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 JUNE 30, 2011

— OR —

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

Commission File Number 1-12833

Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

Texas	75-2669310
(State of incorporation)	(I.R.S. Employer Identification No.)
1601 Bryan Street, Dallas, TX 75201-3411	(214) 812-4600
(Address of principal executive offices) (Zip Code)	(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes   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

As of July 28, 2011, there were 1,675,597,195 shares of common stock, without par value, outstanding of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.’s parent holding company, and none of which are publicly traded).

TABLE OF CONTENTS

		PAGE
GLOSSARY			ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Statements of Consolidated Income (Loss) – Three and Six Months Ended June 30, 2011 and 2010		1
	Condensed Statements of Consolidated Comprehensive Income (Loss) – Three and Six Months Ended June 30, 2011 and 2010		1
	Condensed Statements of Consolidated Cash Flows – Six Months Ended June 30, 2011 and 2010		2
	Condensed Consolidated Balance Sheets – June 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		40
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		69
Item 4.	Controls and Procedures		75
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings		76
Item 1A.	Risk Factors		76
Item 6.	Exhibits		77
SIGNATURE			80

Energy Future Holdings Corp.’s (EFH Corp.) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the EFH Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on EFH Corp.’s website shall not be deemed a part of, or incorporated by reference into, this quarterly report on Form 10-Q. Readers should not rely on or assume the accuracy of any representation or warranty in any agreement that EFH Corp. has filed as an exhibit to this Form 10-Q because such representation or warranty may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties’ risk allocation in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes or may no longer continue to be true as of any given date.

This Form 10-Q and other Securities and Exchange Commission filings of EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or “we,” “our,” “us” or “the company”), EFCH, EFIH, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent 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	EFH Corp.’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 of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-Q (see reconciliations in Exhibits 99(b), 99(c) and 99(d)) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with 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.
Competitive Electric segment	Refers to the EFH Corp. business segment that consists principally of TCEH.
CREZ	Competitive Renewable Energy Zone
CSAPR	Cross-State Air Pollution Rule
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.
EFIH Notes	Refers collectively to EFIH’s and EFIH Finance’s 9.75% Senior Secured Notes due October 15, 2019 (EFIH 9.75% Notes), 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% Notes) and 11% Senior Secured Second Lien Notes due October 1, 2021 (EFIH 11% Notes).
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
FASB	Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting
FERC	US Federal Energy Regulatory Commission
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.

iii

Merger	The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.
Merger Agreement	Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.
MMBtu	million British thermal units
Moody’s	Moody’s Investors Services, Inc. (a credit rating agency)
MW	megawatts
MWh	megawatt-hours
NERC	North American Electric Reliability Corporation
NRC	US Nuclear Regulatory Commission
NYMEX	Refers to the New York Mercantile Exchange, a physical commodity futures exchange.
Oncor	Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.
Oncor Holdings	Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context.
Oncor Ring-Fenced Entities	Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
purchase accounting	The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
Regulated Delivery segment	Refers to the EFH Corp. business segment that consists of the operations of Oncor.
REP	retail electric provider
RRC	Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
S&P	Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)
SEC	US Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended

iv

SG&A	selling, general and administrative
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.)
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 the Oncor Ring-Fenced Entities.
Texas Transmission	Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group.
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.
TXU Gas	TXU Gas Company, a former subsidiary of EFH Corp.
US	United States of America
VIE	variable interest entity

v

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(millions of dollars)
Operating revenues	$	1,679		$	1,993		$	3,351		$	3,992
Fuel, purchased power costs and delivery fees		(838	)		(1,074	)		(1,668	)		(2,121	)
Net gain from commodity hedging and trading activities		190			67			95			1,280
Operating costs		(247	)		(229	)		(463	)		(426	)
Depreciation and amortization		(371	)		(350	)		(740	)		(692	)
Selling, general and administrative expenses		(178	)		(185	)		(342	)		(373	)
Franchise and revenue-based taxes		(22	)		(26	)		(42	)		(49	)
Other income (Note 15)		33			211			75			244
Other deductions (Note 15)		(106	)		(7	)		(110	)		(18	)
Interest income		—			—			2			9
Interest expense and related charges (Note 15)		(1,301	)		(1,122	)		(1,945	)		(2,074	)
Loss before income taxes and equity in earnings of unconsolidated subsidiaries		(1,161	)		(722	)		(1,787	)		(228	)
Income tax benefit		384			237			599			35
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2)		72			59			122			122
Net loss	$	(705	)	$	(426	)	$	(1,066	)	$	(71	)

See Notes to Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(millions of dollars)
Net loss	$	(705	)	$	(426	)	$	(1,066	)	$	(71	)
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax (expense)/benefit of $(3), $2, $(6) and $—)		5			(4	)		10			—
Cash flow hedges — derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $2, $8, $6 and $18)		5			17			12			36
Total other comprehensive income		10			13			22			36
Comprehensive loss	$	(695	)	$	(413	)	$	(1,044	)	$	(35	)

See Notes to Financial Statements.

1

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2011			2010
	(millions of dollars)
Cash flows — operating activities:
Net loss	$	(1,066	)	$	(71	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation and amortization		895			867
Deferred income tax expense (benefit) – net		(671	)		3
Unrealized net (gain) loss from mark-to-market valuations of commodity positions		385			(848	)
Unrealized net loss from mark-to-market valuations of interest rate swaps (Note 6)		261			361
Interest expense on toggle notes payable in additional principal (Notes 6 and 15)		110			278
Equity in earnings of unconsolidated subsidiaries		(122	)		(122	)
Distributions of earnings from unconsolidated subsidiaries		32			87
Debt extinguishment gains (Note 6)		(25	)		(143	)
Bad debt expense (Note 5)		26			59
Accretion expense related to asset retirement and mining reclamation obligations		27			25
Stock-based incentive compensation expense		2			13
Losses on dedesignated cash flow hedges (interest rate swaps)		17			53
Third-party fees related to debt amendment and extension transactions (Note 15)		100			—
Net gain on sale of assets		(3	)		(81	)
Other, net		(3	)		1
Changes in operating assets and liabilities:
Impact of accounts receivable securitization program (Note 5)		—			(383	)
Margin deposits – net		155			25
Other operating assets and liabilities		62			10
Cash provided by operating activities		182			134
Cash flows — financing activities:
Issuances of long-term debt (Note 6)		1,750			500
Repayments/repurchases of long-term debt (Note 6)		(981	)		(401	)
Net short-term borrowings under accounts receivable securitization program (Note 5)		12			158
Decrease in other short-term borrowings (Note 6)		(503	)		(218	)
Decrease in note payable to unconsolidated subsidiary		(18	)		(17	)
Contributions from noncontrolling interests		8			14
Debt amendment, exchange and issuance costs		(853	)		(15	)
Other, net		—			18
Cash provided by (used in) financing activities		(585	)		39
Cash flows — investing activities:
Capital expenditures		(280	)		(571	)
Nuclear fuel purchases		(107	)		(66	)
Investment redeemed from derivative counterparty (Note 11)		—			400
Proceeds from sales of assets		53			141
Proceeds from sales of environmental allowances and credits		1			6
Purchases of environmental allowances and credits		(9	)		(10	)
Proceeds from sales of nuclear decommissioning trust fund securities		1,784			803
Investments in nuclear decommissioning trust fund securities		(1,792	)		(811	)
Other, net		(1	)		(14	)
Cash used in investing activities		(351	)		(122	)
Net change in cash and cash equivalents		(754	)		51
Effect of deconsolidation of Oncor Holdings		—			(29	)
Cash and cash equivalents — beginning balance		1,534			1,189
Cash and cash equivalents — ending balance	$	780		$	1,211

See Notes to Financial Statements.

2

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	780		$	1,534
Restricted cash (Note 15)		55			33
Trade accounts receivable — net (includes $706 and $612 in pledged amounts related to a VIE (Notes 3 and 5))		1,034			999
Inventories (Note 15)		394			395
Commodity and other derivative contractual assets (Note 11)		2,547			2,732
Margin deposits related to commodity positions		84			166
Other current assets		61			60
Total current assets		4,955			5,919
Restricted cash (Note 15)		1,135			1,135
Receivables from unconsolidated subsidiary (Note 13)		1,446			1,463
Investment in unconsolidated subsidiary (Note 2)		5,652			5,544
Other investments (Note 15)		713			697
Property, plant and equipment — net (Note 15)		19,894			20,366
Goodwill (Note 4)		6,152			6,152
Identifiable intangible assets — net (Note 4)		2,292			2,400
Commodity and other derivative contractual assets (Note 11)		1,556			2,071
Other noncurrent assets, principally unamortized debt amendment and issuance costs		1,277			641
Total assets	$	45,072		$	46,388
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (includes $108 and $96 related to a VIE (Notes 3 and 6))	$	730		$	1,221
Long-term debt due currently (Note 6)		462			669
Trade accounts payable		605			681
Payables due to unconsolidated subsidiary (Note 13)		287			254
Commodity and other derivative contractual liabilities (Note 11)		1,783			2,283
Margin deposits related to commodity positions		703			631
Accumulated deferred income taxes		—			11
Accrued interest		508			411
Other current liabilities		363			442
Total current liabilities		5,441			6,603
Accumulated deferred income taxes		4,695			5,350
Commodity and other derivative contractual liabilities (Note 11)		1,276			869
Notes or other liabilities due to unconsolidated subsidiary (Note 13)		389			384
Long-term debt, less amounts due currently (Note 6)		35,294			34,226
Other noncurrent liabilities and deferred credits (Note 15)		4,923			4,867
Total liabilities		52,018			52,299
Commitments and Contingencies (Note 7)
Equity (Note 8):
EFH Corp. shareholders’ equity		(7,033	)		(5,990	)
Noncontrolling interests in subsidiaries		87			79
Total equity		(6,946	)		(5,911	)
Total liabilities and equity	$	45,072		$	46,388

See Notes to Financial Statements.

3

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFH Corp., a Texas corporation, is a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Oncor (and its majority owner, Oncor Holdings) are not consolidated in EFH Corp.’s financial statements in accordance with consolidation accounting standards related to variable interest entities (VIEs) (see Note 3).

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

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

We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor Holdings and its subsidiaries. See Note 14 for further information concerning reportable business segments.

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in the 2010 Form 10-K. Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Notes 2 and 3). All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. 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.

Beginning with this quarterly report on Form 10-Q, disclosures previously prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” have been replaced with the condensed consolidated financial statements of the guarantors EFCH and EFIH.

4

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.

2. EQUITY METHOD INVESTMENTS

Oncor Holdings

Investment in unconsolidated subsidiary totaled $5.652 billion and $5.544 billion as of June 30, 2011 and December 31, 2010, respectively, and consists of our interest in Oncor Holdings (100% owned), which we account for under the equity method (see Note 3). Oncor Holdings owns approximately 80% of Oncor, which is engaged in regulated electricity transmission and distribution operations in Texas. Revenues from TCEH for distribution services represented 33% and 37% of Oncor Holdings’ operating revenues for the six months ended June 30, 2011 and 2010, respectively. See Note 8 for discussion of cash distributions from Oncor Holdings. Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the three and six months ended June 30, 2011 and 2010 are presented below:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Operating revenues	$	756		$	702		$	1,462		$	1,405
Operation and maintenance expenses		(259	)		(252	)		(518	)		(501	)
Depreciation and amortization		(178	)		(164	)		(350	)		(331	)
Taxes other than income taxes		(93	)		(93	)		(190	)		(187	)
Other income		7			9			15			19
Other deductions		(3	)		(2	)		(5	)		(3	)
Interest income		8			9			18			19
Interest expense and related charges		(88	)		(86	)		(177	)		(170	)
Income before income taxes		150			123			255			251
Income tax expense		(60	)		(49	)		(102	)		(98	)
Net income		90			74			153			153
Net income attributable to noncontrolling interests		(18	)		(15	)		(31	)		(31	)
Net income attributable to Oncor Holdings	$	72		$	59		$	122		$	122

5

Assets and liabilities of Oncor Holdings and its subsidiaries as of June 30, 2011 and December 31, 2010 are presented below:

	June 30, 2011		December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	15	$	33
Restricted cash		47		53
Trade accounts receivable — net		307		254
Trade accounts and other receivables from affiliates		208		182
Income taxes receivable from EFH Corp.		79		72
Inventories		106		96
Accumulated deferred income taxes		25		10
Prepayments		78		75
Other current assets		5		5
Total current assets		870		780
Restricted cash		16		16
Other investments		72		78
Property, plant and equipment — net		10,054		9,676
Goodwill		4,064		4,064
Note receivable due from TCEH		159		178
Regulatory assets — net		1,698		1,782
Other noncurrent assets		302		264
Total assets	$	17,235	$	16,838
LIABILITIES
Current liabilities:
Short-term borrowings	$	580	$	377
Long-term debt due currently		491		113
Trade accounts payable — nonaffiliates		187		125
Accrued taxes other than income		88		133
Accrued interest		107		108
Other current liabilities		103		109
Total current liabilities		1,556		965
Accumulated deferred income taxes		1,605		1,516
Investment tax credits		30		32
Long-term debt, less amounts due currently		4,902		5,333
Other noncurrent liabilities and deferred credits		1,989		1,996
Total liabilities	$	10,082	$	9,842

6

3. 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 investees. 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.

As discussed below, our balance sheet includes assets and liabilities of VIEs that meet the consolidation standards. Oncor Holdings, which holds an approximate 80% interest in Oncor, is not consolidated in EFH Corp.’s financial statements because the structural and operational “ring-fencing” measures discussed in Note 1 prevent us from having power to direct the significant activities of Oncor Holdings or Oncor. We account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, because, while we do not have the power to direct Oncor’s significant activities, we do have the ability to exercise significant influence (as defined by US GAAP) over its activities. Our maximum exposure to loss from our variable interests in VIEs does not exceed our carrying value. See Note 2 for additional information about equity method investments including condensed income statement and balance sheet data for Oncor Holdings.

Consolidated VIEs

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

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:	June 30, 2011		December 31, 2010		Liabilities:	June 30, 2011		December 31, 2010
Cash and cash equivalents	$	9	$	9	Short-term borrowings (a)	$	108	$	96
Accounts receivable (a)		706		612	Trade accounts payable		2		3
Property, plant and equipment		126		112	Other current liabilities		8		1
Other assets, including $2 million of current assets in both periods		6		8
Total assets	$	847	$	741	Total liabilities	$	118	$	100

(a) As a result of accounting guidance related to transfers of financial assets, the balance sheet as of June 30, 2011 and December 31, 2010 reflects $706 million and $612 million, respectively, of pledged accounts receivable and $108 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.

7

4. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides the goodwill balances as of June 30, 2011 and December 31, 2010, all of which relate to our competitive business. There were no changes to the goodwill balances in the three or six months ended June 30, 2011. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges	$	18,342
Accumulated impairment charges		(12,190	)
Balance as of June 30, 2011 and December 31, 2010	$	6,152

In July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR). Compliance with the new rule requires significant additional reductions of sulfur dioxide and nitrogen oxide emissions from our fossil-fueled generation units beginning on January 1, 2012, and will likely have material financial effects, including increased environmental capital expenditures, lower wholesale revenues and higher operating costs. Our evaluation of the consequences of the rule could result in the recording of a noncash goodwill impairment charge in the third quarter 2011.

Identifiable Intangible Assets

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

	June 30, 2011						December 31, 2010
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	319	$	144	$	463	$	293	$	170
Favorable purchase and sales contracts		548		274		274		548		257		291
Capitalized in-service software		295		117		178		278		97		181
Environmental allowances and credits		988		347		641		986		304		682
Mining development costs		80		23		57		47		17		30
Total intangible assets subject to amortization	$	2,374	$	1,080		1,294	$	2,322	$	968		1,354
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization) (a)						43						91
Total intangible assets					$	2,292					$	2,400

(a) 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.

Because of emission allowance limitations under CSAPR, we have excess sulfur dioxide emissions allowances under the Clean Air Act’s existing acid rain cap-and-trade program. Accordingly, we expect to record a noncash impairment charge of approximately $400 million (before deferred income tax benefit) related to our existing sulfur dioxide emission allowance intangible assets in the third quarter of 2011. Our sulfur dioxide emission allowances were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger in October 2007.

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

		Three Months Ended June 30,				Six Months Ended June 30,
Identifiable Intangible Asset	Income Statement Line	2011		2010		2011		2010
Retail customer relationship	Depreciation and amortization	$	13	$	19	$	26	$	39
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees		8		10		17		24
Capitalized in-service software	Depreciation and amortization		11		9		20		17
Environmental allowances and credits	Fuel, purchased power costs and delivery fees		21		22		43		44
Mining development costs	Depreciation and amortization		4		3		6		5
Total amortization expense		$	57	$	63	$	112	$	129

8

Estimated Amortization of Intangible Assets — The estimated aggregate amortization expense of intangible assets, without taking into account the emission allowance impairment discussed above, for each of the next five fiscal years is as follows:

Year	Amortization Expense
2011	$	209
2012		166
2013		143
2014		123
2015		103

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 consolidated, wholly-owned, bankruptcy-remote, direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. In accordance with 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, 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 $108 million as of June 30, 2011. Under the terms of the program, available funding as of June 30, 2011 was reduced by $34 million of customer deposits held by the originator because TCEH’s credit ratings were lower than Ba3/BB-.

All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. 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 $598 million and $516 million as of June 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 June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Program fees	$	2		$	3		$	4		$	5
Program fees as a percentage of average funding (annualized)		9.8	%		4.2	%		8.0	%		2.8	%

9

Activities of TXU Receivables Company were as follows:

	Six Months Ended June 30,
	2011			2010
Cash collections on accounts receivable	$	2,501		$	2,921
Face amount of new receivables purchased		(2,595	)		(2,955	)
Discount from face amount of purchased receivables		5			6
Program fees paid to funding entities		(4	)		(5	)
Servicing fees paid to Service Co. for recordkeeping and collection services		(1	)		(1	)
Increase in subordinated notes payable		82			259
Financing cash flows used by (provided to) originator under the program	$	(12	)	$	225

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 June 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. The level of cash flows would normalize in approximately 16 to 30 days.

Trade Accounts Receivable

	June 30, 2011			December 31, 2010
Wholesale and retail trade accounts receivable, including $706 and $612 in pledged retail receivables	$	1,062		$	1,063
Allowance for uncollectible accounts		(28	)		(64	)
Trade accounts receivable — reported in balance sheet	$	1,034		$	999

Gross trade accounts receivable as of June 30, 2011 and December 31, 2010 included unbilled revenues of $386 million and $297 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Six Months Ended June 30,
	2011			2010
Allowance for uncollectible accounts receivable as of beginning of period	$	64		$	81
Increase for bad debt expense		26			59
Decrease for account write-offs		(36	)		(72	)
Reversal of reserve related to counterparty bankruptcy (Note 15)		(26	)		—
Allowance for uncollectible accounts receivable as of end of period	$	28		$	68

10

Receivables from Unconsolidated Subsidiary

Receivables from unconsolidated subsidiary are measured at historical cost and primarily consist of Oncor’s obligation under the EFH Corp. pension and OPEB plans. EFH Corp. reviews Oncor’s credit scores to assess the overall collectability of its affiliated receivables, which totaled $1.446 billion and $1.463 billion as of June 30, 2011 and December 31, 2010, respectively. There were no credit loss allowances as of June 30, 2011. See Note 13 for additional information about related party transactions.

6. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

As of June 30, 2011, outstanding short-term borrowings totaled $730 million, which included $622 million under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.39%, excluding certain customary fees, and $108 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 June 30, 2011 are presented below. The facilities are all senior secured facilities of TCEH. See “Amendment and Extension of TCEH Senior Secured Facilities” below for discussion of amendments, extensions and repayments of the facilities in April 2011.

			As of June 30, 2011
Facility	Maturity Date		Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)		October 2013	$	645	$	—	$	195	$	450
TCEH Revolving Credit Facility (a)		October 2016		1,409		—		427		982
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	$	—	$	1,684	$	1,432
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 June 30, 2011, all outstanding 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 June 30, 2011, all outstanding 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. In April 2011, TCEH repaid $188 million of the cash borrowings as discussed under “Issuance of TCEH 11.5% Senior Secured Notes” below. Letters of credit totaling $927 million issued as of June 30, 2011 are supported by the restricted cash, and the remaining letter of credit availability totals $208 million.

(c) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 190 million MMBtu as of June 30, 2011. As of June 30, 2011, there were no borrowings under this facility.

11

Long-Term Debt

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

	June 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
0.077% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.184% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.077% 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)		(125	)		(132	)
Senior Secured Facilities:
3.690% TCEH Term Loan Facilities maturing October 10, 2014 (e)(f)(g)		3,809			19,929
3.691% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		42			1,250
0.161% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (h)		—			—
4.730% TCEH Term Loan Facilities maturing October 10, 2017 (e)(f)(i)		15,351			—
4.691% TCEH Letter of Credit Facility maturing October 10, 2017 (f)		1,020			—
Other:
10.25% Fixed Senior Notes due November 1, 2015 (j)		1,873			1,873
10.25% Fixed Senior Notes due November 1, 2015, Series B (j)		1,292			1,292
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		70			76
Other		3			3
Unamortized discount		(12	)		—
Unamortized fair value discount (d)		(2	)		(2	)
Total TCEH		29,695			28,848
EFCH
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		44			46
1.073% 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	)
Total EFCH	$	90		$	91

12

	June 30, 2011			December 31, 2010
EFH Corp. (parent entity)
10.875% Fixed Senior Notes due November 1, 2017 (k)	$	196		$	359
11.25 / 12.00% Senior Toggle Notes due November 1, 2017 (k)		363			571
9.75% Fixed Senior Secured Notes due October 15, 2019		115			115
10.000% Fixed Senior Secured Notes due January 15, 2020		1,061			1,061
5.550% Fixed Senior Notes Series P due November 15, 2014 (l)		398			434
6.500% Fixed Senior Notes Series Q due November 15, 2024 (l)		740			740
6.550% Fixed Senior Notes Series R due November 15, 2034 (l)		744			744
8.820% Building Financing due semiannually through February 11, 2022 (m)		64			68
Unamortized fair value premium related to Building Financing (d)		14			15
Capital lease obligations		2			4
Unamortized fair value discount (d)		(453	)		(476	)
Total EFH Corp.		3,244			3,635
EFIH
9.75% Fixed Senior Secured Notes due October 15, 2019		141			141
10.000% Fixed Senior Secured Notes due December 1, 2020		2,180			2,180
11.00% Senior Secured Second Lien Notes due October 1, 2021		406			—
Total EFIH		2,727			2,321
Total EFH Corp. consolidated		35,756			34,895
Less amount due currently		(462	)		(669	)
Total long-term debt	$	35,294		$	34,226

(a) These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.

(b) Interest rates in effect as of June 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 June 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 an aggregate $9.6 billion principal amount from October 2014 through October 2017.

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

(g) December 31, 2010 amount excludes $20 million that is held by EFH Corp. and eliminated in consolidation.

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

(i) June 30, 2011 amount excludes $19 million that is held by EFH Corp. and eliminated in consolidation.

(j) Amounts exclude $173 million and $150 million of the TCEH Senior Notes and TCEH Senior Notes, Series B, respectively, that are held either by EFH Corp. or EFIH and eliminated in consolidation.

(k) Amounts exclude $1.591 billion and $1.428 billion of EFH Corp. 10.875% Notes and $2.676 billion and $2.296 billion of EFH Corp. Toggle Notes as of June 30, 2011 and December 31, 2010, respectively, that are held by EFIH and eliminated in consolidation.

(l) Amounts exclude $45 million and $9 million of the Series P notes as of June 30, 2011 and December 31, 2010, respectively, and $6 million and $3 million of the Series Q and Series R notes, respectively, as of both June 30, 2011 and December 31, 2010 that are held by EFIH and eliminated in consolidation.

(m) This financing is secured and will be serviced with cash drawn by the beneficiary of a letter of credit.

Debt Repayments

Repayments of long-term debt in the six months ended June 30, 2011 totaled $981 million and included $958 million of long-term debt borrowings under the TCEH Senior Secured Facilities as discussed immediately below, $16 million of principal payments at scheduled maturity dates and $7 million of contractual payments under capitalized lease obligations.

13

Amendment and Extension of TCEH Senior Secured Facilities

Borrowings under these facilities totaled $20.844 billion as of June 30, 2011. 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 ending from March 31, 2011 through December 31, 2014, and decline over time to 5.50 to 1.00 for the test periods ending March 31, 2017 and thereafter. The previous maximum ratios were 6.75 to 1.00 for the test periods ending December 31, 2010 through September 30, 2011, declining over time to 5.75 to 1.00 for the test period ending March 31, 2014 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 contains 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). In addition to the acknowledgements described above, TCEH agreed in the Amendment:

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

• that borrowings outstanding under the P&I Note will not exceed $2 billion in the aggregate at any time (as of June 30, 2011, the outstanding balance of the P&I Note was $1.139 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).

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

• the maturity of $15.351 billion principal amount of first lien term loans held by accepting lenders 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 the $645 million of commitments not extended and until October 2016 with respect to the $1.409 billion of commitments that were extended; such amounts borrowed totaled $195 million and $427 million, respectively, as of June 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 $100 million were expensed (see Note 15 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 $790 million in operating loss carryforwards. The transactions resulted in a one-time 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);

• 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 $799 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.

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, beginning July 1, 2011, 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.

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.

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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. The transaction resulted in a debt extinguishment gain of $25 million (reported as other income). EFIH intends to hold the acquired securities as an investment.

The EFIH 11% Notes mature in October 2021, with interest payable in cash semiannually in arrears on May 15 and November 15, beginning November 15, 2011, at a fixed rate of 11% per annum. The EFIH 11% Notes are secured on a second-priority basis by the EFIH Collateral described in the discussion of the EFH Corp. 10% Senior Secured Notes below.

The EFIH 11% Notes were issued in private placements 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 EFIH and are effectively senior in right of payment to all existing or future unsecured debt of EFIH to the extent of the value of the EFIH Collateral. The notes are effectively subordinated to all debt of EFIH that is either (i) secured by a lien on the EFIH Collateral that is senior to the second-priority liens securing the EFIH 11% Notes or (ii) secured by assets other than the EFIH Collateral, to the extent of the value of the collateral securing that debt. Furthermore, the EFIH 11% Notes are (i) structurally subordinated to all indebtedness and other liabilities of EFIH’s subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries, any of EFIH’s future foreign subsidiaries and any other unrestricted subsidiaries and (ii) senior in right of payment to any future subordinated indebtedness of EFIH.

The indenture governing the EFIH 11% Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFIH’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.

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 the aggregate principal amount of all outstanding EFIH 11% Notes may declare the principal amount on all such notes to be due and payable immediately.

Until May 15, 2014, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFIH 11% Notes from time to time at a redemption price of 111% of the aggregate principal amount of the notes being redeemed, plus accrued interest. EFIH may redeem the notes at any time prior to May 15, 2016 at a price equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. EFIH may also redeem the notes, in whole or in part, at any time on or after May 15, 2016, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture), EFIH must offer to repurchase the notes at 101% of their principal amount, plus accrued interest.

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EFIH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH 11% 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 EFIH 11% Notes, unless such notes meet certain transferability conditions (as described in the related registration rights agreement). If the registration statement has not been filed and declared effective within 365 days after the original issue date (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter, the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.

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 June 30, 2011 of $4.650 billion (excluding $323 million principal amount held by EFH Corp. and EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH’s direct parent, EFCH (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.

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 June 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 (collectively, the Guarantors). The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), 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 issued in private placements and have not been registered under the Securities Act. TCEH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the TCEH Senior Secured Second Lien Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the TCEH Senior Secured Second Lien Notes unless such notes meet certain transferability conditions (as described in the related registration rights agreement). If the registration statement has not been filed and declared effective within 365 days after the original issue date (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.

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EFH Corp. 10% Senior Secured Notes — These notes mature in January 2020, with interest payable in cash semi-annually in arrears on January 15 and July 15 at a fixed rate of 10% per annum, and had a total principal amount of $1.061 billion as of June 30, 2011. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH. The guarantee from EFIH is secured by EFIH’s pledge of 100% of the membership interests and other investments it owns in Oncor Holdings (such membership interests and other investments, the EFIH Collateral). The guarantee from EFCH is not secured. EFIH’s guarantee of the EFH Corp. 10% Notes is secured by the EFIH Collateral on an equal and ratable basis with the EFIH Notes and EFIH’s guarantee of the EFH Corp. 9.75% Notes.

The EFH Corp. 10% Notes were issued in private placements with registration rights. In March 2011, EFH Corp. completed an offer to exchange notes registered under the Securities Act that have substantially identical terms (other than transfer restrictions) for the EFH Corp. 10% Notes.

EFH Corp. 10.875% Senior Notes and 11.25/12.00% Senior Toggle Notes (collectively, EFH Corp. Senior Notes) — These notes mature in November 2017, with interest payable in cash semi-annually in arrears on May 1 and November 1 at a fixed rate for the 10.875% Notes of 10.875% per annum and for the Toggle Notes a fixed rate of 11.250% per annum for cash interest and a fixed rate of 12.000% per annum for PIK Interest. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the Toggle Notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once EFH Corp. makes a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. revokes the election.

These notes had a total principal amount as of June 30, 2011 of $559 million (excluding $4.267 billion principal amount held by EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by EFCH and EFIH.

EFIH 10% Senior Secured Notes — These notes mature in December 2020, with interest payable in cash semi-annually in arrears on June 1 and December 1 at a fixed rate of 10% per annum, and had a total principal amount of $2.180 billion as of June 30, 2011. The EFIH 10% Notes are secured by the EFIH Collateral on an equal and ratable basis with the EFIH 9.75% Notes and EFIH’s guarantee of the EFH Corp. Senior Secured Notes.

Interest Rate Swap Transactions

As of June 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 $9.6 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 six months ended June 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 $9.6 billion principal amount of debt maturing from 2014 to 2017 were entered into in the six months ended June 30, 2011.

As of June 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 $11.25 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 six months ended June 30, 2011, interest rate basis swaps related to an aggregate $3.95 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 such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $403 million and $261 million in net losses in the three and six months ended June 30, 2011, respectively, and $254 million and $361 million in net losses in the three and six months ended June 30, 2010, respectively. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.680 billion as of June 30, 2011, of which $87 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.

Disposed TXU Gas operations — In connection with the sale of TXU Gas in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.

Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. As of June 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 and Note 11 to Financial Statements in the 2010 Form 10-K for discussion of guarantees and security for certain of our indebtedness.

Letters of Credit

As of June 30, 2011, TCEH had outstanding letters of credit under its credit facilities totaling $927 million as follows:

• $525 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);

• $73 million to support TCEH’s REP’s financial requirements with the PUCT, and

• $121 million for miscellaneous credit support requirements.

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. While we are unable to estimate any possible loss or predict the outcome of the litigation, we believe that the plaintiffs’ claims are without merit, and we intend to vigorously defend this litigation.

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

The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our common stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or on a pro forma basis, after giving effect to such distribution, EFH Corp.’s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total debt (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. EFH Corp.’s consolidated leverage ratio was 9.4 to 1.0 as of June 30, 2011.

In addition, the indentures governing the EFIH Notes generally restrict EFIH from making any cash distribution to EFH Corp. for the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend, EFIH’s consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indentures governing the EFIH Notes, the term “consolidated leverage ratio” is defined as the ratio of EFIH’s consolidated total debt (as defined in the indentures) to EFIH’s Adjusted EBITDA on a consolidated basis (including Oncor’s Adjusted EBITDA). EFIH’s consolidated leverage ratio was 5.6 to 1.0 as of June 30, 2011.

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 our common stock unless at the time, and after giving effect to such dividend, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. As of June 30, 2011, that ratio was 8.4 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 would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent.

EFH Corp. has not declared or paid any dividends since the Merger.

Distributions from Oncor — Oncor’s distributions to us totaled $32 million and $87 million in the six months ended June 30, 2011 and 2010, respectively. Subsequent to the Merger through December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s cumulative net income determined in accordance with US GAAP, subject to certain defined adjustments. Such adjustments include deducting a $46 million after-tax one-time refund to customers in 2008, net accretion of fair value adjustments resulting from purchase accounting and funds spent as part of a $100 million commitment for additional demand-side management or other energy efficiency initiatives, which totaled $37 million after tax through June 30, 2011, and removing the effects of the $860 million goodwill impairment charge in 2008. As of June 30, 2011, $241 million was available for distribution to Oncor’s members under the cumulative net income restriction, of which approximately 80% relates to EFH Corp.’s ownership interest in Oncor.

Oncor’s distributions are further limited by an agreement with the PUCT that its regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. As of June 30, 2011, the regulatory capitalization ratio was 58.9% debt and 41.1% equity. The PUCT has the authority to determine what types of debt and equity are included in a utility’s debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes transition bonds issued by Oncor Electric Delivery Transition Bond Company. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization). As of June 30, 2011, $150 million was available for distribution under the capital structure restriction, of which approximately 80% relates to our ownership interest in Oncor.

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Noncontrolling Interests

As discussed in Note 3, 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 six months ended June 30, 2011 and 2010.

Equity

The following table presents the changes to equity during the six months ended June 30, 2011.

	EFH Corp. Shareholders’ Equity
	Common      Stock (a)		Additional     Paid-in Capital		Retained      Earnings     (Deficit)			Accumulated Other     Comprehensive     Income (Loss)			Noncontrolling     Interests		Total      Equity
Balance as of December 31, 2010	$	2	$	7,937	$	(13,666	)	$	(263	)	$	79	$	(5,911	)
Net loss		—		—		(1,066	)		—			—		(1,066	)
Effects of stock-based incentive compensation plans		—		1		—			—			—		1
Change in unrecognized gains related to pension and OPEB plans		—		—		—			10			—		10
Net effects of cash flow hedges		—		—		—			12			—		12
Investment by noncontrolling interests		—		—		—			—			8		8
Balance as of June 30, 2011	$	2	$	7,938	$	(14,732	)	$	(241	)	$	87	$	(6,946	)

(a) Authorized shares totaled 2,000,000,000 as of June 30, 2011. Outstanding shares totaled 1,675,484,695 and 1,671,812,118 as of June 30, 2011 and December 31, 2010, respectively.

The following table presents the changes to equity during the six months ended June 30, 2010.

	EFH Corp. Shareholders’ Equity
	Common      Stock (a)		Additional     Paid-in Capital			Retained      Earnings     (Deficit)			Accumulated Other     Comprehensive     Income (Loss)			Noncontrolling     Interests			Total      Equity
Balance as of December 31, 2009	$	2	$	7,914		$	(10,854	)	$	(309	)	$	1,411		$	(1,836	)
Net loss		—		—			(71	)		—			—			(71	)
Effects of EFH Corp. stock-based incentive compensation plans		—		14			—			—			—			14
Net effects of cash flow hedges		—		—			—			36			—			36
Effects of deconsolidation of Oncor Holdings		—		—			—			—			(1,363	)		(1,363	)
Investment by noncontrolling interests		—		—			—			—			14			14
Stock repurchases		—		(1	)		—			—			—			(1	)
Other		—		—			—			—			(1	)		(1	)
Balance as of June 30, 2010	$	2	$	7,927		$	(10,925	)	$	(273	)	$	61		$	(3,208	)

(a) Authorized shares totaled 2,000,000,000 as of June 30, 2010. Outstanding shares totaled 1,668,680,542 and 1,668,065,133 as of June 30, 2010 and December 31, 2009, respectively.

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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 June 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	$	457	$	3,249	$	81	$	8	$	3,795
Interest rate swaps		—		308		—		—		308
Nuclear decommissioning trust – equity securities (c)		208		128		—		—		336
Nuclear decommissioning trust – debt securities (c)		—		233		—		—		233
Total assets	$	665	$	3,918	$	81	$	8	$	4,672
Liabilities:
Commodity contracts	$	519	$	461	$	58	$	8	$	1,046
Interest rate swaps		—		2,013		—		—		2,013
Total liabilities	$	519	$	2,474	$	58	$	8	$	3,059

(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 15.

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		—		98		—		—		98
Nuclear decommissioning trust – equity securities (c)		192		121		—		—		313
Nuclear decommissioning trust – debt securities (c)		—		223		—		—		223
Total assets	$	919	$	4,017	$	401	$	2	$	5,339
Liabilities:
Commodity contracts	$	875	$	672	$	59	$	2	$	1,608
Interest rate swaps		—		1,544		—		—		1,544
Total liabilities	$	875	$	2,216	$	59	$	2	$	3,152

(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 15.

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 transactions 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 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 six months ended June 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 six months ended June 30, 2011 and 2010:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Balance as of beginning of period	$	4		$	156		$	342		$	81
Total realized and unrealized gains (losses) included in net income (loss) (a)		(30	)		14			(48	)		65
Purchases, issuances and settlements (b):
Purchases		53			34			64			73
Issuances		(2	)		(11	)		(3	)		(41	)
Settlements		(2	)		(10	)		13			(1	)
Transfers into Level 3 (c)		—			—			—			—
Transfers out of Level 3 (c)		—			(14	)		(345	)		(8	)
Balance as of end of period	$	23		$	169		$	23		$	169
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period		(26	)		21			(24	)		75

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

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

(c) Includes transfers due to changes in the observability of significant inputs. 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 of 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.

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10. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments as of June 30, 2011 and December 31, 2010 were as follows:

	June 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)	$	35,684	$	28,977	$	34,815	$	26,594
Off balance sheet liabilities:
Financial guarantees	$	—	$	5	$	—	$	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.

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 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.

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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 June 30, 2011 and December 31, 2010:

June 30, 2011
	Derivative assets					Derivative liabilities
	Commodity     contracts			Interest rate     swaps		Commodity     contracts			Interest rate     swaps			Total
Current assets	$	2,238		$	306	$	3		$	—		$	2,547
Noncurrent assets		1,551			2		3			—			1,556
Current liabilities		(1	)		—		(984	)		(798	)		(1,783	)
Noncurrent liabilities		(1	)		—		(60	)		(1,215	)		(1,276	)
Net assets (liabilities)	$	3,787		$	308	$	(1,038	)	$	(2,013	)	$	1,044
December 31, 2010
	Derivative assets					Derivative liabilities
	Commodity     contracts			Interest rate     swaps		Commodity     contracts			Interest rate     swaps			Total
Current assets	$	2,637		$	95	$	—		$	—		$	2,732
Noncurrent assets		2,068			3		—			—			2,071
Current liabilities		(2	)		—		(1,542	)		(739	)		(2,283	)
Noncurrent liabilities		—			—		(64	)		(805	)		(869	)
Net assets (liabilities)	$	4,703		$	98	$	(1,606	)	$	(1,544	)	$	1,651

As of June 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 $638 million and $479 million in net liabilities as of June 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 June 30,						Six Months Ended June 30,
Derivative (Income statement presentation)	2011			2010			2011			2010
Commodity contracts (Net gain from commodity hedging and trading activities)	$	189		$	73		$	171		$	1,276
Interest rate swaps (Interest expense and related charges) (a)		(576	)		(422	)		(594	)		(698	)
Net gain (loss)	$	(387	)	$	(349	)	$	(423	)	$	578

(a) Includes amounts reported as unrealized mark-to-market net gains/losses as well as the net effect on interest paid/accrued, both reported in “Interest Expense and Related Charges” (see Note 15).

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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 six months ended June 30, 2011 or 2010.

Derivative type (income statement presentation of loss reclassified from accumulated OCI into income)	Three Months Ended       June 30,						Six Months Ended       June 30,
	2011			2010			2011			2010
Interest rate swaps (interest expense and related charges)	$	(7	)	$	(24	)	$	(17	)	$	(53	)
Interest rate swaps (depreciation and amortization)		—			—			(1	)		—
Commodity contracts (operating revenues)		—			(1	)		—			(1	)
Total	$	(7	)	$	(25	)	$	(18	)	$	(54	)

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

Accumulated other comprehensive income related to cash flow hedges as of June 30, 2011 and December 31, 2010 totaled $57 million and $69 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $11 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income as of June 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 June 30, 2011 and December 31, 2010:

		June 30, 2011		June 30, 2011	June 30, 2011
	June 30, 2011		December 31, 2010
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed	$	29,955	$	17,500	Million US dollars
Basis	$	11,250	$	15,200	Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		2,161		2,681	Million MMBtu
Locational basis swaps		947		1,092	Million MMBtu
All other		737		887	Million MMBtu
Electricity		141,312		143,776	GWh
Congestion Revenue Rights (b)		64,782		15,782	GWh
Coal		5		6	Million tons
Fuel oil		79		109	Million gallons

(a) Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, was approximately 900 million MMBtu and 1.0 billion MMBtu as of June 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.

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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 our credit rating is downgraded by one or more credit rating agency; however, due to our credit ratings being below investment grade, substantially all of such collateral posting requirements are already effective.

As of June 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 $314 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 $80 million and $65 million as of June 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 June 30, 2011 and December 31, 2010, the remaining related liquidity requirement would have totaled $17 million and $18 million, respectively, after reduction for net accounts receivable and derivative assets under netting arrangements.

In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of June 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 $2.007 billion and $1.865 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 June 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 June 30, 2011 and December 31, 2010, the remaining related liquidity requirement would have totaled $885 million and $674 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 $2.321 billion and $2.273 billion as of June 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 June 30, 2011, total credit risk exposure to all counterparties related to derivative contracts totaled $4.0 billion (including associated accounts receivable). The net exposure to those counterparties totaled $1.2 billion as of June 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 $767 million. As of June 30, 2011, the credit risk exposure to the banking and financial sector represented 94% of the total credit risk exposure, a significant amount of which is related to the long-term hedging program, and the largest net exposure to a single counterparty totaled $453 million. Exposure to the 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.

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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.

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

Net pension and OPEB costs for the three and six months ended June 30, 2011 and 2010 are comprised of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Components of net pension costs:
Service cost	$	11		$	10		$	22		$	21
Interest cost		41			39			82			78
Expected return on assets		(39	)		(39	)		(78	)		(79	)
Amortization of net loss		22			13			44			26
Net pension costs		35			23			70			46
Components of net OPEB costs:
Service cost		4			3			7			6
Interest cost		16			15			32			30
Expected return on assets		(4	)		(3	)		(7	)		(6	)
Amortization of net loss		7			5			14			10
Net OPEB costs		23			20			46			40
Total net pension and OPEB costs		58			43			116			86
Less amounts expensed by Oncor (and not consolidated)		(9	)		(9	)		(18	)		(18	)
Less amounts deferred principally as a regulatory asset or property by Oncor		(32	)		(21	)		(65	)		(42	)
Net amounts recognized as expense by EFH Corp. and consolidated subsidiaries	$	17		$	13		$	33		$	26

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.

We made cash contributions related to our pension and OPEB plans totaling $50 million and $12 million, respectively, in the first half of 2011, of which $58 million was contributed by Oncor. We expect to make additional contributions of $125 million and $13 million, respectively, in the remainder of 2011, of which $132 million is expected to be contributed by Oncor.

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13. RELATED PARTY TRANSACTIONS

The following represent our significant related-party transactions.

• We pay an annual management fee under the terms of a management agreement with the Sponsor Group for which we accrued $9 million for both the three months ended June 30, 2011 and 2010 and $18 million for each of the six months ended June 30, 2011 and 2010. The fee is reported as SG&A expense.

• In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of 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.

• Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, 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. 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. Goldman acted as an initial purchaser in the issuance of $500 million principal amount of EFH Corp. 10% Notes in January 2010 for which it received fees totaling $3 million.

• 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.

• TCEH’s retail operations pay electricity delivery fees to Oncor. Amounts expensed for these fees totaled $251 million and $257 million for the three months ended June 30, 2011 and 2010, respectively, and $490 million and $521 million for the six months ended June 30, 2011 and 2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheet as of June 30, 2011 and December 31, 2010 reflects amounts due currently to Oncor totaling $168 million and $143 million, respectively (included in payables due to unconsolidated subsidiary), primarily related to these electricity delivery fees.

• Oncor’s bankruptcy-remote financing subsidiary has issued securitization bonds to recover generation-related regulatory assets through a transition surcharge to its customers. Oncor’s incremental income taxes related to the transition surcharges it collects are being reimbursed by TCEH. Therefore, the balance sheet reflects a noninterest bearing note payable to Oncor of $199 million ($40 million current portion included in payables due to unconsolidated subsidiary) and $217 million ($39 million current portion included in payables due to unconsolidated subsidiary) as of June 30, 2011 and December 31, 2010, respectively. TCEH’s payments on the note totaled $9 million for both the three months ended June 30, 2011 and 2010 and $18 million and $17 million for the six months ended June 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 $9 million for the three months ended June 30, 2011 and 2010, respectively, and $16 million and $19 million for the six months ended June 30, 2011 and 2010, respectively.

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• Oncor pays EFH Corp. subsidiaries for financial and other administrative services and shared facilities at cost. Such amounts reduced reported selling, general and administrative expense by $9 million and $11 million for the three months ended June 30, 2011 and 2010, respectively, and $18 million and $19 million for the six months ended June 30, 2011 and 2010, respectively.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in other investments on the balance sheet, is funded by a delivery fee surcharge billed to REPs by Oncor and remitted monthly to TCEH (totaling $4 million for each of the three months ended June 30, 2011 and 2010 and $8 million for each of the six months ended June 30, 2011 and 2010), with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported in noncurrent liabilities on the balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by us are offset by a net change in the intercompany receivable/payable with Oncor, which in turn results in a change in Oncor’s net regulatory asset/liability. As of June 30, 2011 and December 31, 2010, the excess of the trust fund balance over the decommissioning liability resulted in a payable to Oncor totaling $230 million and $206 million, respectively, included in noncurrent liabilities due to unconsolidated subsidiary in the balance sheet.

• We file a consolidated federal income tax return; however, Oncor Holdings’ federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if Oncor Holdings files its own income tax return. As of June 30, 2011 and December 31, 2010, the amount due to Oncor Holdings totaled $110 million (including $31 million noncurrent portion reported in other noncurrent liabilities expected to be collected in 2012) and $72 million, respectively, and is included in payables due to unconsolidated subsidiary. Oncor Holdings made income tax payments to EFH Corp. totaling $18 million and $94 million in the six months ended June 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 June 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.

• EFH Corp. and Oncor are jointly and severally liable for the funding of the EFH Corp. pension plan and a portion of the OPEB plan obligations. EFH Corp. is liable for the majority of the OPEB plan obligations. Oncor has contractually agreed to reimburse EFH Corp. with respect to certain pension plan and OPEB liabilities. Accordingly, as of June 30, 2011 and December 31, 2010, the balance sheet of EFH Corp. reflects unfunded liabilities related to these obligations and a corresponding receivable from Oncor in the amount of $1.446 billion and $1.463 billion, respectively, classified as noncurrent, which represents the portion of the obligations recoverable by Oncor under regulatory rate-setting provisions and reported by Oncor in its balance sheet.

• 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.

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14. SEGMENT INFORMATION

Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted by TCEH.

The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary. See Note 3 for discussion of the reporting of Oncor Holdings and, accordingly, the Regulated Delivery segment, as an equity method investment.

Corporate and Other represents the remaining nonsegment operations consisting primarily of general corporate expenses and interest on EFH Corp. (parent entity), EFIH and EFCH debt.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 above and in Note 1 to Financial Statements in the 2010 Form 10-K. We evaluate performance based on income from continuing operations. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Operating revenues (all Competitive Electric)	$	1,679		$	1,993		$	3,351		$	3,992
Equity in earnings of unconsolidated subsidiaries (net of tax):
Regulated Delivery (net of minority interest of $18, $15, $31 and $31)	$	72		$	59		$	122		$	122
Net income (loss):
Competitive Electric	$	(671	)	$	(427	)	$	(992	)	$	5
Regulated Delivery		72			59			122			122
Corporate and Other		(106	)		(58	)		(196	)		(198	)
Consolidated	$	(705	)	$	(426	)	$	(1,066	)	$	(71	)

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15. 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 common shares 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 9.4 million restricted stock units in exchange for 16.1 million Time-Based Options (including 5.2 million that were vested) and 2.8 million Performance-Based Options (including 2.0 million that were vested). In addition, restricted stock units issued as compensation to management employees and directors totaled 0.2 million and 0.6 million, respectively, in the three and six months ended June 30, 2011.

Shares of common stock awarded as compensation to board members and other non-employees totaled 2.9 million in the three months ended June 30, 2011 and 3.3 million and 0.2 million in the six months ended June 30, 2011 and 2010, respectively. Of the restricted stock units payable in cash previously granted to certain management employees, 0.6 million vested in of the six months ended June 30, 2010.

Expense recognized for restricted stock units payable in shares totaled $1.4 million and $2.0 million for the three and six months ended June 30, 2011, respectively. Expense recognized for options granted totaled $0.2 million and $2.9 million for the three months ended June 30, 2011 and 2010, respectively, and $1.3 million and $9.8 million for the six months ended June 30, 2011 and 2010, respectively. Expense recognized for deferred shares and other common stock awarded as compensation totaled $1.3 million and $1.4 million for the three months ended June 30, 2011 and 2010, respectively, and $3.0 million and $2.9 million for the six months ended June 30, 2011 and 2010, respectively. In addition, as a result of the decline in value of EFH Corp. shares, in the first quarter 2011, a credit of $3.5 million was recorded related to restricted stock units payable in cash.

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Other Income and Deductions

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Other income:
Debt extinguishment gains (Note 6) (a)	$	25	$	129	$	25	$	143
Settlement of counterparty bankruptcy claims (b) (c)		—		—		21		—
Property damage claim (b)		—		—		7		—
Office space rental income (a)		3		—		6		—
Franchise tax refund (b)		—		—		6		—
Gain on sale of land/water rights (b)		—		44		—		44
Gain on sale of interest in natural gas gathering pipeline business (b)		—		30		—		37
Sales tax refund (b)		—		—		—		5
Other		5		8		10		15
Total other income	$	33	$	211	$	75	$	244
Other deductions:
Net third-party fees paid in connection with the amendment and extension of the TCEH Senior Secured Facilities (Note 6) (d)		100		—		100		—
Ongoing pension and OPEB expense related to discontinued businesses (a)		3		2		5		5
Net charges related to cancelled development of generation facilities (b)		—		1		1		2
Severance charges		—		—		—		2
Other		3		4		4		9
Total other deductions	$	106	$	7	$	110	$	18

(a) Reported in Corporate and Other.

(b) Reported in Competitive Electric segment.

(c) 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.

(d) Includes $86 million reported in Competitive Electric segment and $14 million in Corporate and Other.

Interest Expense and Related Charges

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	768		$	669		$	1,453		$	1,324
Accrued interest to be paid with additional toggle notes		54			139			110			278
Unrealized mark-to-market net loss on interest rate swaps (Note 6)		403			254			261			361
Amortization of interest rate swap losses at dedesignation of hedge accounting		7			24			17			53
Amortization of fair value debt discounts resulting from purchase accounting		13			19			27			38
Amortization of debt issuance, amendment and extension costs and discounts (a)		64			33			93			67
Capitalized interest		(8	)		(16	)		(16	)		(47	)
Total interest expense and related charges	$	1,301		$	1,122		$	1,945		$	2,074

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

Restricted Cash

	June 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)	$	—	$	1,135	$	—	$	1,135
Amounts related to margin deposits held		55		—		33		—
Total restricted cash	$	55	$	1,135	$	33	$	1,135

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Inventories by Major Category

	June 30,     2011		December 31,     2010
Materials and supplies	$	168	$	162
Fuel stock		186		198
Natural gas in storage		40		35
Total inventories	$	394	$	395

Other Investments

	June 30,     2011		December 31,     2010
Nuclear decommissioning trust	$	569	$	536
Assets related to employee benefit plans, including employee savings programs, net of distributions		99		117
Land		41		41
Miscellaneous other		4		3
Total other investments	$	713	$	697

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 unconsolidated subsidiary, reflecting changes in Oncor’s regulatory asset/liability. A summary of investments in the fund follows:

	June 30, 2011
	Cost (a)		Unrealized gain		Unrealized loss			Fair market     value
Debt securities (b)	$	227	$	8	$	(2	)	$	233
Equity securities (c)		220		131		(15	)		336
Total	$	447	$	139	$	(17	)	$	569
	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 4.20% and 4.61% and an average maturity of 6.6 years and 8.8 years as of June 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 June 30, 2011 mature as follows: $103 million in one to five years, $51 million in five to ten years and $79 million after ten years.

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 June 30,					Six Months Ended June 30,
	2011		2010			2011			2010
Realized gains	$	1	$	—		$	1		$	1
Realized losses		—		(1	)		(2	)		(1	)
Proceeds from sale of securities		1,050		239			1,784			803

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Property, Plant and Equipment

As of June 30, 2011 and December 31, 2010, property, plant and equipment of $19.9 billion and $20.4 billion, respectively, is stated net of accumulated depreciation and amortization of $4.9 billion and $4.2 billion, respectively. Our evaluation of the consequences of the EPA’s Cross-State Air Pollution Rule (discussed in Note 4) could result in the recording of noncash asset impairment charges in the third quarter 2011 related to our generation facilities, including related lignite mining operations.

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 six months ended June 30, 2011:

Liability as of January 1, 2011	$	493
Additions:
Accretion		24
Reductions:
Payments, essentially all mining reclamation		(36	)
Liability as of June 30, 2011		481
Less amounts due currently		35
Noncurrent liability as of June 30, 2011	$	446

Other Noncurrent Liabilities and Deferred Credits

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

	June 30, 2011		December 31, 2010
Uncertain tax positions (including accrued interest)	$	1,832	$	1,806
Retirement plan and other employee benefits		1,902		1,895
Asset retirement and mining reclamation obligations		446		452
Unfavorable purchase and sales contracts		660		673
Other		83		41
Total other noncurrent liabilities and deferred credits	$	4,923	$	4,867

The conclusion of all issues contested 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 $700 million with an offsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes. No cash income tax liability is expected related to the conclusion of the 1997 through 2002 audit.

The 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 and $6 million in the three months ended June 30, 2011 and 2010, respectively, and $13 million in each of the six months ended June 30, 2011 and 2010. See Note 4 for intangible assets related to favorable purchase and sales contracts.

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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

	Six Months Ended June 30,
	2011			2010
Cash payments (receipts) related to:
Interest paid (a)	$	1,356		$	1,289
Capitalized interest		(16	)		(47	)
Interest paid (net of capitalized interest) (a)		1,340			1,242
Income taxes		20			52
Noncash investing and financing activities:
Construction expenditures (b)		35			51
Debt exchange transactions		(22	)		(43	)
Principal amount of toggle notes issued in lieu of cash interest (Note 6)		100			272
Capital leases		—			9

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

(b) Represents end-of-period accruals.

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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 six months ended June 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

We are a Dallas, Texas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 3 to Financial Statements for a description of the material features of these “ring-fencing” measures and for a discussion of the reporting of our investment in Oncor (and its majority owner, Oncor Holdings) as an equity method investment.

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The Regulated Delivery segment is comprised of Oncor Holdings and its subsidiaries.

See Note 14 to Financial Statements for further information regarding reportable business segments.

Significant Activities and Events

Natural Gas Prices and Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of June 30, 2011, has effectively sold forward approximately 900 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 111,000 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 for the period beginning July 1, 2011 and ending 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 New York Mercantile Exchange (NYMEX) Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged approximately 90% of the Houston Ship Channel versus Henry Hub pricing point risk for 2011.

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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 17% of the positions in the long-term hedging program as of June 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.

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

	Measure		Balance     2011 (a)		2012		2013		2014		2015		Total
Natural gas hedge volumes (b)		mm MMBtu		~88		~383		~265		~149		—		~885
Weighted average hedge price (c)		$/MMBtu		~7.49		~7.36		~7.19		~7.80		—		—
Weighted average market price (d)		$/MMBtu		4.47		4.84		5.16		5.42		5.70		—

(a) Balance of 2011 is from July 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 115 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 June 30, 2011, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $900 million in pretax unrealized mark-to-market gains or losses.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Realized gains	$	282		$	286		$	621		$	529
Unrealized gains (losses) including reversals of previously recorded amounts on positions settled		(59	)		(167	)		(401	)		890
Total (pre-tax)	$	223		$	119		$	220		$	1,419

The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $2.742 billion and $3.143 billion as of June 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.

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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 adverse 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 substantial portion of which begins to mature in 2014.

		000000000000		000000000000		000000000000		000000000000		000000000000
	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

(a) Based on NYMEX Henry Hub prices.

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

As of June 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 June 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)		Balance 2011(a)		Balance 2011(a)		Balance 2011(a)		Balance 2011(a)
	Balance 2011(a)		2012		2013		2014		2015
$1.00/MMBtu change in gas price (b)	$	~11	$	~45	$	~300	$	~445	$	~610
0.1/MMBtu/MWh change in market heat rate (c)	$	~2	$	~21	$	~41	$	~46	$	~49
$1.00/gallon change in diesel fuel price	$	~1	$	~2	$	~48	$	~48	$	~53

(a) Balance of 2011 is from August 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 June 30, 2011.

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Liability Management Program — As of June 30, 2011, EFH Corp. and its consolidated subsidiaries had $36.3 billion principal amount of long-term debt outstanding. In October 2009, we implemented a liability management program designed to improve our balance sheet by reducing debt and extending debt maturities through debt exchanges, repurchases and amendments. Activities under the liability management program do not include debt issued by Oncor or its subsidiaries.

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

Other liability management activities since October 2009 include debt exchange, issuance and repurchase activities as follows (except where noted, debt amounts are principal amounts):

	Since Inception
Security	Debt Acquired/Settled		Debt Issued/         Cash Paid
EFH Corp 10.875% Notes due 2017	$	1,804	$	—
EFH Corp. Toggle Notes due 2017		2,661		—
EFH Corp. 5.55% Series P Senior Notes due 2014		602		—
EFH Corp. 6.50% Series Q Senior Notes due 2024		10		—
EFH Corp. 6.55% Series R Senior Notes due 2034		6		—
TCEH 10.25% Notes due 2015		1,835		—
TCEH Toggle Notes due 2016		751		—
TCEH Senior Secured Facilities due 2013 and 2014		1,623		—
EFH Corp. and EFIH 9.75% Notes due 2019		—		256
EFH Corp 10% Notes due 2020		—		561
EFIH 11% Notes due 2021		—		406
EFIH 10% Notes due 2020		—		2,180
TCEH 15% Notes due 2021		—		1,221
TCEH 11.5% Notes due 2020 (a)		—		1,604
Cash paid, including use of proceeds from debt issuances in 2010 (b)		—		1,042
Total	$	9,292	$	7,270

(a) Excludes from the $1.750 billion principal amount $12 million in debt discount and $134 million in proceeds used for transaction costs related to the issuance of these notes and the amendment and extension of the TCEH Senior Secured Facilities. All other proceeds were used to repay borrowings under the TCEH Senior Secured Facilities, and the remaining transaction costs were funded with cash on hand.

(b) Includes $95 million of the proceeds from the January 2010 issuance of $500 million principal amount of EFH Corp. 10% Notes due 2020 and $290 million of the proceeds from the October 2010 issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021.

Since inception, the liability management transactions have resulted in the capture of $2.0 billion of debt discount.

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

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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.

TCEH Interest Rate Swap Transactions — As of June 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 $9.6 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 six months ended June 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 $9.6 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 June 30, 2011, 3% of our consolidated long-term debt portfolio was exposed to variable interest rate risk through September 2014 and 18% for October 2014 through October 2017. We may enter into additional interest rate hedges from time to time.

As of June 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 $11.25 billion principal amount of senior secured debt. Swaps related to an aggregate $3.95 billion principal amount of debt expired in the six months ended June 30, 2011.

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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 $403 million and $261 million in net losses in the three and six months ended June 30, 2011, respectively, and $254 million and $361 million in net losses in the three and six months ended June 30, 2010, respectively. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.680 billion and $1.419 billion as of June 30, 2011 and December 31, 2010, respectively, of which $87 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) requiring states to reduce emissions of sulfur dioxide (SO₂) and nitrogen oxide (NOx) that significantly contribute to nonattainment with or interfere with the maintenance of the EPA’s National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone in downwind states. In 2008, the US Court of Appeals for the D.C. Circuit invalidated CAIR, but allowed the rule to continue until such time as 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 (as adopted, the Cross-State Air Pollution Rule (CSAPR)). As proposed, the CSAPR did not include the State of Texas in its annual SO₂ or NO_x programs to address alleged downwind fine particulate effects. However, the EPA solicited comment on whether the State of Texas should be included in the annual program because of possible future concerns regarding downwind effects related to the NAAQS for fine particulate matter.

On July 7, 2011, the EPA issued the final CSAPR. As issued, the final CSAPR includes the State of 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 coal-fueled generation units in covered states (including the State of Texas) and institute a limited “cap and trade” system to achieve required reductions. Compliance with the CSAPR is required beginning January 1, 2012.

The CSAPR requires that (i) one-quarter of the nationwide SO₂ emissions reductions required by the rule occur within the State of Texas, (ii) the State of Texas reduce its total annual SO₂ and NO_x emissions by approximately 47 and 8 percent, respectively, compared to 2010 levels, each beginning on January 1, 2012, and (iii) our fossil-fueled generation units reduce their annual SO₂ and NO_x emissions by approximately 64 and 22 percent, respectively, compared to 2010 levels, each beginning on January 1, 2012. The CSAPR also requires our fossil-fueled generation units to reduce their seasonal NO_x emissions by 19 percent, compared to 2010 levels, beginning on January 1, 2012. We are currently evaluating our operations and options to determine how to comply with the emissions requirements set forth in the CSAPR. Although the CSAPR establishes a “cap and trade” system intended to aid compliance with the emissions budgets, we do not expect sufficient liquidity in emissions trading markets to enable the purchase of emissions credits as a significant element of our near-term compliance strategy. Due to the short timeframe for compliance with the emissions budgets in the CSAPR (i.e., beginning on January 1, 2012), we believe that the permitting, engineering, procurement and construction of new environmental control equipment (or boiler equipment component replacements to enable switching to lower-sulfur coal while maintaining historical power output) that would be necessary to comply with the CSAPR will not be feasible before January 1, 2012.

Each of our lignite/coal-fueled generation facilities is currently equipped with substantial emissions control equipment, including equipment installed as part of our commitment (in connection with the construction of the three recently completed lignite-fueled generation units) to reduce emissions of NO_x, SO₂ and mercury through the installation of emissions control equipment at both new and existing units and fuel blending at some existing units. All of our lignite/coal-fueled generation facilities are equipped with activated carbon injection systems to reduce mercury emissions. Flue gas desulfurization systems designed primarily to reduce SO₂ emissions are installed at Oak Grove Units 1 and 2, Sandow Units 4 and 5, Martin Lake Units 1, 2, and 3, and Monticello Unit 3. Selective catalytic reduction systems designed to reduce NO_x emissions are installed at Oak Grove Units 1 and 2 and Sandow Unit 4. Selective non-catalytic reduction systems designed to reduce NO_x emissions are installed at Sandow Unit 5, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Fabric filter systems designed primarily to reduce particulate matter emissions are installed at Oak Grove Units 1 and 2, Sandow Unit 5, Monticello Units 1 and 2, and Big Brown Units 1 and 2. Electrostatic precipitator systems designed primarily to reduce particulate matter emissions are installed at Sandow Unit 4, Martin Lake Units 1, 2, and 3, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Sandow Unit 5 uses a fluidized bed combustion process that facilitates control of NO_x and SO₂. Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitator systems also assist in reducing mercury and other emissions.

In order to ensure near-term compliance with the CSAPR, the primary options we have identified are (i) reducing the operating levels at certain of our fossil-fueled generation facilities (potentially in conjunction with fuel switching from lignite to Powder River Basin coal and the mothballing or closure of related lignite mining operations), (ii) conducting seasonal or temporary shut-downs of certain of our fossil-fueled generation facilities and related lignite mining operations, (iii) installing and operating dry sorbent injection systems for SO₂ emission reductions and/or increasing levels of scrubber utilization at certain of our lignite/coal-fueled generation facilities, assuming we have access to an adequate supply of sorbent (potentially in conjunction with reducing operating levels and/or fuel switching and mothballing or closure of related lignite mining operations) and (iv) mothballing certain of our fossil-fueled generation facilities and related lignite mining operations. The scrubbers at our legacy coal/lignite-fueled generation facilities typically have maximum efficiency levels in the low to mid-80% range before the units experience significant reductions in operating capacity. We expect to utilize one or more of these options at certain of our fossil-fueled generation facilities and related lignite mining operations.

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In connection with these actions, we will likely incur material capital expenditures and operating costs and experience material revenue decreases due to reduced generation and wholesale power sales volumes. Our evaluation of the consequences of the rule could also result in the recording of noncash asset impairment charges in the third quarter 2011 related to goodwill and/or our generation facilities, including related lignite mining operations.

Further, because of emission allowance limitations under CSAPR, we have more SO₂ emissions allowances provided to us under the Clean Air Act’s existing acid rain cap-and-trade program than we can use in the future. Our SO₂ emission allowances were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger in October 2007. Accordingly, we expect to record a noncash impairment charge of approximately $400 million (before deferred income tax benefit) related to our existing SO₂ emission allowance intangible assets in the third quarter of 2011. We do not expect this noncash impairment charge or the possible other asset impairment charges to cause us or any of our subsidiaries to be in default under any of our respective debt agreements or have a material impact on liquidity.

At the request of the PUCT, ERCOT is updating its prior review of the effects of federal environmental rules on adequate power supplies in the ERCOT region to include the CSAPR.

We expect to petition the EPA to (i) reconsider the final CSAPR provisions that apply the annual SO₂ and NO_x requirements to the State of Texas and (ii) stay the effectiveness of those provisions. We also have the option to challenge these provisions in appropriate legal proceedings. We cannot predict whether we would be successful in a legal challenge to the CSAPR. 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, do not include potential effects of the EPA’s recent issuance of CSAPR.

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. 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 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 or results of operations.

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Recent Federal Level Environmental Lawsuit Activity — In June 2011, the US Supreme Court rejected claims by various states, a municipality and certain private trusts that several power generation companies’ emissions of GHGs constituted a public nuisance under federal common law. In American Electric Power Co. (AEP) v. Connecticut, the Supreme Court held that the Clean Air Act and the EPA actions it authorizes displace any federal common law right to seek abatement of carbon-dioxide emissions from fossil-fueled power plants. Regarding the question whether such claims can be brought under state law, the Supreme Court noted that the issue would depend on whether the Clean Air Act preempts state law. The Supreme Court left the preemption issue open for consideration on remand.

In September 2009, the US District Court for the Northern District of California issued a decision in the case of Native Village of Kivalina v. ExxonMobil Corporation dismissing claims asserted by an Eskimo village that emissions of GHGs from approximately 24 oil and energy companies are causing global warming, which has damaged the arctic sea ice that protects the village from winter storms and erosion. The court dismissed the claims because they raised political (not judicial) questions and because plaintiffs lacked standing to sue. An appeal of the district court’s decision is currently pending in the US Court of Appeals for the Ninth Circuit.

While we are not parties to the AEP and Kivalina cases, rulings in those cases might have an impact on Comer II (discussed in Note 7 to Financial Statements) or on other similar claims that might be filed against us in the future.

Oncor Technology Initiatives — Oncor continues to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters to all residential and most non-residential retail electricity customers in Oncor’s service area. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits.

As of June 30, 2011, Oncor has installed approximately 1,862,000 advanced digital meters, including approximately 348,000 in 2011. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $429 million as of June 30, 2011, including $69 million in 2011. Oncor expects to complete installations of the remaining approximately 1.1 million advanced meters by the end of 2012.

Oncor Rate Review Filed with the PUCT — In January 2011, Oncor filed for a rate review with the PUCT and 203 cities based on a test year ended June 30, 2010. In April 2011, Oncor filed, and the administrative law judges in the rate review granted, a motion requesting abatement of the procedural schedule in the rate review on the grounds that Oncor and the parties to the rate review had reached a Memorandum of Settlement that would settle and resolve all issues in the rate review. Oncor filed a stipulation in May 2011 that incorporated the Memorandum of Settlement along with proposed tariffs. The stipulation and related tariffs are expected to be considered by the PUCT at its August 3, 2011 open meeting. The terms of the settlement include an approximate $137 million base rate increase and additional provisions to address franchise fees and other expenses. The settlement will result in an impact of less than 1% on an average residential monthly bill of 1,300 kWh for a TXU Energy customer. Approximately $93 million of the increase became effective July 1, 2011 on an interim basis, and the remainder will become effective by January 1, 2012. The settlement did not change Oncor’s authorized regulatory capital structure of 60% debt and 40% equity or its authorized return on equity of 10.25%. See “Regulatory Matters” below for further discussion.

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

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RESULTS OF OPERATIONS

Consolidated Financial Results – Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

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

SG&A expenses decreased $7 million, or 4%, to $178 million in 2011. The decrease was driven by lower retail bad debt expense reflecting improved collection initiatives and customer mix.

See Note 15 to Financial Statements for details of other income and deductions.

Interest expense and related charges increased $179 million, or 16%, to $1.301 billion in 2011 reflecting a $149 million increase in unrealized mark-to-market net losses related to interest rate swaps, $31 million in higher amortization of debt issuance and amendment costs and discounts and $8 million in lower capitalization of interest, partially offset by $17 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting.

Income tax benefit totaled $384 million in 2011 compared to $237 million in 2010. The effective tax benefit rates were 33.1% in 2011 and 32.8% in 2010. The increase in the effective tax rate was driven by lower interest accrued on uncertain tax positions, reflecting the most likely settlement of issues related to the discontinued Europe business, largely offset by the Texas margin tax impact from the amendments to the TCEH Senior Secured Facilities completed in April 2011. See Note 6 for additional discussion of income tax effects of the amendments.

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) increased $13 million to $72 million in 2011 reflecting higher revenue rates and warmer weather, partially offset by higher depreciation and third-party transmission service expense.

Net loss increased $279 million to $705 million in 2011.

• Net loss in the Competitive Electric segment increased $244 million to $671 million.

• Earnings from the Regulated Delivery segment increased $13 million to $72 million as discussed above.

• Corporate and Other net expenses (after-tax) totaled $106 million in 2011 and $58 million in 2010. The amounts in 2011 and 2010 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The increase of $48 million reflected lower debt extinguishment gains (reported in other income, see Note 15 to Financial Statements) and net third party fees related to the amendment and extension of the TCEH Senior Secured Facilities, partially offset by lower interest expense driven by reduced debt under the liability management program.

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Consolidated Financial Results – Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

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

SG&A expenses decreased $31 million, or 8%, to $342 million in 2011. The decrease was driven by lower retail bad debt expense reflecting improved collection initiatives and customer mix.

See Note 15 to Financial Statements for details of other income and deductions.

Interest income decreased $7 million to $2 million in 2011 reflecting interest in 2010 on $465 million in collateral under a funding arrangement settled in March 2010.

Interest expense and related charges decreased $129 million, or 6%, to $1.945 billion in 2011 reflecting a $100 million decrease in unrealized mark-to-market net losses related to interest rate swaps and $36 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting as well as lower interest expense resulting from reduced debt under the liability management program as described above under “Significant Activities and Events,” partially offset by $31 million in lower capitalization of interest and $26 million in higher amortization of debt issuance and amendment costs and discounts.

Income tax benefit totaled $599 million in 2011 compared to $35 million in 2010. The effective tax benefit rates were 33.5% in 2011 and 15.4% in 2010. The increase in the effective tax rate was driven by lower interest accrued on uncertain tax positions, the effect of an $8 million deferred tax charge in 2010 related to the Patient Protection and Affordable Care Act and the tax effect of mark-to-market losses on derivative transactions in 2011 compared to significant mark-to-market gains in 2010.

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) totaled $122 million in each period.

Net loss increased $995 million to $1.066 billion in 2011.

• After-tax results in the Competitive Electric segment decreased $997 million to a net loss of $992 million.

• Earnings from the Regulated Delivery segment totaled $122 million in both periods as discussed above.

• Corporate and Other net expenses (after-tax) totaled $196 million in 2011 and $198 million in 2010. The amounts in 2011 and 2010 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The decrease of $2 million reflected lower debt extinguishment gains (reported in other income, see Note 15 to Financial Statements) and net third party fees related to the amendment and extension of the TCEH Senior Secured Facilities, partially offset by lower interest expense driven by reduced debt under the liability management program.

Non-GAAP Earnings Measures

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

49

Competitive Electric Segment

Financial Results

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Operating revenues	$	1,679		$	1,993		$	3,351		$	3,992
Fuel, purchased power costs and delivery fees		(838	)		(1,074	)		(1,668	)		(2,121	)
Net gain from commodity hedging and trading activities		190			67			95			1,280
Operating costs		(247	)		(229	)		(463	)		(426	)
Depreciation and amortization		(364	)		(345	)		(726	)		(681	)
Selling, general and administrative expenses		(175	)		(180	)		(336	)		(363	)
Franchise and revenue-based taxes		(22	)		(26	)		(42	)		(49	)
Other income		4			76			35			89
Other deductions		(89	)		(5	)		(91	)		(11	)
Interest income		19			21			46			42
Interest expense and related charges		(1,183	)		(948	)		(1,714	)		(1,721	)
Income (loss) before income taxes		(1,026	)		(650	)		(1,513	)		31
Income tax (expense) benefit		355			223			521			(26	)
Net income (loss)	$	(671	)	$	(427	)	$	(992	)	$	5

Sales Volume and Customer Count Data

	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			% Change			2011			2010			% Change
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential		6,833			6,848			(0.2	)		12,777			13,568			(5.8	)
Small business (a)		1,806			1,993			(9.4	)		3,572			3,974			(10.1	)
Large business and other customers		3,251			3,925			(17.2	)		6,509			7,444			(12.6	)
Total retail electricity		11,890			12,766			(6.9	)		22,858			24,986			(8.5	)
Wholesale electricity sales volumes (b)		8,414			11,910			(29.4	)		17,625			23,618			(25.4	)
Total sales volumes		20,304			24,676			(17.7	)		40,483			48,604			(16.7	)
Average volume (kWh) per residential customer (c)		3,966			3,723			6.5			7,350			7,351			—
Weather (North Texas average) – percent of normal (d):
Cooling degree days		136.3	%		117.2	%		16.3			143.4	%		115.1	%		24.6
Heating degree days		85.5	%		63.5	%		34.6			110.5	%		131.9	%		(16.2	)
Customer counts:
Retail electricity customers (end of period and in thousands) (e):
Residential											1,706			1,830			(6.8	)
Small business (a)											199			241			(17.4	)
Large business and other customers											20			22			(9.1	)
Total retail electricity customers											1,925			2,093			(8.0	)

(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.

50

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			% Change			2011			2010		% Change
Operating revenues:
Retail electricity revenues:
Residential	$	847		$	906			(6.5	)	$	1,575		$	1,776		(11.3	)
Small business (a)		228			263			(13.3	)		454			529		(14.2	)
Large business and other customers		255			307			(16.9	)		504			592		(14.9	)
Total retail electricity revenues		1,330			1,476			(9.9	)		2,533			2,897		(12.6	)
Wholesale electricity revenues (b) (c)		285			449			(36.5	)		680			953		(28.6	)
Amortization of intangibles (d)		3			3			—			5			2		—
Other operating revenues		61			65			(6.2	)		133			140		(5.0	)
Total operating revenues	$	1,679		$	1,993			(15.8	)	$	3,351		$	3,992		(16.1	)
Net gain from commodity hedging and trading activities:
Unrealized net gains (losses)	$	(73	)	$	(162	)		54.9		$	(395	)	$	816		—
Realized net gains on settled positions		263			229			14.8			490			464		5.6
Total	$	190		$	67			—		$	95		$	1,280		(92.6	)

(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 June 30,					Six Months Ended June 30,
	2011		2010			2011		2010
Reported in revenues	$	—	$	(14	)	$	—	$	(32	)
Reported in fuel and purchased power costs		4		31			10		64
Net gains	$	4	$	17		$	10	$	32

(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.

51

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			% Change			2011			2010			% Change
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	36		$	35			2.9		$	78		$	73			6.8
Lignite/coal		255			209			22.0			488			432			13.0
Total nuclear and lignite/coal		291			244			19.3			566			505			12.1
Natural gas fuel and purchased power (a)		107			390			(72.6	)		215			714			(69.9	)
Amortization of intangibles (b)		32			37			(13.5	)		68			80			(15.0	)
Other costs		62			42			47.6			148			106			39.6
Fuel and purchased power costs		492			713			(31.0	)		997			1,405			(29.0	)
Delivery fees (c)		346			361			(4.2	)		671			716			(6.3	)
Total	$	838		$	1,074			(22.0	)	$	1,668		$	2,121			(21.4	)
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
Nuclear fuel	$	8.30		$	7.83			6.0		$	8.15		$	7.68			6.1
Lignite/coal (d)		20.25			19.49			3.9			19.81			19.76			0.3
Natural gas fuel and purchased power		71.35			50.28			41.9			81.28			51.06			59.2
Delivery fees per MWh	$	29.06		$	28.18			3.1		$	29.27		$	28.57			2.5
Production and purchased power volumes (GWh):
Nuclear		4,384			4,527			(3.2	)		9,590			9,539			0.5
Lignite/coal		14,657			12,479			17.5			28,623			25,297			13.1
Total nuclear- and lignite/coal-fueled generation		19,041			17,006			12.0			38,213			34,836			9.7
Natural gas-fueled generation		244			464			(47.4	)		396			836			(52.6	)
Purchased power (e)		1,019			7,206			(85.9	)		1,874			12,932			(85.5	)
Total energy supply volumes		20,304			24,676			(17.7	)		40,483			48,604			(16.7	)
Capacity factors:
Nuclear		87.3	%		90.1	%		(3.1	)		96.0	%		95.5	%		0.5
Lignite/coal		83.7	%		74.1	%		13.0			83.5	%		78.1	%		6.9
Total		84.5	%		78.0	%		8.3			86.4	%		82.3	%		5.0

(a) See note (b) on previous page.

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

(c) Includes delivery fee charges from Oncor.

(d) Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.

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

Competitive Electric Segment

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.

52

Competitive Electric Segment – Financial Results — Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Operating revenues decreased $314 million, or 16%, to $1.679 billion in 2011.

Retail electricity revenues decreased $146 million or 10%, to $1.330 billion and reflected the following:

• A 7% decrease in sales volumes decreased revenues by $101 million and was driven by declines in both the large and small business markets. Business volumes decreased 15% reflecting a change in customer mix as well as lower counts driven by competitive activity. Residential volumes were essentially flat reflecting a 7% decline in customer count driven by competitive activity offset by 7% higher average consumption driven by warmer weather.

• Lower average pricing decreased revenues by $45 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 $164 million, or 37%, to $285 million 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. The change in wholesale revenues also reflected $14 million in lower unrealized losses 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 $236 million, or 22%, to $838 million in 2011. Purchased power costs decreased $304 million driven by the effect of the nodal market described above. Delivery fees declined $15 million reflecting lower retail volumes. These decreases were partially offset by $47 million in higher fuel costs driven by increased generation and higher prices for purchased coal. Unrealized gains related to physical derivative commodity purchase contracts declined $27 million as described in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

Overall nuclear- and lignite/coal-fueled generation volumes increased 12% in 2011 reflecting a 17% increase in lignite/coal-fueled production driven by the newly constructed generation facilities. Nuclear-fueled production decreased 3% due to an unplanned outage in 2011.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities, which totaled $190 million and $67 million in net gains for the three months ended June 30, 2011 and June 30, 2010, respectively:

	Three Months Ended June 30, 2011
	Net Realized Gains		Net Unrealized Gains (Losses)			Total
Hedging positions	$	260	$	(74	)	$	186
Trading positions		3		1			4
Total	$	263	$	(73	)	$	190

(a) Includes $262 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the period.

	Three Months Ended June 30, 2010
	Net Realized Gains		Net Unrealized Losses			Total
Hedging positions	$	222	$	(149	)	$	73
Trading positions		7		(13	)		(6	)
Total	$	229	$	(162	)	$	67

53

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 $4 million and $17 million in net gains in 2011 and 2010, respectively.

Operating costs increased $18 million, or 8%, to $247 million in 2011. The increase reflected $17 million in higher nuclear maintenance costs reflecting an increase in scope of the planned refueling outage in 2011 as compared to the planned outage in 2010 and $6 million in incremental expense related to new generation units, partially offset by $6 million in lower maintenance costs at natural gas-fueled facilities.

Depreciation and amortization increased $19 million, or 6%, to $364 million in 2011. The increase reflected $15 million in increased depreciation primarily for lignite/coal generation facilities resulting from additions and replacements and $9 million in incremental depreciation from a new generation unit placed in service in May 2010. These increases were partially offset by decreased amortization of intangible assets (see Note 4 to Financial Statements).

SG&A expenses decreased $5 million, or 3%, to $175 million in 2011. The decrease was driven by an $11 million reduction in retail bad debt expense reflecting improved collection initiatives and customer mix.

Other income totaled $4 million in 2011 and $76 million in 2010. Other income in 2010 included a $44 million gain on the sale of land and related water rights and a $30 million gain on the sale of interests in a natural gas gathering pipeline business. See Note 15 to Financial Statements.

Other deductions totaled $89 million in 2011 and $5 million in 2010. Other deductions in 2011 included $86 million in third party fees related to the amendment and extension of the TCEH Senior Secured Facilities. See Notes 6 and 15 to Financial Statements.

Interest expense and related charges increased $235 million, or 25%, to $1.183 billion in 2011 reflecting a $149 million increase in unrealized mark-to-market net losses related to interest rate swaps, $63 million driven by higher average rates, $32 million in higher amortization of debt issuance and amendment costs and discounts and $8 million in lower capitalization of interest, partially offset by $17 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting.

Income tax benefit totaled $355 million in 2011 compared to $223 million in 2010. The effective rate was 34.6% and 34.3% in 2011 and 2010, respectively.

After-tax results for the segment decreased $244 million to a net loss of $671 million in 2011 reflecting higher interest expense driven by higher unrealized mark-to-market net losses related to interest rate swaps, third party fees related to the amendment and extension of the TCEH Senior Secured Facilities in April 2011 and the effect of lower retail volumes and prices, partially offset by a decrease in unrealized mark-to-market net losses from commodity hedging and trading activities.

54

Competitive Electric Segment – Financial Results — Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Operating revenues decreased $641 million, or 16%, to $3.351 billion in 2011.

Retail electricity revenues decreased $364 million or 13%, to $2.533 billion and reflected the following:

• A 9% decrease in sales volumes decreased revenues by $246 million and was driven by declines in both the residential and large and small business markets. Business volumes decreased 12% reflecting a change in customer mix as well as lower counts driven by competitive activity. Residential volumes decreased 6% reflecting a 7% decline in customer count driven by competitive activity.

• Lower average pricing decreased revenues by $118 million reflecting declining prices in both the residential and 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 $273 million, or 29%, to $680 million 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. The change in wholesale revenues also reflected $32 million in lower unrealized losses 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 $453 million, or 21%, to $1.668 billion in 2011. Purchased power costs decreased $530 million driven by the effect of the nodal market described above. Delivery fees declined $45 million reflecting lower retail volumes. These decreases were partially offset by $61 million in higher fuel costs driven by increased generation and higher prices for purchased coal. Unrealized gains related to physical derivative commodity purchase contracts declined $54 million as described in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities.”

Overall nuclear- and lignite/coal-fueled generation production increased 10% in 2011 reflecting a 13% increase in lignite/coal-fueled production driven by increased production from the newly constructed generation facilities.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities, which totaled $95 million and $1.280 billion in net gains for the six months ended June 30, 2011 and June 30, 2010, respectively:

	Six Months Ended June 30, 2011
	Net Realized Gains		Net Unrealized Gains (Losses)			Total
Hedging positions	$	467	$	(400	)	$	67
Trading positions		23		5			28
Total	$	490	$	(395	)	$	95

(a) Includes $566 million in net losses that represent reversals of previously recorded unrealized net gains on positions settled in the period.

	Six Months Ended June 30, 2010
	Net Realized Gains		Net Unrealized Gains		Total
Hedging positions	$	431	$	814	$	1,245
Trading positions		33		2		35
Total	$	464	$	816	$	1,280

55

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 $10 million and $32 million in net gains in 2011 and 2010, respectively.

Operating costs increased $37 million, or 9%, to $463 million in 2011. The increase reflected $18 million in higher nuclear maintenance costs reflecting an increase in scope of the planned refueling outage in 2011 as compared to the planned outage in 2010, $15 million in incremental expense related to new generation units and $8 million in implementation costs for new technology systems and process improvements for generation facilities, partially offset by $6 million in lower maintenance costs at natural gas-fueled facilities.

Depreciation and amortization increased $45 million, or 7%, to $726 million in 2011. The increase reflected $29 million in increased depreciation primarily for lignite/coal generation facilities resulting from additions and replacements and $25 million in incremental depreciation from a new generation unit placed in service in May 2010. These increases were partially offset by decreased amortization of intangible assets (see Note 4 to Financial Statements).

SG&A expenses decreased $27 million, or 7%, to $336 million in 2011. The decrease was driven by $33 million in lower retail bad debt expense reflecting improved collection initiatives and customer mix.

Other income totaled $35 million in 2011 and $89 million in 2010. Other income in 2011 included $21 million related to the settlement of bankruptcy claims against a counterparty and $7 million for a property damage claim. 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 and a $5 million refund of sales taxes related to prior years. See Note 15 to Financial Statements.

Other deductions totaled $91 million in 2011 and $11 million in 2010. Other deductions in 2011 included $86 million in third party fees related to the amendment and extension of the TCEH Senior Secured Facilities. See Note 15 to Financial Statements.

Interest expense and related charges decreased $7 million to $1.714 billion in 2011 reflecting a $100 million decrease in unrealized mark-to-market net losses related to interest rate swaps and $36 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting, partially offset by a $68 million increase driven by higher average rates, $31 million in lower capitalization of interest and $30 million in higher amortization of debt issuance and amendment costs and discounts.

Income tax benefit totaled $521 million on a pretax loss in 2011 compared to income tax expense of $26 million on pretax income in 2010. The effective rate was 34.4% and 83.9% in 2011 and 2010, respectively. The decrease in the effective rate reflected the effect of interest accrued on uncertain tax positions, which was lower in 2011, and the effect of mark-to-market net losses on derivative transactions in 2011 compared to significant mark-to-market net gains in 2010.

After-tax results for the segment decreased $997 million to a net loss of $992 million in 2011 reflecting the decline in unrealized mark-to-market net gains from commodity hedging and trading activities, the effect of lower retail volumes and prices and third party fees related to the amendment and extension of the TCEH Senior Secured Facilities in April 2011, partially offset by a decline in unrealized mark-to-market net losses related to interest rate swaps.

56

Competitive Electric Segment – Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2011 and 2010. The net change in these assets and liabilities, excluding “other activity” as described below, represents $385 million in unrealized net losses in 2011 and $848 million 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.

	Six Months Ended June 30,
	2011			2010
Commodity contract net asset as of beginning of period	$	3,097		$	1,718
Settlements of positions (a)		(556	)		(428	)
Changes in fair value of positions in the portfolio (b)		171			1,276
Other activity (c)		37			44
Commodity contract net asset as of end of period	$	2,749		$	2,610

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

(b) Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”).

(c) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold and physical natural gas exchange transactions.

Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of June 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  June 30, 2011
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(52	)	$	(10	)	$	—		$	—		$	(62	)
Prices provided by other external sources		1,295			1,301			192			—			2,788
Prices based on models		24			(1	)		—			—			23
Total	$	1,267		$	1,290		$	192		$	—		$	2,749
Percentage of total fair value		46	%		47	%		7	%		—	%		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 nonexchange traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 9 to Financial Statements for fair value disclosures and discussion of fair value measurements.

57

FINANCIAL CONDITION

Liquidity and Capital Resources

Cash Flow — Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010 — Cash provided by operating activities increased $48 million to $182 million 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 $335 million, which reflected a low wholesale power price environment and the effects of a severe winter storm in February 2011 as well as increased interest payments and lower distributions received from Oncor, 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 $155 million and $175 million for the six months ended June 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 and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and delivery fees and interest expense and related charges.

Cash used in financing activities totaled $585 million compared to cash provided of $39 million in 2010. Activity in 2011 reflected the amendment and extension of the TCEH Senior Secured Facilities and EFIH debt exchange transaction as discussed in Note 6 to Financial Statements. Activity in 2010 included a $383 million source of financing cash flows due to an accounting change related to the accounts receivable securitization program as discussed above, partially offset by net repayments of debt.

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

Cash used in investing activities totaled $351 million and $122 million in 2011 and 2010, respectively. Investing activities in 2010 reflected the return in 2010 of a $400 million cash investment posted with a derivative counterparty in 2009. Capital expenditures decreased $291 million to $280 million in 2011 reflecting a decrease in spending related to the construction of new generation facilities.

Debt Financing Activity — Activities related to short-term borrowings and long-term debt during the six months ended June 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	$	(977	)
EFCH		—		(2	)
EFH Corp.		427		(434	)
Total long-term		2,256		(1,413	)
Total short-term – TCEH (c)		—		(503	)
Total	$	2,256	$	(1,916	)

(a) Includes $506 million of noncash principal increases consisting of $406 million of EFIH 11% Senior Secured Second Lien Notes issued as a result of the 2011 debt exchange discussed in Note 6 to Financial Statements and $79 million of TCEH Toggle Notes and $21 million of EFH Toggle Notes issued in May 2011 in payment of accrued interest as discussed below under “Toggle Notes Interest Election.”

(b) Includes $432 million of noncash retirements primarily consisting of $428 million as a result of the 2011 debt exchange discussed in Note 6 to Financial Statements and $4 million of reductions of prepayments on a building lease.

(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 $415 million principal amount of TCEH pollution control revenue bonds (PCRBs) subject to mandatory tender and remarketing in November 2011 and amendments to the TCEH Senior Secured Facilities as well as maturity extensions and repayments of borrowings under those facilities in April 2011. Failure of the PCRB remarketing would negatively impact liquidity as TCEH would be required to purchase the bonds at par.

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/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
	June 30, 2011		December 31, 2010		Change
Cash and cash equivalents	$	780	$	1,534	$	(754	)
TCEH Revolving Credit Facility (a)		1,432		1,440		(8	)
TCEH Letter of Credit Facility		208		261		(53	)
Total liquidity (b)	$	2,420	$	3,235	$	(815	)

(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, of which $622 million was borrowed as of June 30, 2011. Lehman is no longer a participant in the facility.

(b) As of June 30, 2011 and December 31, 2010, total liquidity includes $619 million and $465 million, respectively, of net receipts of margin deposits from counterparties related to commodity positions (net of $84 million and $166 million, respectively, 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.

The decline in available liquidity since December 31, 2010 reflected transaction costs of the April 2011 amendment and extension of the TCEH Senior Secured Facilities and interest payments, which were funded largely by cash on hand. Since the April 2011 transaction, liquidity declined $268 million reflecting interest payments.

Pension and OPEB Plan Funding — Pension and OPEB plan funding is expected to total $175 million and $25 million, respectively, in 2011. Oncor is expected to fund $190 million of the total amount consistent with its share of the liability. We made pension and OPEB contributions of $50 million and $12 million, respectively, in the six months ended June 30, 2011, of which $58 million was contributed by Oncor.

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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. We 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.

EFH Corp. made its May 2011 interest payment and will make its November 2011 interest payment on the EFH Corp. Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $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 that is eliminated in consolidation) 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.

Similarly, TCEH made its May 2011 interest payment and will make its November 2011 interest payment 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.

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 June 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 June 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.

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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 June 30, 2011, restricted cash collateral held totaled $55 million. See Note 15 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 June 30, 2011, approximately 340 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 most of these transactions.

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

• $77 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;

• $696 million in cash has been received from counterparties, net of $7 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $630 million received, net of $1 million in cash posted, as of December 31, 2010;

• $525 million in letters of credit have been posted with counterparties, as compared to $473 million posted as of December 31, 2010, and

• $64 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 $48 million, and net refunds of federal income taxes are expected to total approximately $6 million in the next 12 months. Net payments totaled $20 million in the six months ended June 30, 2011.

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 15 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 $108 million and $96 million as of June 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.

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Distributions from Oncor — Oncor’s distributions to us totaled $32 million and $87 million in the six months ended June 30, 2011 and 2010, respectively. In July 2011, we received an additional $32 million distribution. Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with US GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. (See Note 8 to Financial Statements.)

In January 2009, the PUCT awarded certain CREZ construction projects to Oncor. See discussion below under “Regulatory Matters – Oncor Matters with the PUCT.” As a result of the increased capital expenditures for CREZ and the debt-to-equity ratio cap, we expect our distributions from Oncor will be substantially reduced or temporarily discontinued during the CREZ construction period, which is expected to be completed in 2013.

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 June 30, 2011, we were in compliance with all such covenants.

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

Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Secured Notes) for the twelve months ended June 30, 2011 totaled $5.107 billion for EFH Corp. See Exhibits 99(b), 99(c) and 99(d) for a reconciliation of net income (loss) to Adjusted EBITDA for EFH Corp., TCEH and EFIH, respectively, for the six and twelve months ended June 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., EFIH 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, the EFH Corp. Senior Secured Notes and the EFIH Notes as of June 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., EFIH or TCEH to incur certain permitted debt or make certain restricted payments and/or investments. EFH Corp. and its consolidated subsidiaries are in compliance with their maintenance covenants.

	June 30, 2011		December 31, 2010		Threshold Level as  of June 30, 2011
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to Adjusted EBITDA ratio (a)		5.49 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
EFIH Notes:
EFIH fixed charge coverage ratio (c)		(d)		(d)		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 (e)		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 (e)		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
EFIH Notes:
General restrictions (non-EFH Corp. payments):
EFIH fixed charge coverage ratio (c) (f)		(d)		23.9 to 1.0		At least 2.0 to 1.0
General restrictions (EFH Corp. payments):
EFIH fixed charge coverage ratio (c) (f)		(d)		(d)		At least 2.0 to 1.0
EFIH leverage ratio		5.6 to 1.0		5.3 to 1.0		Equal to or less than 6.0 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		8.4 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 (see Note 6 to Financial Statements). As of June 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 June 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) Although EFIH currently meets the fixed charge coverage ratio threshold applicable to certain covenants contained in the indentures governing the EFIH Notes, EFIH’s ability to use such thresholds to incur debt or make restricted payments/investments is currently limited by the covenants contained in the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes.

(d) EFIH meets the ratio threshold. Because EFIH’s interest income exceeds interest expense, the result of the ratio calculation is not meaningful.

(e) 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.

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

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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 June 30, 2011, counterparties to those contracts could have required TCEH to post up to an aggregate of $20 million in additional collateral. This amount largely represents the below market terms of these contracts as of June 30, 2011; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of June 30, 2011, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $26 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 June 30, 2011, TCEH posted letters of credit in the amount of $73 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 $225 million as of June 30, 2011 (which is subject to weekly adjustments based on settlement activity with ERCOT).

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

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

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

A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the 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 ($20.844 billion as of June 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 $44 million in remaining lease payments as of June 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 $49 million in remaining lease payments as of June 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 indentures governing the EFIH Notes contain a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFIH or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFIH Notes.

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (a direct subsidiary of EFH Corp.), as collection agent, in the aggregate have a cross default threshold of $50,000. If any of the aforementioned defaults on indebtedness of the applicable threshold were to occur, the program could terminate.

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

Each of TCEH’s natural gas hedging agreements 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 June 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)	$	427	$	123	$	7,678	$	28,043	$	36,271
Long-term debt – interest (b)		2,992		6,344		5,697		8,716		23,749

(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 June 30, 2011.

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

OFF–BALANCE SHEET ARRANGEMENTS

See Notes 3 and 7 to Financial Statements regarding VIEs and guarantees, 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 June 30, 2011 that are expected to materially impact our financial statements.

REGULATORY MATTERS

See discussions in Note 7 to Financial Statements.

Sunset Review and Other State Legislation

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.

During the 2011 legislative session, the Texas Legislature passed Senate Bill 1693, which directs the PUCT to adopt a rule by September 25, 2011 that will allow utilities to recover distribution-related investments on an interim basis without the need for a full rate case. Utilities will be allowed to file under certain circumstances up to four periodic rate adjustments for these distribution investments between rate cases. No other legislation passed during the 2011 legislation session is expected to have a material impact on our operations, financial position, results of operations or cash flows.

Oncor Matters with the PUCT

Rate Cases — In January 2011, Oncor filed for a rate review (PUCT Docket No. 38929) with the PUCT and 203 original jurisdiction cities based on a test year ended June 30, 2010. If approved as requested, this review would have resulted in an aggregate annual rate increase of approximately $353 million over the test year period adjusted for the impact of weather. Oncor also requested a revised regulatory capital structure of 55% debt to 45% equity. In April 2011, Oncor filed, and the administrative law judges in the rate review granted, a motion requesting abatement of the procedural schedule in the rate review on the grounds that Oncor and the parties to the rate review had reached a Memorandum of Settlement that would settle and resolve all issues in the rate review. Oncor filed a stipulation in May 2011 that incorporated the Memorandum of Settlement along with proposed tariffs. The terms of the settlement include an approximate $137 million base rate increase and additional provisions to address franchise fees (discussed further below) and other expenses. The settlement will result in an impact of less than 1% on an average retail residential monthly bill of 1,300 kWh. Approximately $93 million of the increase became effective in July 2011 on an interim basis, and the remainder will become effective by January 1, 2012. The settlement did not change Oncor’s authorized regulatory capital structure of 60% debt and 40% equity or its authorized return on equity of 10.25%. Under the settlement, Oncor cannot file another general base rate review prior to July 1, 2013, but is not restricted from filing wholesale transmission rate, transmission cost recovery factor, distribution-related investment or other rate updates and adjustments permitted by Texas state law and PUCT rules.

In response to concerns raised by PUCT Commissioners at the July 22, 2011 PUCT open meeting regarding the Memorandum of Settlement, Oncor filed a modified stipulation that removed from the settlement a one-time payment to certain cities served by Oncor for retrospective franchise fees. Instead, pursuant to the terms of a separate agreement with certain cities served by Oncor, and only if the modified stipulation is approved, Oncor would make a one-time payment of approximately $22 million to those cities for retrospective franchise fees. The payment is subject to refund from the cities or recovery from customers after final resolution of proceedings related to the appeals from Oncor’s June 2008 rate review filing discussed immediately below. No other significant terms of the original Memorandum of Settlement were revised. The modified stipulation and related tariffs are scheduled for an evidentiary hearing on July 29, 2011, and may be considered by the PUCT at its August 3, 2011 open meeting.

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In August 2009, the PUCT issued a final order with respect to Oncor’s June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007 (PUCT Docket No. 35717), and new rates were implemented in September 2009. In November 2009, Oncor and four other parties appealed various portions of the rate case final order to a state district court. In January 2011, the District Court signed its judgment reversing the PUCT with respect to two issues: the PUCT’s disallowance of certain franchise fees, and the PUCT’s decision that PURA no longer requires imposition of a rate discount for state colleges and universities. Oncor filed an appeal with the Austin Court of Appeals in February 2011 with respect to the issues it appealed to the District Court and did not prevail upon, as well as the District Court’s decision to reverse the PUCT with respect to discounts for state colleges and universities. The case is currently in the briefing stage. Oncor is unable to predict the outcome of the appeal.

Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT awarded Oncor CREZ construction projects (PUCT Docket Nos. 35665 and 37902) requiring 14 related Certificate of Convenience and Necessity (CCN) amendment proceedings before the PUCT for 17 projects. All 17 projects and 14 CCN amendments have been approved by the PUCT. The projects involve the construction of transmission lines and stations to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of Texas. In addition to these projects, ERCOT completed a study in December 2010 that will result in Oncor and other transmission service providers building additional facilities to provide further voltage support to the transmission grid as a result of CREZ. Oncor currently estimates, based on these additional voltage support facilities and the approved routes and stations for its awarded CREZ projects, that CREZ construction costs will total approximately $2.0 billion. CREZ-related costs could change based on finalization of costs for the additional voltage support facilities and final detailed designs of subsequent project routes. As of June 30, 2011, Oncor’s cumulative CREZ-related capital expenditures totaled $538 million, including $222 million in 2011. Oncor expects that all necessary permitting actions and other requirements and all construction activities for Oncor’s CREZ construction projects will be completed by the end of 2013.

Transmission Cost Recovery and Rates (PUCT Docket Nos. 38938 and 39456) — In order to recover increases in its transmission costs, including incremental fees paid to other transmission service providers due to an increase in their rates, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs. In December 2010, an application was filed to increase the TCRF, which was administratively approved in January 2011 and became effective March 1, 2011. This application increased Oncor’s annualized revenues by an estimated $33 million. In June 2011, Oncor filed an application to increase the TCRF, which is expected to be administratively approved and become effective in September 2011. This application is expected to increase Oncor’s annualized revenues by an estimated $48 million.

Application for Reconciliation of Advanced Meter Surcharge (PUCT Docket No. 39552) — In July 2011, Oncor filed an application with the PUCT for reconciliation of all costs incurred and investments made through December 31, 2010, in the deployment of its advanced meter system (AMS) pursuant to its AMS Deployment Plan that was approved in Docket No. 35718. The Order in Docket No. 35718 included a requirement that Oncor file a reconciliation proceeding two years after the implementation of the AMS surcharge. Through the end of 2010, Oncor spent approximately $357 million in executing the approved AMS Deployment Plan and billed customers approximately $171 million through the AMS surcharge. Oncor is not seeking a change in the AMS surcharge or the AMS Deployment Plan in this proceeding. The PUCT Staff has proposed a procedural schedule, and Oncor anticipates that the proceeding will be concluded by the end of 2011.

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Application for 2012 Energy Efficiency Cost Recovery Factor (PUCT Docket No. 39375) — In May 2011, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2012. PUCT rules require Oncor to make an annual EECRF filing by May 1 (or the first business day in May) for implementation at the beginning of the next calendar year. The requested 2012 EECRF is $54 million, as compared to $51 million established for 2011, and would result in a $0.98 per month charge for residential customers, as compared to the 2011 residential charge of $0.91 per month. As allowed by the rule, the 2012 EECRF is designed to recover $49 million of Oncor’s costs for the 2012 programs and an $8 million performance bonus based on 2010 results, partially offset by a $3 million reduction for over-recovery of 2010 costs. Two parties have requested a hearing, which is scheduled for August 25, 2011. Oncor anticipates that the PUCT will issue an order by the end of 2011.

Remand of 1999 Wholesale Transmission Matrix Case (PUCT Docket No. 38780) — In October 2010, the PUCT established Docket No. 38780 for the remand of Docket No. 20381, the 1999 wholesale transmission charge matrix case. A joint settlement agreement was entered into effective October 6, 2003. This settlement resolved disputes regarding wholesale transmission pricing and charges for the period of January 1997 through August 1999, the period prior to the September 1, 1999 effective date of the legislation that authorized 100% postage stamp pricing for ERCOT wholesale transmission. Since a series of appeals has become final, the 1999 matrix docket has been remanded to the PUCT to address additional issues. If the appealing parties prevail and the PUCT rules adversely with respect to these issues, Oncor believes its liabilities, totaling up to approximately $22 million, would be appropriate for recovery through rates. At this time, Oncor cannot predict the outcome of these matters.

Stipulation Approved by the PUCT — In April 2008, the PUCT entered an order (PUCT Docket No. 34077), which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The filing reported an ownership change involving Texas Holdings’ purchase of EFH Corp. Among other things, the stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007, which Oncor filed in June 2008 as discussed above. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas. A hearing on the appeal was held in June 2010, and the District Court affirmed the PUCT order in its entirety. Nucor Steel appealed that ruling to the Third District Court of Appeals in Austin, Texas in July 2010. Oral argument was held before the court in March 2011. There is no deadline for the court to act. While Oncor is unable to predict the outcome of the appeal, it does not expect the appeal to affect the major provisions of the stipulation.

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

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(e) 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

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.

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

Commodity Price Risk

The competitive business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. 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.

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

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

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

	Six Months Ended     June 30, 2011		Year Ended      December 31, 2010
Month-end average Trading VaR:	$	2	$	3
Month-end high Trading VaR:	$	4	$	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.

	Six Months Ended     June 30, 2011		Year Ended      December 31, 2010
Month-end average MtM VaR:	$	224	$	426
Month-end high MtM VaR:	$	268	$	621
Month-end low MtM VaR:	$	187	$	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.

	Six Months Ended     June 30, 2011		Year Ended      December 31, 2010
Month-end average EaR:	$	185	$	477
Month-end high EaR:	$	228	$	662
Month-end low EaR:	$	150	$	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.

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Interest Rate Risk

As of June 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.

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 $2.206 billion as of June 30, 2011. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of June 30, 2011 include $709 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $75 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 June 30, 2011, the exposure to credit risk from these counterparties totaled $1.497 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $719 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $778 million decreased $828 million in the six months ended June 30, 2011, reflecting a reduction of the asset position of the long-term hedging program due to maturities (partially offset by the effect of a decrease in forward natural gas prices on the value of positions in the program) and an increase in derivative liabilities related to interest rate swaps due to lower interest rates.

Of this $778 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 June 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. 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	$	1,488		$	719	$	769		$	1,272	$	237	$	(21	)	$	1,488
Noninvestment grade		9			—		9			7		2		—			9
Totals	$	1,497		$	719	$	778		$	1,279	$	239	$	(21	)	$	1,497
Investment grade		99.4	%				98.8	%
Noninvestment grade		0.6	%				1.2	%

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, which represented 46% and 25% of the net $778 million 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;
¡	allowed rates of return;
¡	permitted capital structure;
¡	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 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;

• 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.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

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

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the 2010 Form 10-K and in Item 1A of our quarterly report on Form 10-Q for the three months ended March 31, 2011 (March 2011 Form 10-Q) except for the risk factor discussed below and the information disclosed elsewhere in this Form 10-Q that provides factual updates to risk factors contained in the 2010 Form 10-K and March 2011 Form 10-Q.

In order to comply with the EPA’s recently issued Cross-State Air Pollution Rule (CSAPR) we will likely incur material capital expenditures and operating costs and experience material revenue decreases due to reduced generation and wholesale power sales volumes, and we may incur material asset (including goodwill) impairment charges.

In July 2011, the EPA issued the CSAPR. The CSAPR requires states (including the State of Texas) to reduce emissions of sulfur dioxide and nitrogen oxide that significantly contribute to or interfere with the maintenance of the EPA’s National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone in downwind states. The CSAPR includes the State of Texas in its annual sulfur dioxide and nitrogen oxide emissions reduction programs, as well as the seasonal nitrogen oxide emissions reduction program. These programs require significant additional reductions of sulfur dioxide and nitrogen oxide emissions from our fossil-fueled generation units (including Martin Lake, Monticello, Big Brown and Sandow Unit 4) and institute a limited “cap and trade” system to achieve required reductions. In order to comply with CSAPR, our fossil-fueled generation units must reduce their annual sulfur dioxide and nitrogen oxide emissions levels by approximately 64 and 22 percent, respectively, compared to 2010 levels, beginning on January 1, 2012. Additionally, our fossil-fueled generation units must reduce their seasonal nitrogen oxide emissions by 19 percent, compared to 2010 levels, beginning on January 1, 2012. Although the CSAPR establishes a “cap and trade” system intended to aid compliance with the emissions budgets, we do not expect sufficient liquidity in emissions trading markets to enable the purchase of emissions credits as a significant element of our near-term compliance strategy. Due to the short timeframe for compliance with the emissions budgets in the CSAPR (i.e., beginning on January 1, 2012), we believe that the permitting, engineering, procurement and construction of the new environmental control equipment (or boiler equipment component replacements to enable switching to lower-sulfur coal while maintaining historical power output) necessary to comply with the CSAPR will not be feasible before January 1, 2012.

In order to ensure near-term compliance with the CSAPR, the primary options we have identified are (i) reducing the operating levels at certain of our fossil-fueled generation facilities (potentially in conjunction with fuel switching from lignite to Powder River Basin coal and the mothballing or closure of related lignite mining operations), (ii) conducting seasonal or temporary shut-downs of certain of our fossil-fueled generation facilities and related lignite mining operations, (iii) installing and operating dry sorbent injection systems for sulfur dioxide emission reductions and/or increasing levels of scrubber utilization at certain of our lignite/coal-fueled generation facilities, assuming we have access to an adequate supply of sorbent (potentially in conjunction with reducing operating levels and/or fuel switching and mothballing or closure of related lignite mining operations) and (iv) mothballing certain of our fossil-fueled generation facilities and related lignite mining operations. The scrubbers at our legacy coal/lignite-fueled generation facilities typically have maximum efficiency levels in the low to mid-80% range before the units experience significant reductions in operating capacity. We expect to utilize one or more of these options at certain of our fossil-fueled generation facilities and related lignite mining operations. In connection with these actions, we will likely incur material capital expenditures and operating costs and experience material revenue decreases due to reduced generation and wholesale power sales volumes, and we may incur material asset (including goodwill) impairment charges.

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Item 6. Exhibits

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

Exhibits	Previously Filed With File Number*	As Exhibit
(4)	Instruments Defining the Rights of Security Holders, Including Indentures.
	Texas Competitive Electric Holdings Company LLC
4(a)	1-12833 Form 8-K (filed April 20, 2011)	4.1	—	Indenture, dated as of April 19, 2011, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 11.5% Senior Secured Notes due 2020.
4(b)	1-12833 Form 8-K (filed April 20, 2011)	4.2	—	Form of Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as collateral agent for the benefit of the holders of the 11.5% Senior Secured Notes due 2020 of Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., as Beneficiary.
4(c)	1-12833 Form 8-K (filed April 20, 2011)	4.3	—	Form of Deed of Trust and Security Agreement to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as collateral agent for the benefit of the secured parties, as beneficiary.
4(d)	1-12833 Form 8-K (filed April 20, 2011)	4.4	—	Form of Subordination and Priority Agreement, among Citibank, N.A., as beneficiary under the First Lien Credit Deed of Trust, The Bank of New York Mellon Trust Company, N.A., as beneficiary under the Second Lien Indenture Deed of Trust, Citibank, N.A., as beneficiary under the First Lien Indenture Deed of Trust, Texas Competitive Electric Holdings Company LLC and the subsidiary guarantors party thereto.
	Energy Future Intermediate Holding Company LLC
4(e)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	4(e)	—	Indenture, dated as of April 25, 2011, among Energy Future Intermediate Holding Company LLC, EFIH Finance, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11% Senior Secured Second Lien Notes due 2021.
4(f)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	4(f)	—	Junior Lien Pledge Agreement, dated as of April 25, 2011, from Energy Future Intermediate Holding Company LLC, as pledgor, to The Bank of New York Mellon Trust Company, N.A., as collateral trustee.

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Exhibits	Previously Filed With File Number*	As Exhibit
4(g)			—	As permitted by the rules of the Securities and Exchange Commission (Commission), the registrant has not filed certain instruments defining the rights of holders of long-term debt of the registrant or consolidated subsidiaries under which the total amount of securities authorized does not exceed 10% of the total assets of the registrant and its consolidated subsidiaries. The registrant agrees to furnish to the Commission, upon request, a copy of any omitted instrument.
(10)	Material Contracts.
10(a)	1-12833 Form 8-K (filed April 20, 2011)	10.1	—	Amendment No. 2, dated as of April 7, 2011, to the Credit Agreement, dated October 10, 2007, among Energy Future Competitive Holdings Company; Texas Competitive Electric Holdings Company LLC, as the borrower; the several lenders from time to time parties thereto; Citibank, N.A., as administrative agent, collateral agent, swingline lender, revolving letter of credit issuer and deposit letter of credit issuer; Goldman Sachs Credit Partners L.P., as posting agent, posting syndication agent and posting documentation agent; JPMorgan Chase Bank, N.A., as syndication agent and revolving letter of credit issuer; Citigroup Global Markets Inc., J.P. Morgan Securities Inc., Goldman Sachs Credit Partners L.P., Lehman Brothers Inc., Morgan Stanley Senior Funding, Inc. and Credit Suisse Securities (USA) LLC, as joint lead arrangers and bookrunners; Goldman Sachs Credit Partners L.P., as posting lead arranger and bookrunner; Credit Suisse, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc., Morgan Stanley Senior Funding, Inc., as co-documentation agents; and J. Aron & Company, as posting calculation agent.
10(b)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	10(b)	—	Form of First Amendment to Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Beneficiary
(31)	Rule 13a - 14(a)/15d - 14(a) Certifications.
31(a)			—	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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Exhibits	Previously Filed With File Number*	As Exhibit
(32)	Section 1350 Certifications.
32(a)			—	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99)	Additional Exhibits
99(a)			—	Condensed Statement of Consolidated Income – Twelve Months Ended June 30, 2011.
99(b)			—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2011 and 2010.
99(c)			—	Texas Competitive Electric Holding Company LLC Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2011 and 2010.
99(d)			—	Energy Future Intermediate Holding Company LLC Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2011 and 2010.
99(e)			—	Mine safety disclosure required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.
99(f)	1-34543 Form 10-Q (filed July 29, 2011)		—	Energy Future Competitive Holdings Company Part I, Item 1 presented pursuant to Rule 3-10 of Regulation S-X
99(g)	1-34544 Form 10-Q (filed July 29, 2011)		—	Energy Future Intermediate Holding Company LLC Part I, Item1 presented pursuant to Rule 3-10 of Regulation S-X
	XBRL Data Files
101.INS			—	XBRL Instance Document
101.SCH			—	XBRL Taxonomy Extension Schema Document
101.CAL			—	XBRL Taxonomy Extension Calculation Document
101.LAB			—	XBRL Taxonomy Extension Labels Document
101.PRE			—	XBRL Taxonomy Extension Presentation Document

* Incorporated herein by reference.

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SIGNATURE

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

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

Date: July 28, 2011

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