Net payments totaled $75 million in the nine months ended September 30, 2011. (See Note 13 to Financial Statements.)

We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions, but expect that no material federal income tax payments related to such positions will be made in the next 12 months. (See Note 14 to Financial Statements.)

Interest Rate Swap Transactions — See Note 6 to Financial Statements.

Accounts Receivable Securitization Program — TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). In accordance with 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 $211 million and $96 million as of September 30, 2011 and December 31, 2010, respectively. See Note 5 to Financial Statements for a more complete description of the program including the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of September 30, 2011, we were in compliance with all such covenants.

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

Adjusted EBITDA (as used in the maintenance covenant contained in the TCEH Senior Secured Facilities) for the twelve months ended September 30, 2011 totaled $3.741 billion for TCEH. See Exhibits 99(b) and 99(c) for a reconciliation of net loss to Adjusted EBITDA for TCEH and EFH Corp., respectively, for the nine and twelve months ended September 30, 2011 and 2010.

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The table below 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 threshold covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Notes, the TCEH Senior Secured Second Lien Notes, the EFH Corp. Senior Notes, and the EFH Corp. Senior Secured Notes as of September 30, 2011 and December 31, 2010. The debt incurrence and restricted payments/limitations on investments covenants thresholds described below represent levels that must be met in order for EFH Corp. or TCEH to incur certain permitted debt or make certain restricted payments and/or investments. EFCH and its consolidated subsidiaries are in compliance with their maintenance covenants.

	September 30, 2011	December 31, 2010	Threshold Level as of September  30, 2011
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to Adjusted EBITDA ratio (a)	5.34 to 1.00	5.19 to 1.00	Must not exceed 8.00 to 1.00 (b)
Debt Incurrence Covenants:
EFH Corp. Senior Secured Notes:
EFH Corp. fixed charge coverage ratio	1.1 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.3 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH Senior Notes, Senior Secured Notes and Senior Secured
Second Lien Notes:
TCEH fixed charge coverage ratio	1.3 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.4 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	9.4 to 1.0	8.5 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)	1.4 to 1.0	1.6 to 1.0	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (c)	1.1 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	9.4 to 1.0	8.5 to 1.0	Equal to or less than 7.0 to 1.0
TCEH Senior Notes, Senior Secured Notes and Senior Secured
Second Lien Notes:
TCEH fixed charge coverage ratio	1.3 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to Adjusted EBITDA ratio	8.3 to 1.0	7.9 to 1.0	Equal to or less than 6.5 to 1.0

(a) As of December 31, 2010, includes Adjusted EBITDA for the new Sandow 5 and Oak Grove 1 generation units and their proportional amount of outstanding debt under the Delayed Draw Term Loan. As of September 30, 2011, includes pro forma Adjusted EBITDA for the new Oak Grove 2 generation unit as well as Adjusted EBITDA for Sandow 5 and Oak Grove 1 units and all outstanding debt under the Delayed Draw Term Loan.

(b) Threshold level increased to a maximum of 8.00 to 1.00 for the test periods ending March 31, 2011 through December 31, 2014, effective with the April 2011 amendment to the TCEH Senior Secured Facilities discussed in Note 6 to Financial Statements. Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities and up to $1.5 billion ($906 million excluded as of September 30, 2011) principal amount of TCEH senior secured first lien notes whose proceeds are used to prepay term loans or deposit letter of credit loans under 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, 2011, counterparties to those contracts could have required TCEH to post up to an aggregate of $6 million in additional collateral. This amount largely represents the below market terms of these contracts as of September 30, 2011; 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, 2011, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $25 million, with $13 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of September 30, 2011, TCEH posted letters of credit in the amount of $76 million, which are subject to adjustments.

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 $700 million to $950 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 participate in the “day-ahead” and “real-time markets” operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $125 million as of September 30, 2011 (which is subject to weekly adjustments based on settlement activity with ERCOT). Such collateral decreased by $100 million in the third quarter 2011 due to reduced forward exposure.

Other arrangements of EFCH and its subsidiaries, including the accounts receivable securitization program (see Note 5 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

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

Material Cross Default/Acceleration Provisions — Certain of our 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” or “cross acceleration” 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 ($20.241 billion as of September 30, 2011) under such facilities.

The indentures governing the TCEH Senior Notes, TCEH Senior Secured 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, TCEH Senior Secured Notes and TCEH Senior Secured Second Lien Notes.

Under the terms of a TCEH rail car lease, which had $43 million in remaining lease payments as of September 30, 2011 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 another TCEH rail car lease, which had $48 million in remaining lease payments as of September 30, 2011 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 these cross default provisions were triggered, the program could be terminated.

We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.

Each of TCEH’s natural gas hedging agreements and interest rate swap 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 or 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.

Long-Term Contractual Obligations and Commitments — The following table summarizes our contractual cash obligations as of September 30, 2011 that have changed materially since December 31, 2010 because of the amendment and extension of the TCEH Senior Secured Facilities. (See Note 6 to Financial Statements for additional disclosures regarding the long-term debt obligations.)

Contractual Cash Obligations	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Long-term debt – principal (a)	$	422	$	110	$	7,593	$	22,745	$	30,870
Long-term debt – interest (b)		2,520		5,340		4,796		5,498		18,154

(a) Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting.

(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect as of September 30, 2011.

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

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OFF–BALANCE SHEET ARRANGEMENTS

See Notes 2 and 7 to Financial Statements regarding VIEs and guarantees, respectively.

COMMITMENTS AND CONTINGENCIES

See Note 7 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

There have been no recently issued accounting standards effective after September, 30 2011 that are expected to materially impact our financial statements.

REGULATORY MATTERS

See discussions in Note 7 to Financial Statements.

Sunset Review

PURA, the PUCT, the RRC, ERCOT, the TCEQ and the Texas Office of Public Utility Counsel (OPUC) were 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 (e.g. PURA). During the 2011 legislative session, the Texas Legislature extended the life of the PUCT and the RRC until 2013, at which time the PUCT will undergo a limited purpose sunset review and the RRC will undergo a full sunset review. The Texas Legislature also continued ERCOT until the subsequent PUCT sunset review and the OPUC and the TCEQ for 12 years.

Mine Safety Disclosures

We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our 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 ours, 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. Disclosure of MSHA citations, orders and proposed assessments required by Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act are provided in Exhibit 99(d) to this Quarterly Report on Form 10-Q.

Summary

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Risk Oversight

We manage 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 our businesses.

Commodity Price Risk

We are subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products we market or purchase. We actively manage the portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we 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, we enter 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. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive 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, 2011			Year Ended December 31,  2010
Month-end average Trading VaR:		$	3		$	3
Month-end high Trading VaR:		$	8		$	4
Month-end low Trading VaR:		$	1		$	1

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, 2011			Year Ended December 31,  2010
Month-end average MtM VaR:		$	208		$	426
Month-end high MtM VaR:		$	268		$	621
Month-end low MtM VaR:		$	147		$	321

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, 2011			Year Ended December 31,  2010
Month-end average EaR:		$	175		$	477
Month-end high EaR:		$	228		$	662
Month-end low EaR:		$	139		$	323

The decreases in the risk measures (MtM VaR and EaR) above primarily reflected a reduction of positions in the long-term hedging program due to maturities and lower volatility in commodity prices.

Interest Rate Risk

As of September 30, 2011, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $12 million, taking into account the interest rate swaps discussed in Note 6 to Financial Statements.

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Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.

Credit Exposure — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $2.063 billion as of September 30, 2011. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of September 30, 2011 include $733 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $72 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, 2011, the exposure to credit risk from these counterparties totaled $1.330 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $733 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $597 million decreased $1.009 billion in the nine months ended September 30, 2011, reflecting an increase in derivative liabilities related to interest rate swaps due to lower interest rates and a reduction of the asset position of the long-term hedging program driven by maturities.

Of this $597 million net exposure, essentially all is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.

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The following table presents the distribution of credit exposure as of September 30, 2011 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. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 11 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	$	1,316		$	732	$	584		$	1,184	$	163	$	(31	)	$	1,316
Noninvestment grade		14			1		13			11		3		—			14
Totals	$	1,330		$	733	$	597		$	1,195	$	166	$	(31	)	$	1,330
Investment grade		98.9	%				97.8	%
Noninvestment grade		1.1	%				2.2	%

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

Significant (10% or greater) concentration of credit exposure exists with two counterparties, each of which represented 36% of the $597 million net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.

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

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain “forward-looking statements.” All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses 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 we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under Item 1A, “Risk Factors” in this report and the 2010 Form 10-K and the discussion under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:

• prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the FERC, the NERC, the TRE, the PUCT, the RRC, the NRC, the EPA, the TCEQ and the CFTC, with respect to, among other things:

• allowed prices;

• industry, market and rate structure;

• purchased power and recovery of investments;

• operations of nuclear generation facilities;

• operations of fossil-fueled generation facilities;

• operations of mines;

• acquisition 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 the CSAPR and 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;

• our ability to attract and retain profitable customers;

• our ability to profitably serve our customers;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices;

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

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

• our ability to effectively hedge against unfavorable 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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• the willingness of our lenders to extend the maturities of our debt instruments and the terms and conditions of any such extensions;

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

• activity in the credit default swap market related to our debt instruments;

• financial restrictions placed on us by the agreements governing our debt instruments;

• our ability to generate sufficient cash flow to make interest payments on, or refinance, our debt instruments;

• our ability to successfully execute our liability management program;

• competition for new energy development and other business opportunities;

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

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

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

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

• changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, 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 we may not have adequate insurance to cover losses resulting from such hazards;

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• our ability to effectively execute our operational strategy, and

• our 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, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.

INDUSTRY AND MARKET INFORMATION

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

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Item 4.   CONTROLS AND PROCEDURES

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

PART II.   OTHER INFORMATION

Item 1.   LEGAL PROCEEDINGS

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

Item 1A.   RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, and Part II, “Item 1A. Risk Factors” in our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2011 and June 30, 2011 and the risks described below, which could materially affect our business, financial condition or future results. The risks described in such reports and below are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

Lenders and holders of our debt have in the past alleged and might allege in the future that we are not operating in compliance with covenants in our debt agreements. In addition, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the past claimed and might claim in the future that a credit event has occurred under such credit derivative securities. In each case, even if the claims have no merit, they could cause the trading price of our debt securities to decline and adversely affect our ability to raise additional capital and/or refinance our existing debt.

Lenders or holders of our debt have in the past alleged and might allege in the future that we are not operating in compliance with the covenants in our debt agreements or that a default under our debt agreements has occurred or make other allegations regarding our business, including for the purpose, and potentially having the effect, of causing a default under our debt or other agreements, accelerating the maturity of such debt, protecting claims of debt issued at a certain entity or entities in our or EFH Corp.’s capital structure at the expense of debt claims elsewhere in our or EFH Corp.’s capital structure and/or obtaining economic benefits from us. These claims have included and may include in the future, among other things, claims that certain intercompany loans from TCEH to EFH Corp. were in violation of the terms of our debt agreements or were fraudulent transfers. Further, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the past claimed and in the future may claim that a credit event has occurred under such credit derivative securities based on our financial condition. Even if all of these claims are without merit, such a claim could nevertheless cause the trading price of our debt to decline and adversely affect our ability to raise additional capital and/or refinance our existing debt.

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Our results of operations, liquidity and financial condition may be materially adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.

In recent years, a growing concern has emerged about global climate change and how greenhouse gas (GHG) emissions, such as carbon dioxide (CO2), contribute to global climate change. Several bills addressing climate change have been introduced in the US Congress or discussed by the Obama Administration that are intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), incentives for the development of low-carbon technology and federal renewable portfolio standards. In addition, a number of federal court cases have been filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies that produce GHG emissions.

The EPA has issued a rule, known as the Prevention of Significant Deterioration (PSD) tailoring rule, which establishes new thresholds for regulating GHG emissions from stationary sources under the Clean Air Act. The rule requires any source subject to the PSD permitting program due to emissions of non-GHG pollutants that increases its GHG emissions by 75,000 tons per year (tpy) to have an operating permit under the Title V Operating Permit Program of the Clean Air Act and install the best available control technology in conjunction with construction activities or plant modifications. PSD permitting requirements also apply to new projects with GHG emissions of at least 100,000 tpy and modifications to existing facilities that increase GHG emissions by at least 75,000 tpy (even if no non-GHG PSD thresholds are exceeded). The EPA has also issued regulations that require certain categories of GHG emitters (including our lignite/coal-fueled generation facilities) to monitor and report their annual GHG emissions.

The EPA also announced in late 2010 its intent to promulgate, in 2011, GHG emission limits known as New Source Performance Standards that would apply to new and modified sources, as well as GHG emission guidelines that states might apply to existing sources of GHGs. The EPA has indicated that such new standards and guidelines would be applicable to electricity generation facilities. We cannot predict what limits or guidelines the EPA might adopt. If limits or guidelines become applicable to our generation facilities and require us to install new control equipment or substantially alter our operations, it could have a material adverse effect on our results of operations, liquidity and financial condition.

We produce GHG emissions from the combustion of fossil fuels at our generation facilities. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our results of operations, liquidity and financial condition could be materially adversely affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with such a program. The EPA regulation of GHGs under the Clean Air Act, or judicially imposed sanctions or damage awards related to GHG emissions, may require us to make material expenditures to reduce our GHG emissions. In addition, a significant number of our customers or others refuse to do business with us because of our GHG emissions, it could have a material adverse effect on our results of operations, liquidity or financial condition.

Litigation related to environmental issues, including claims alleging that GHG emissions constitute a public nuisance by contributing to global climate change, has increased in recent years. Connecticut v. American Electric Power Company Inc., Comer v. Murphy Oil USA and Native Village of Kivalina v. ExxonMobil Corporation all involve nuisance claims for damages purportedly caused by the defendants’ emissions of GHGs. Although we are not currently a party to any pending lawsuits alleging that GHG emissions are a public nuisance, these lawsuits could establish precedent that might affect our business or our industry generally. Other similar lawsuits have involved claims of property damage, personal injury, challenges to issued permits and citizen enforcement of environmental laws and regulations. We cannot predict the ultimate outcome of the pending proceedings. If we are sued in these or similar proceedings and are ultimately subject to an adverse ruling, we could be required to make substantial capital expenditures for emissions control equipment, halt operations and/or pay substantial damages. Such expenditures or the cessation of operations could adversely affect our results of operations, liquidity and financial condition.

79

Our results of operations, liquidity and financial condition may be materially adversely affected by insufficient water supplies.

Assured supplies of water are important for our generation facilities. Water in Texas is limited and various parties have made conflicting claims regarding the right to access and use such limited supplies of water. In addition, Texas has been experiencing sustained, severe drought conditions that may affect the water supply for certain of our generation facilities if adequate rain does not fall in the watershed that supplies the affected areas. If we are unable to access sufficient supplies of water, it could restrict, prevent, or increase the cost of, operations at certain of our generation facilities.

80

Item 6. Exhibits

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

Exhibits	Previously Filed With File Number*	As Exhibit
(3)	Articles of Incorporation and By-laws.
3(a)	333-153529 Form S-4 (filed September 17, 2008)	3(b)	—	Second Amended and Restated Articles of Incorporation of Energy Future Competitive Holdings Company (formerly known as TXU US Holdings Company)
3(b)	333-153529 Form S-4 (filed September 17, 2008)	3(e)	—	Restated Bylaws of Energy Future Competitive Holdings Company (formerly known as TXU US Holdings Company)
(4)	Instruments Defining the Rights of Security Holders, Including Indentures.
4(a)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	4(a)	—	Third Supplemental Indenture, dated as of September 26, 2011, to Indenture, dated as of October 6, 2010, relating to 15% Senior Secured Second Lien Notes due 2021 of Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc.
(10)	Material Contracts.
10(a)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(c)	—	Amended and Restated Employment Agreement, dated October 17, 2011, among Luminant Holding Company LLC, Energy Future Holdings Corp., and David A. Campbell.
10(b)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(d)	—	Amended and Restated Employment Agreement, dated October 17, 2011, among TXU Energy Retail Company LLC, Energy Future Holdings Corp., and James A. Burke.
10(c)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(e)	—	Amended and Restated Employment Agreement, dated October 17, 2011, among Luminant Holding Company LLC, Energy Future Holdings Corp., and Mark Allen McFarland.
(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.

81

Exhibits	Previously Filed With File Number*	As Exhibit
(32)	Section 1350 Certifications.
32(a)			—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Company, 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, 2011.
99(b)			—	Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2011 and 2010.
99(c)			—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2011 and 2010.
99(d)			—	Mine Safety Disclosures
	XBRL Data Files
101.INS			—	XBRL Instance Document
101.SCH			—	XBRL Taxonomy Extension Schema Document
101.CAL			—	XBRL Taxonomy Extension Calculation Document
101.DEF			—	XBRL Taxonomy Extension Definition Document
101.LAB			—	XBRL Taxonomy Extension Labels Document
101.PRE			—	XBRL Taxonomy Extension Presentation Document

* Incorporated herein by reference.

82

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 27, 2011

83

Exhibit 31(a)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 302

of Sarbanes – Oxley Act of 2002

I, John F. Young, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy Future Competitive Holdings Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2011		/s/ JOHN F. YOUNG
	Name:	John F. Young
	Title:	Chair, President and Chief Executive

Exhibit 31(b)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 302

of Sarbanes – Oxley Act of 2002

I, Paul M. Keglevic, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy Future Competitive Holdings Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2011		/s/ PAUL M. KEGLEVIC
	Name:	Paul M. Keglevic
	Title:	Executive Vice President and Chief Financial Officer

Exhibit 32(a)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 906

of Sarbanes – Oxley Act of 2002

CERTIFICATION OF CEO

The undersigned, John F. Young, Chair, President and Chief Executive of Energy Future Competitive Holdings Company (the “Company”), DOES HEREBY CERTIFY that, to his knowledge:

1. The Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2011 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 27th day of October, 2011.

	/s/ JOHN F. YOUNG
Name:	John F. Young
Title:	Chair, President and Chief Executive

A signed original of this written statement required by Section 906 has been provided to Energy Future Competitive Holdings Company and will be retained by Energy Future Competitive Holdings Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 906

of Sarbanes – Oxley Act of 2002

CERTIFICATION OF CFO

The undersigned, Paul M. Keglevic, Executive Vice President and Chief Financial Officer of Energy Future Competitive Holdings Company (the “Company”), DOES HEREBY CERTIFY that, to his knowledge:

1. The Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2011 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 27th day of October, 2011.

	/s/ PAUL M. KEGLEVIC
Name:	Paul M. Keglevic
Title:	Executive Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Energy Future Competitive Holdings Company and will be retained by Energy Future Competitive Holdings Company and furnished to the Securities and Exchange Commission or its staff upon request.

EXHIBIT 99(a)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

	Twelve Months  Ended September 30, 2011
	(millions of dollars)
Operating revenues	$	7,308
Fuel, purchased power costs and delivery fees		(3,576	)
Net gain from commodity hedging and trading activities		254
Operating costs		(884	)
Depreciation and amortization		(1,450	)
Selling, general and administrative expenses		(705	)
Franchise and revenue-based taxes		(98	)
Impairment of goodwill		–
Other income		851
Other deductions		(574	)
Interest income		91
Interest expense and related charges		(3,440	)
Loss before income taxes		(2,223	)
Income tax benefit		764
Net loss	$	(1,459	)

Exhibit 99(b)

Texas Competitive Electric Holdings Company LLC Consolidated

Adjusted EBITDA Reconciliation

	Nine Months Ended September 30, 2011			Nine Months Ended September 30, 2010			Twelve Months Ended September 30, 2011			Twelve Months Ended September 30, 2010
	(millions of dollars)
Net loss	$	(1,660	)	$	(3,646	)	$	(1,397	)	$	(3,430	)
Income tax expense (benefit)		(874	)		260			(732	)		377
Interest expense and related charges		3,020			2,516			3,344			3,019
Depreciation and amortization		1,097			1,027			1,450			1,337
EBITDA	$	1,583		$	157		$	2,665		$	1,303
Interest income		(66	)		(65	)		(92	)		(89	)
Amortization of nuclear fuel		104			102			142			130
Purchase accounting adjustments (a)		147			124			186			194
Impairment of goodwill		—			4,100			—			4,100
Impairment of assets and inventory write down (b)		427			1			439			35
Net gain on debt exchange offers		—			—			(687	)		—
Unrealized net (gain) loss resulting from hedging transactions		247			(1,615	)		641			(2,127	)
EBITDA amount attributable to consolidated unrestricted subsidiaries		(5	)		—			(5	)		1
Amortization of “day one” net loss on Sandow 5 power purchase agreement		—			(19	)		(2	)		(22	)
Corporate depreciation, interest and income tax expenses included in SG&A expense		11			9			11			9
Losses on sale of receivables		—			—			—			3
Noncash compensation expense (c)		8			11			11			11
Severance expense		52			3			52			4
Transition and business optimization costs (d)		33			2			40			5
Transaction and merger expenses (e)		28			29			37			30
Restructuring and other (f)		70			1			(51	)		(1	)
Expenses incurred to upgrade or expand a generation station (g)		100			100			100			100
Adjusted EBITDA per Incurrence Covenant	$	2,739		$	2,940		$	3,487		$	3,686
Expenses related to unplanned generation station outages		162			122			172			152
Pro forma adjustment for Sandow 5 and Oak Grove 1 reaching 70% capacity in Q1 2010 (h)		—			—			—			42
Pro forma adjustment for Oak Grove 2 reaching 70% capacity in Q2 2011 (h)		32			—			64			—
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (i)		8			19			18			36
Adjusted EBITDA per Maintenance Covenant	$	2,941		$	3,081		$	3,741		$	3,916

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

(b) Impairment of assets includes impairment of emission allowances and certain assets relating to mining operations due to EPA rule and impairment of land.

(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and exclude capitalized amounts.

(d) Transition and business optimization costs include certain incentive compensation expenses, system development professional fees related to major generation operations and retail billing/customer care computer applications and costs relating to certain growth initiatives.

(e) Transaction and merger expenses include costs relating to the Merger and the Sponsor Group management fee.

(f) Restructuring and other includes net third-party fees paid in connection with the amendment and extension of the TCEH Senior Secured Facilities, gains on termination of a long-term power sales contract and settlement of amounts due from a hedging/trading counterparty, and reversal of certain liabilities accrued in purchase accounting.

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

(h) Pro forma adjustment for the nine and twelve months ended September 30, 2011 represents the annualization of the actual six months ended September 30, 2011 EBITDA results for Oak Grove 2, which achieved the requisite 70% average capacity factor in the second quarter 2011. Pro forma adjustment for the twelve months ended September 30, 2010 represents the annualization of the actual nine months ended September 30, 2010 EBITDA results for Sandow 5 and Oak Grove 1, which achieved the requisite 70% average capacity factor in the first quarter 2010.

(i) Primarily pre-operating expenses relating to Oak Grove and Sandow 5.

Exhibit 99(c)

Energy Future Holdings Corp. Consolidated

Adjusted EBITDA Reconciliation

	Nine Months Ended September 30, 2011			Nine Months Ended September 30, 2010			Twelve Months Ended September 30, 2011			Twelve Months Ended September 30, 2010
	(millions of dollars)
Net loss attributable to EFH Corp.	$	(1,776	)	$	(2,973	)	$	(1,615	)	$	(2,836	)
Income tax expense (benefit)		(1,042	)		336			(989	)		449
Interest expense and related charges		3,467			3,092			3,929			3,868
Depreciation and amortization		1,119			1,043			1,483			1,511
EBITDA	$	1,768		$	1,498		$	2,808		$	2,992
Oncor EBITDA		—			—			—			(311	)
Oncor Holdings distributions		64			141			91			239
Interest income		(2	)		(9	)		(3	)		(24	)
Amortization of nuclear fuel		104			102			142			130
Purchase accounting adjustments (a)		182			159			233			241
Impairment of goodwill		—			4,100			—			4,100
Impairment of assets and inventory write down (b)		429			3			441			40
Net gain on debt exchange offers		(25	)		(1,166	)		(673	)		(1,253	)
Net income attributable to noncontrolling interests		—			—			—			9
Equity in earnings of unconsolidated subsidiary		(235	)		(240	)		(272	)		(240	)
EBITDA amount attributable to consolidated unrestricted subsidiaries		—			—			—			1
Unrealized net (gain) loss resulting from hedging transactions		247			(1,615	)		641			(2,127	)
Amortization of “day one” net loss on Sandow 5 power purchase agreement		—			(19	)		(2	)		(22	)
Losses on sale of receivables		—			—			—			3
Noncash compensation expenses (c)		8			13			13			15
Severance expense		54			3			54			4
Transition and business optimization costs (d)		30			(2	)		36			1
Transaction and merger expenses (e)		27			37			38			53
Restructuring and other (f)		74			(1	)		(41	)		(4	)
Expenses incurred to upgrade or expand a generation station (g)		100			100			100			100
Adjusted EBITDA per Incurrence Covenant	$	2,825		$	3,104		$	3,606		$	3,947
Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)		1,206			1,053			1,508			1,248
Adjusted EBITDA per Restricted Payments Covenant	$	4,031		$	4,157		$	5,114		$	5,195

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

(b) Impairment of assets includes impairments of emission allowances and certain assets relating to mining operations due to EPA rule, impairment of land and charges relating to cancelled development of coal-fueled generation facilities.

(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and exclude capitalized amounts.

(d) Transition and business optimization costs include certain incentive compensation expenses, system development professional fees related to major generation operations and retail billing/customer care computer applications and costs relating to certain growth initiatives.

(e) Transaction and merger expenses include costs related to the Merger and abandoned strategic transactions, the Sponsor Group management fee, outsourcing transition costs and costs related to certain growth initiatives.

(f) Restructuring and other includes net third-party fees paid in connection with the amendment and extension of the TCEH Senior Secured Facilities, gains on termination of a long-term power sales contract and settlement of amounts due from a hedging/trading counterparty, and reversal of certain liabilities accrued in purchase accounting.

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

Exhibit 99(d)

Mine Safety Disclosures

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

We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our 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 ours, 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 of fines and assessments 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 Dodd-Frank Wall Street Reform and Consumer Protection Act sourced from data documented as of October 6, 2011 in the MSHA Data Retrieval System for the three and nine months ended September 30, 2011 (except pending legal actions, which are as of September 30, 2011), are as follows:

	Three Months Ended September 30, 2011						Nine Months Ended September 30, 2011
Mine (a)	Section 104 S and S Citations (b)		Proposed MSHA Assessments ($ thousands) (c)		Pending Legal Action (d)		Section 104 S and S Citations (b)		Proposed MSHA Assessments ($ thousands) (c)		Pending Legal Action (d)
Beckville		6		10		5		8		19		5
Big Brown		3		—		2		6		25		2
Kosse		2		—		2		4		118		2
Oak Hill		1		1		2		1		14		2
Sulphur Springs		5		—		2		5		6		2
Tatum		—		—		2		1		5		2
Three Oaks		2		1		3		4		6		3
Turlington		3		2		—		3		2		—
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 periods ended September 30, 2011, 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, 2011, our mining operations received five citations and orders under Section 104(d) (Beckville (3), Kosse and Turlington mines), one order under Section 107(a) (Beckville mine) and no citations, orders or written notices under Sections 104(b), 104(e) or 110(b)(2)] of the Mine Act, and they experienced no fatalities. During the nine months ended September 30, 2011, our mining operations received six citations and order under Section 104(d) (Beckville (3), Kosse (2) and Turlington mines), two orders under Section 107(a) (Beckville mine) and no citations, orders or written notices under Sections 104(b), 104(e) or 110(b)(2) of the Mine Act, and they experienced no fatalities.