Energy Future (TXU) 10-Q 2013 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2013

— OR —

o 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	46-2488810
(State or other jurisdiction of incorporation or organization)	(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, including area code)

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

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 x    No o

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 o  Accelerated filer o  Non-Accelerated filer x (Do not check if a smaller reporting company)

Smaller reporting company o

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

At August 1, 2013, there were 1,669,861,383 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 is 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, 2013 and 2012	1
	Condensed Statements of Consolidated Comprehensive Income (Loss) — Three and Six Months Ended June 30, 2013 and 2012	1
	Condensed Statements of Consolidated Cash Flows — Six Months Ended June 30, 2013 and 2012	2
	Condensed Consolidated Balance Sheets — June 30, 2013 and December 31, 2012	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	72
Item 4.	Controls and Procedures	78
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	78
Item 1A.	Risk Factors	78
Item 4.	Mine Safety Disclosures	78
Item 5.	Other Information	78
Item 6.	Exhibits	79
SIGNATURE		81

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. The representations and warranties contained in any agreement that we have filed as an exhibit to this quarterly report on Form 10-Q or that we have or may publicly file in the future may contain representations and warranties made by and to the parties thereto at specific dates. Such representations and warranties may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties' risk allocation in the particular transaction, or may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.

This quarterly report on 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 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.

2012 Form 10-K	EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2012
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 US 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.
CAIR	Clean Air Interstate Rule
CFTC	US Commodity Futures Trading Commission
Competitive Electric segment	the EFH Corp. business segment that consists principally of TCEH
CREZ	Competitive Renewable Energy Zone
CSAPR	the final Cross-State Air Pollution Rule issued by the EPA in July 2011, vacated by the US Court of Appeals for the District of Columbia Circuit in August 2012 and accepted for review by the US Supreme Court in June 2013 (see Note 6 to Financial Statements)
D.C. Circuit Court	US Court of Appeals for the District of Columbia Circuit
EBITDA	earnings (net income) before interest expense, income taxes, depreciation and amortization
EFCH	Energy Future Competitive Holdings Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context
EFH Corp.	Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context, whose major subsidiaries include TCEH and Oncor
EFIH	Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings
EFIH Finance	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 6.875% Senior Secured Notes due August 15, 2017 (EFIH 6.875% Notes), 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), 11% Senior Secured Second Lien Notes due October 1, 2021 (EFIH 11% Notes), 11.75% Senior Secured Second Lien Notes due March 1, 2022 (EFIH 11.75% Notes) and 11.25%/12.25% Senior Toggle Notes due December 1, 2018 (EFIH Toggle Notes).
EPA	US Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
ERISA	Employee Retirement Income Security Act of 1974, as amended
Fifth Circuit Court	US Court of Appeals for the Fifth Circuit
GAAP	generally accepted accounting principles
GWh	gigawatt-hours
IRS	US Internal Revenue Service

ii

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	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.
MATS	the Mercury and Air Toxics Standard established by the EPA
Merger	The transaction referred to in the Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which was completed on October 10, 2007.
MMBtu	million British thermal units
Moody's	Moody's Investors Services, Inc. (a credit rating agency)
MW	megawatts
MWh	megawatt-hours
NERC	North American Electric Reliability Corporation
NOX	nitrogen oxides
NRC	US Nuclear Regulatory Commission
NYMEX	the New York Mercantile Exchange, a physical commodity futures exchange
Oncor	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	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	Oncor Holdings and its direct and indirect subsidiaries, including Oncor
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
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	the EFH Corp. business segment that consists primarily of our investment in Oncor
REP	retail electric provider
RCT	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

iii

Securities Act	Securities Act of 1933, as amended
SG&A	selling, general and administrative
SO2	sulfur dioxide
Sponsor Group	Refers, collectively, to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GS Capital Partners, an affiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Holdings.
TCEH	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, and whose major subsidiaries include Luminant and TXU Energy
TCEH Demand Notes	Refers to certain loans from TCEH to EFH Corp. in the form of demand notes to finance EFH Corp. debt principal and interest payments and, until April 2011, other general corporate purposes of EFH Corp., that were guaranteed on a senior unsecured basis by EFCH and EFIH and were settled by EFH Corp. in January 2013.
TCEH Finance	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 and TCEH Finance's 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015, Series B (collectively, TCEH 10.25% Notes) and TCEH's and TCEH Finance's 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).
TCEH Senior Secured Facilities	Refers, collectively, to the TCEH Term Loan Facilities, TCEH Revolving Credit Facility and TCEH Letter of Credit Facility. See Note 5 to Financial Statements for details of these facilities.
TCEH Senior Secured Notes	TCEH's and TCEH Finance's 11.5% Senior Secured Notes due October 1, 2020
TCEH Senior Secured Second Lien Notes	Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes due April 1, 2021 and TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.
TCEQ	Texas Commission on Environmental Quality
Texas Holdings	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	Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities
Texas Transmission	Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor and is not affiliated with EFH Corp., any of EFH Corp.'s subsidiaries or any member of the Sponsor Group
TRE	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	TXU Energy Retail Company LLC, a direct, wholly owned subsidiary of TCEH that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
US	United States of America
VIE	variable interest entity

iv

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,
	2013			2012			2013			2012
	(millions of dollars)
Operating revenues	$	1,419		$	1,385		$	2,679		$	2,607
Fuel, purchased power costs and delivery fees	(687		)	(674		)	(1,323		)	(1,302		)
Net gain (loss) from commodity hedging and trading activities	168			(136		)	(29		)	232
Operating costs	(266		)	(228		)	(496		)	(435		)
Depreciation and amortization	(345		)	(343		)	(695		)	(679		)
Selling, general and administrative expenses	(177		)	(157		)	(338		)	(315		)
Franchise and revenue-based taxes	(16		)	(17		)	(33		)	(36		)
Other income (Note 13)	7			12			14			19
Other deductions (Note 13)	(1		)	(6		)	(4		)	(12		)
Interest income	—			—			1			1
Interest expense and related charges (Note 13)	(598		)	(1,018		)	(1,382		)	(1,804		)
Loss before income taxes and equity in earnings of unconsolidated subsidiaries	(496		)	(1,182		)	(1,606		)	(1,724		)
Income tax benefit	351			403			825			583
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2)	74			83			141			141
Net loss	$	(71	)	$	(696	)	$	(640	)	$	(1,000	)

See Notes to Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(millions of dollars)
Net loss	$	(71	)	$	(696	)	$	(640	)	$	(1,000	)
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax benefit (expense) of $—, $(3), $1 and $(5))	(1		)	4			(3		)	8
Cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $1, $1, $2 and $2)	2			1			4			4
Net effects related to Oncor — reported in equity in earnings of unconsolidated subsidiaries (net of tax benefit of $— in all periods)	—			—			1			1
Total other comprehensive income	1			5			2			13
Comprehensive loss	$	(70	)	$	(691	)	$	(638	)	$	(987	)

See Notes to Financial Statements.

1

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)
	Six Months Ended June 30,
	2013			2012
	(millions of dollars)
Cash flows — operating activities:
Net loss	$	(640	)	$	(1,000	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation and amortization	777			777
Deferred income tax benefit, net	(565		)	(594		)
Income tax benefit due to audit resolutions (Note 13)	(267		)	—
Unrealized net loss from mark-to-market valuations of commodity positions	529			765
Unrealized net gain from mark-to-market valuations of interest rate swaps (Note 13)	(489		)	(9		)
Interest expense on toggle notes payable in additional principal (Notes 5 and 13)	83			117
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 13)	119			122
Equity in earnings of unconsolidated subsidiaries	(141		)	(141		)
Distributions of earnings from unconsolidated subsidiaries	80			69
Bad debt expense (Note 4)	13			11
Accretion expense related primarily to mining reclamation obligations (Note 13)	16			18
Stock-based incentive compensation expense	3			7
Net loss on sale of assets	—			1
Other, net	(1		)	1
Changes in operating assets and liabilities:
Margin deposits, net	(140		)	59
Other operating assets and liabilities	2			(152		)
Cash provided by (used in) operating activities	(621		)	51
Cash flows — financing activities:
Issuances of long-term debt (Note 5)	—			1,150
Repayments/repurchases of long-term debt (Note 5)	(81		)	(24		)
Net short-term borrowings under accounts receivable securitization program (Note 4)	37			38
Decrease in other short-term borrowings (Note 5)	—			(485		)
Decrease in note payable to unconsolidated subsidiary (Note 11)	—			(20		)
Sale/leaseback of equipment	—			15
Contributions from noncontrolling interests	2			4
Debt amendment, exchange and issuance costs and discounts, including third-party fees expensed	(6		)	(38		)
Other, net	(4		)	—
Cash provided by (used in) financing activities	$	(52	)	$	640

2

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)
	Six Months Ended June 30,
	2013			2012
	(millions of dollars)
Cash flows — investing activities:
Capital expenditures	$	(274	)	$	(404	)
Nuclear fuel purchases	(27		)	(96		)
Proceeds from sales of assets	—			1
Acquisition of combustion turbine trust interest (Note 5)	(40		)	—
Restricted cash used to settle TCEH Demand Notes (Note 11)	680			—
Other changes in restricted cash	(5		)	64
Purchases of environmental allowances and credits	(10		)	(13		)
Proceeds from sales of nuclear decommissioning trust fund securities	105			31
Investments in nuclear decommissioning trust fund securities	(112		)	(38		)
Other, net	6			1
Cash provided by (used in) investing activities	323			(454		)
Net change in cash and cash equivalents	(350		)	237
Cash and cash equivalents — beginning balance	1,913			826
Cash and cash equivalents — ending balance	$	1,563		$	1,063

See Notes to Financial Statements.

3

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2013			December 31, 2012
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	1,563		$	1,913
Restricted cash (Note 13)	5			680
Trade accounts receivable — net (includes $508 and $445 in pledged amounts related to a VIE (Notes 2 and 4))	751			718
Inventories (Note 13)	442			393
Commodity and other derivative contractual assets (Note 9)	1,293			1,595
Margin deposits related to commodity positions	45			71
Other current assets	74			143
Total current assets	4,173			5,513
Restricted cash (Note 13)	947			947
Receivable from unconsolidated subsidiary (Note 11)	831			825
Investment in unconsolidated subsidiary (Note 2)	5,913			5,850
Other investments (Note 13)	820			767
Property, plant and equipment — net (Note 13)	18,348			18,705
Goodwill (Note 3)	4,952			4,952
Identifiable intangible assets — net (Note 3)	1,708			1,755
Commodity and other derivative contractual assets (Note 9)	311			586
Other noncurrent assets, primarily unamortized debt amendment and issuance costs	1,104			1,070
Total assets	$	39,107		$	40,970
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (includes $119 and $82 related to a VIE (Notes 2 and 5))	$	2,173		$	2,136
Long-term debt due currently (Note 5)	40			103
Trade accounts payable	420			394
Net payables due to unconsolidated subsidiary (Note 11)	92			19
Commodity and other derivative contractual liabilities (Note 9)	960			1,044
Margin deposits related to commodity positions	434			600
Accumulated deferred income taxes	41			48
Accrued interest	524			571
Other current liabilities	345			353
Total current liabilities	5,029			5,268
Accumulated deferred income taxes	3,567			2,828
Commodity and other derivative contractual liabilities (Note 9)	1,080			1,556
Long-term debt, less amounts due currently (Note 5)	38,108			37,815
Other noncurrent liabilities and deferred credits (Note 13)	2,884			4,426
Total liabilities	50,668			51,893
Commitments and Contingencies (Note 6)
Equity (Note 7):
EFH Corp. shareholders' equity	(11,665		)	(11,025		)
Noncontrolling interests in subsidiaries	104			102
Total equity	(11,561		)	(10,923		)
Total liabilities and equity	$	39,107		$	40,970

See Notes to Financial Statements.

4

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

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.

EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. 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. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor Holdings, a holding company that holds an approximate 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor and 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 2).

TCEH operates largely in the ERCOT market, and wholesale electricity prices in that market have generally moved with the price of natural gas. Wholesale electricity prices have significant implications to TCEH's profitability and cash flows and, accordingly, the value of its business.

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, consisting largely of TCEH, and the Regulated Delivery segment, consisting largely of our investment in Oncor. See Note 12 for further information concerning reportable business segments.

Liquidity Considerations

EFH Corp.'s competitive business has been and is expected to continue to be adversely affected by the sustained decline in natural gas prices and its effect on wholesale and retail electricity prices in ERCOT. Further, the remaining natural gas hedges that TCEH entered into when forward market prices of natural gas were significantly higher than current prices will mature in 2013 and 2014. These market conditions challenge the long-term profitability and operating cash flows of EFH Corp.'s competitive businesses and the ability to support their significant interest payments and debt maturities, and could adversely impact their ability to obtain additional liquidity and service, refinance and/or extend the maturities of their outstanding debt.

Note 5 provides the details of EFH Corp.'s and its consolidated subsidiaries' short-term borrowings and long-term debt, including principal amounts and maturity dates, as well as details of debt activity in 2013, including the three-year extension of the portion of the TCEH Revolving Credit Facility that would have expired in 2013. At June 30, 2013, TCEH has $1.1 billion of cash and cash equivalents and $133 million of available capacity under its letter of credit facility. Based on the current forecast of cash from operating activities, which reflects current forward market electricity prices, projected capital expenditures and other cash flows, we expect that TCEH will have sufficient liquidity to meet its obligations until October 2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures. TCEH's ability to satisfy this obligation is dependent upon the implementation of one or more of the actions described immediately below.

5

EFH Corp. and its subsidiaries (other than Oncor Holdings and its subsidiaries) continue to consider and evaluate possible transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and will likely from time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives. These transactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debt of EFH Corp., EFIH, EFCH and TCEH into equity of EFH Corp., EFIH, EFCH, TCEH and/or any of their subsidiaries. These actions could result in holders of EFH Corp., EFIH, EFCH and TCEH debt instruments not recovering the full principal amount of those obligations.

Discussions with Creditors

In March and April 2013, we engaged in discussions with certain unaffiliated holders of first lien senior secured claims against EFCH, TCEH and certain of TCEH's subsidiaries (the EFCH and Subsidiaries Creditors) with respect to our capital structure, including the possibility of a restructuring transaction. During the discussions, proposed changes to our capital structure were presented to the EFCH and Subsidiaries Creditors. The proposed changes included a consensual restructuring of TCEH's debt under which EFCH, TCEH, and certain of TCEH's subsidiaries would implement a prepackaged plan of reorganization by commencing voluntary cases under Chapter 11 of the United States Bankruptcy Code. Under this proposed plan, the TCEH first lien creditors would exchange their claims for a combination of EFH Corp. equity and cash or new long-term debt of TCEH, and the Sponsors would continue to hold an equity investment in EFH Corp. The Sponsors communicated a willingness to contribute new equity capital to EFH Corp. to facilitate implementation of the proposed plan in an amount that would provide substantial additional liquidity to EFH Corp. and EFIH, provided that in such circumstances the Sponsors would receive additional equity of EFH Corp. Following implementation of the proposed plan, EFH Corp. would continue to hold all of the equity interests in EFCH and EFIH, EFCH would continue to hold all of the equity interests in TCEH, and EFIH would continue to hold all of the equity interests in Oncor Holdings. We and the EFCH and Subsidiaries Creditors have not reached agreement on the terms of any change in our capital structure.

The company has engaged in additional discussions regarding possible changes to our capital structure with the advisors to the EFCH and Subsidiaries Creditors, EFIH creditors and other creditors. We will continue to consider and evaluate a range of future changes to our capital structure, in addition to the proposed changes described above, which may include filing a voluntary case under Chapter 11 of the United States Bankruptcy Code for some or all of EFH Corp. and its subsidiaries (excluding the Oncor Ring-Fenced Entities).

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in our 2012 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 Note 2). 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. Any 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 our 2012 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.

6

2. 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). 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. The maximum exposure to loss from our interests in VIEs does not exceed our carrying value.

Oncor Holdings, an indirect wholly owned subsidiary of EFH Corp. that holds an approximate 80% interest in Oncor, is not consolidated in EFH Corp.'s financial statements, and instead is accounted for as an equity method investment, 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. In accordance with accounting standards, we account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, based on our level of influence over its activities. See below for additional information about our equity method investment in Oncor Holdings. There are no other material investments accounted for under the equity or cost method.

Consolidated VIEs

See discussion in Note 4 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 7).

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

Assets:	June 30, 2013		December 31, 2012		Liabilities:	June 30, 2013		December 31, 2012
Cash and cash equivalents	$	32	$	43	Short-term borrowings	$	119	$	82
Accounts receivable	508		445		Trade accounts payable	1		1
Property, plant and equipment	137		134		Other current liabilities	10		7
Other assets, including $3 million and $12 million of current assets	11		16
Total assets	$	688	$	638	Total liabilities	$	130	$	90

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 assets to settle the obligations of the VIE.

7

Non-Consolidation of Oncor and Oncor Holdings

Our investment in unconsolidated subsidiary as presented in the balance sheet totaled $5.913 billion and $5.850 billion at June 30, 2013 and December 31, 2012, respectively, and consists almost entirely of our interest in Oncor Holdings, which we account for under the equity method as described above. Oncor provides services, principally electricity distribution, to TCEH's retail operations, and the related revenues represented 27% and 29% of Oncor Holdings' consolidated operating revenues for the six months ended June 30, 2013 and 2012, respectively.

See Note 11 for discussion of Oncor Holdings' and Oncor's transactions with EFH Corp. and its other subsidiaries.

Distributions from Oncor Holdings —Oncor Holdings' distributions of earnings to us totaled $80 million and $69 million for the six months ended June 30, 2013 and 2012, respectively. Distributions may not be paid except to the extent Oncor maintains a required regulatory capital structure as discussed below. At June 30, 2013, $143 million was eligible to be distributed to Oncor's members after taking into account the regulatory capital structure limit, of which approximately 80% relates to our ownership interest in Oncor. The boards of directors of each of Oncor and Oncor Holdings can withhold distributions to the extent the applicable board determines in good faith that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings.

Oncor's distributions are limited by its regulatory capital structure, which is required to 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. At June 30, 2013, Oncor's regulatory capitalization ratio was 59.0% debt and 41.0% 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 bonds issued by Oncor Electric Delivery Transition Bond Company, which were issued in 2003 and 2004 to recover specific generation-related regulatory assets and other qualified costs. 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).

In addition to distributions of earnings, under a tax sharing agreement we received income tax payments from Oncor and Oncor Holdings totaling $53 million and $37 million in the six months ended June 30, 2013 and 2012, respectively (see Note 11).

Oncor Holdings Financial Statements —Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the three and six months ended June 30, 2013 and 2012 are presented below:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Operating revenues	$	857		$	828		$	1,674		$	1,611
Operation and maintenance expenses	(307		)	(285		)	(605		)	(581		)
Depreciation and amortization	(202		)	(192		)	(401		)	(376		)
Taxes other than income taxes	(101		)	(98		)	(203		)	(200		)
Other income	5			7			10			14
Other deductions	(4		)	(1		)	(8		)	(3		)
Interest income	1			12			2			21
Interest expense and related charges	(95		)	(92		)	(189		)	(183		)
Income before income taxes	154			179			280			303
Income tax expense	(61		)	(75		)	(102		)	(126		)
Net income	93			104			178			177
Net income attributable to noncontrolling interests	(19		)	(21		)	(37		)	(36		)
Net income attributable to Oncor Holdings	$	74		$	83		$	141		$	141

8

Assets and liabilities of Oncor Holdings at June 30, 2013 and December 31, 2012 are presented below:

	June 30, 2013		December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	12	$	45
Restricted cash	45		55
Trade accounts receivable — net	372		338
Trade accounts and other receivables from affiliates	139		53
Inventories	67		73
Accumulated deferred income taxes	58		26
Prepayments and other current assets	100		82
Total current assets	793		672
Restricted cash	16		16
Other investments	86		83
Property, plant and equipment — net	11,693		11,318
Goodwill	4,064		4,064
Regulatory assets — net	1,647		1,788
Other noncurrent assets	80		78
Total assets	$	18,379	$	18,019
LIABILITIES
Current liabilities:
Short-term borrowings	$	960	$	735
Long-term debt due currently	128		125
Trade accounts payable — nonaffiliates	109		121
Income taxes payable to EFH Corp.	47		34
Accrued taxes other than income	93		153
Accrued interest	95		95
Other current liabilities	106		110
Total current liabilities	1,538		1,373
Accumulated deferred income taxes	1,853		1,736
Investment tax credits	22		24
Long-term debt, less amounts due currently	5,444		5,400
Other noncurrent liabilities and deferred credits	1,927		1,999
Total liabilities	$	10,784	$	10,532

3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides information regarding our goodwill balance, all of which relates to the Competitive Electric segment and arose in connection with accounting for the Merger. There were no changes to the goodwill balance for the three and six months ended June 30, 2013. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges	$	18,342
Accumulated impairment charges	(13,390		)
Balance at June 30, 2013 and December 31, 2012	$	4,952

In the first quarter 2013, we finalized the fair value calculations supporting the $1.2 billion noncash goodwill impairment charge related to the Competitive Electric segment that was recorded in the fourth quarter 2012. No additional impairment was recorded.

9

Identifiable Intangible Assets

Identifiable intangible assets, including amounts that arose in connection with accounting for the Merger, are comprised of the following:

	June 30, 2013						December 31, 2012
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	390	$	73	$	463	$	378	$	85
Favorable purchase and sales contracts	552		327		225		552		314		238
Capitalized in-service software	353		186		167		356		174		182
Environmental allowances and credits	596		399		197		594		393		201
Mining development costs	177		97		80		163		82		81
Total intangible assets subject to amortization	$	2,141	$	1,399	742		$	2,128	$	1,341	787
Retail trade name (not subject to amortization)					955						955
Mineral interests (not currently subject to amortization)					11						13
Total intangible assets					$	1,708					$	1,755

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

Identifiable Intangible Asset	Income Statement Line	Segment	Three Months Ended June 30,				Six Months Ended June 30,
			2013		2012		2013		2012
Retail customer relationship	Depreciation and amortization	Competitive Electric	$	6	$	8	$	12	$	17
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	Competitive Electric	7		8		13		15
Capitalized in-service software	Depreciation and amortization	Competitive Electric and Corporate and Other	11		10		21		19
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	Competitive Electric	3		4		6		9
Mining development costs	Depreciation and amortization	Competitive Electric	7		7		15		13
Total amortization expense			$	34	$	37	$	67	$	73

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

Year	Estimated Amortization Expense
2013	$	140
2014	$	118
2015	$	109
2016	$	89
2017	$	69

10

4. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

Under an accounts receivable securitization program, TXU Energy (originator) sells all of its trade accounts receivable to TXU Energy Receivables Company LLC (TXU Energy 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 subsidiary of TCEH. TXU Energy Receivables Company borrows funds from a financial institution using the accounts receivable as collateral.

The trade accounts receivable amounts under the program are reported in the financial statements as pledged balances, and the related funding amounts are reported as short-term borrowings.

The maximum funding amount currently available under the program is $200 million, which approximates the expected usage and applies only to receivables related to non-executory retail sales contracts. Program funding increased to $119 million at June 30, 2013 from $82 million at December 31, 2012. Because TCEH's credit ratings were lower than Ba3/BB-, under the terms of the program available funding is reduced by the amount of customer deposits held by the originator, which totaled $34 million at June 30, 2013.

TXU Energy Receivables Company issues a subordinated note payable to the originator in an amount equal to the difference between the face amount of the accounts receivable purchased, less a discount, and cash paid to the originator. Because the subordinated note is limited to 25% of the uncollected accounts receivable purchased, and the amount of borrowings is limited by terms of the financing agreement, any additional funding to purchase the receivables is sourced from cash on hand, which totaled $21 million at June 30, 2013, and/or capital contributions from TCEH. Under the program, the subordinated note issued by TXU Energy Receivables Company is subordinated to the security interests of the financial institution. The balance of the subordinated note payable, which is eliminated in consolidation, totaled $96 million and $97 million at June 30, 2013 and December 31, 2012, respectively.

All new trade receivables under the program generated by the originator are continuously purchased by TXU Energy Receivables Company with the proceeds from collections of receivables previously purchased and, as necessary, increased borrowings or funding sources as described immediately above. Changes in the amount of borrowings by TXU Energy 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.

The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the financial institution. 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 Energy Receivables Company to TXU Energy, which provides recordkeeping services and is the collection agent under the program.

Program fee amounts were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Program fees	$	1		$	2		$	3		$	4
Program fees as a percentage of average funding (annualized)	7.1		%	7.8		%	6.5		%	7.4		%

11

Activities of TXU Energy Receivables Company and its predecessor, TXU Receivables Company, were as follows:

	Six Months Ended June 30,
	2013			2012
Cash collections on accounts receivable	$	1,879		$	2,111
Face amount of new receivables purchased (a)	(1,942		)	(2,131		)
Discount from face amount of purchased receivables	16			5
Program fees paid to financial institution	(3		)	(4		)
Servicing fees paid for recordkeeping and collection services	—			(1		)
Decrease in subordinated notes payable	(1		)	(18		)
Decrease in cash held	13			—
Other — net	1			—
Cash flows provided to originator under the program	$	(37	)	$	(38	)

____________

(a) Net of allowance for uncollectible accounts.

The program expires in November 2015, but the expiration date will change to June 2014 if at that time more than $500 million aggregate principal amount of the term loans and deposit letter of credit loans under the TCEH Senior Secured Facilities maturing prior to October 2017 remain outstanding. The program is subject to the same financial maintenance covenant as the TCEH Senior Credit Facilities as discussed in Note 8 to Financial Statements in our 2012 Form 10-K. The program 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 outstanding ratio exceed stated thresholds, unless the financial institution waives such events of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Energy Receivables Company defaults in any payment with respect to debt in excess of $50,000 in the aggregate, or if EFH Corp., TCEH, any affiliate of TCEH acting as collection agent, any parent guarantor of the originator or the originator defaults in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. At June 30, 2013, there were no such events of termination. Further, TCEH has the unilateral right to terminate the facility at any time.

If the program was terminated, TCEH's liquidity would be reduced because collections of sold receivables would be used by TXU Energy Receivables Company to repay borrowings from the financial institution instead of purchasing new receivables. We expect that the level of cash flows would normalize in approximately 10 to 24 days following termination.

Trade Accounts Receivable

	June 30, 2013			December 31, 2012
Wholesale and retail trade accounts receivable	$	762		$	727
Allowance for uncollectible accounts	(11		)	(9		)
Trade accounts receivable — reported in balance sheet, including $508 and $445 in pledged retail receivables	$	751		$	718

Gross trade accounts receivable at June 30, 2013 and December 31, 2012 included unbilled revenues of $283 million and $260 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Six Months Ended June 30,
	2013			2012
Allowance for uncollectible accounts receivable at beginning of period	$	9		$	27
Increase for bad debt expense	13			11
Decrease for account write-offs	(11		)	(20		)
Allowance for uncollectible accounts receivable at end of period	$	11		$	18

12

5. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At June 30, 2013, outstanding short-term borrowings totaled $2.173 billion, which included $2.054 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.69%, excluding customary fees, and $119 million under the accounts receivable securitization program discussed in Note 4.

At December 31, 2012, outstanding short-term borrowings totaled $2.136 billion, which included $2.054 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.40%, excluding customary fees, and $82 million under the accounts receivable securitization program.

Credit Facilities

Credit facilities and related cash borrowings at June 30, 2013 are presented below. Available letter of credit capacity totaled $133 million at June 30, 2013 as discussed below. The facilities are all senior secured facilities of TCEH.

		June 30, 2013
Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)	October 2016	$	2,054	$	—	$	2,054	$	—
TCEH Letter of Credit Facility (b)	October 2017 (b)	1,062		—		1,062		—
Total TCEH		$	3,116	$	—	$	3,116	$	—

___________

(a) Facility used for borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. At June 30, 2013, borrowings under the facility bear interest at LIBOR plus 4.50%, 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. In January 2013, commitments previously maturing in 2013 were extended to 2016 as discussed below.

(b) Facility, $42 million of which matures in October 2014, 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 secured by a first-lien interest in the assets of TCEH. The borrowings under this facility have been recorded by TCEH as restricted cash that supports issuances of letters of credit and are classified as long-term debt. At June 30, 2013, the restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009 related to an office building financing. At June 30, 2013, the restricted cash supports $814 million in letters of credit outstanding, leaving $133 million in available letter of credit capacity.

Amendment and Extension of TCEH Revolving Credit Facility — In January 2013, the Credit Agreement governing the TCEH Senior Secured Facilities was amended to extend the maturity date of the $645 million of commitments maturing in October 2013 to October 2016, bringing the maturity date of all commitments under the TCEH Revolving Credit Facility totaling $2.054 billion to October 2016. The extended commitments have the same terms and conditions as the existing commitments expiring in October 2016 under the Credit Agreement. Fees in consideration for the extension were settled through the incurrence of $340 million principal amount of incremental term loans under the TCEH Term Loan Facilities maturing in October 2017. In connection with the extension request, TCEH eliminated its ability to draw letters of credit under the TCEH Revolving Credit Facility. At the date of the extension, there were no outstanding letters of credit under the TCEH Revolving Credit Facility.

13

Long-Term Debt

At June 30, 2013 and December 31, 2012, long-term debt consisted of the following:

	June 30, 2013			December 31, 2012
EFH Corp. (parent entity)
9.75% Fixed Senior Notes due October 15, 2019	$	2		$	115
10% Fixed Senior Notes due January 15, 2020	3			1,061
10.875% Fixed Senior Notes due November 1, 2017 (a)	33			64
11.25 / 12.00% Senior Toggle Notes due November 1, 2017 (a)	27			60
5.55% Fixed Series P Senior Notes due November 15, 2014 (a)	90			92
6.50% Fixed Series Q Senior Notes due November 15, 2024 (a)	201			230
6.55% Fixed Series R Senior Notes due November 15, 2034 (a)	291			291
8.82% Building Financing due semiannually through February 11, 2022 (b)	50			53
Unamortized fair value premium related to Building Financing (b)(c)	10			11
Unamortized fair value discount (c)	(126		)	(137		)
Total EFH Corp.	581			1,840
EFIH
6.875% Fixed Senior Secured First Lien Notes due August 15, 2017	503			503
10% Fixed Senior Secured First Lien Notes due December 1, 2020	3,482			2,180
11% Fixed Senior Secured Second Lien Notes due October 1, 2021	406			406
11.75% Fixed Senior Secured Second Lien Notes due March 1, 2022	1,750			1,750
11.25 / 12.25% Senior Toggle Notes due December 1, 2018	1,476			1,304
9.75% Fixed Senior Notes due October 15, 2019	2			141
Unamortized premium	323			351
Unamortized discount	(152		)	(131		)
Total EFIH	7,790			6,504
EFCH
9.58% Fixed Notes due in annual installments through December 4, 2019 (d)	35			35
8.254% Fixed Notes due in quarterly installments through December 31, 2021 (d)	37			39
1.074% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (e)	1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037	8			8
Unamortized fair value discount (c)	(7		)	(7		)
Total EFCH	74			76
TCEH
Senior Secured Facilities:
3.720% TCEH Term Loan Facilities maturing October 10, 2014 (e)(f)	3,809			3,809
3.695% TCEH Letter of Credit Facility maturing October 10, 2014 (e)	42			42
4.719% TCEH Term Loan Facilities maturing October 10, 2017 (a)(e)(f)	15,691			15,351
4.695% TCEH Letter of Credit Facility maturing October 10, 2017 (e)	1,020			1,020
11.5% Fixed Senior Secured Notes due October 1, 2020	1,750			1,750
15% Fixed Senior Secured Second Lien Notes due April 1, 2021	336			336
15% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B	1,235			1,235
10.25% Fixed Senior Notes due November 1, 2015 (a)	1,833			1,833
10.25% Fixed Senior Notes due November 1, 2015, Series B (a)	1,292			1,292
10.50 / 11.25% Senior Toggle Notes due November 1, 2016	1,749			1,749

14

	June 30, 2013			December 31, 2012
Pollution Control Revenue Bonds:
Brazos River Authority:
5.40% Fixed Series 1994A due May 1, 2029	$	39		$	39
7.70% Fixed Series 1999A due April 1, 2033	111			111
6.75% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (g)	—			16
7.70% Fixed Series 1999C due March 1, 2032	50			50
8.25% Fixed Series 2001A due October 1, 2030	71			71
8.25% Fixed Series 2001D-1 due May 1, 2033	171			171
0.087% Floating Series 2001D-2 due May 1, 2033 (h)	97			97
0.275% Floating Taxable Series 2001I due December 1, 2036 (i)	62			62
0.087% Floating Series 2002A due May 1, 2037 (h)	45			45
6.75% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (g)	—			44
6.30% Fixed Series 2003B due July 1, 2032	39			39
6.75% Fixed Series 2003C due October 1, 2038	52			52
5.40% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (g)	31			31
5.00% Fixed Series 2006 due March 1, 2041	100			100
Sabine River Authority of Texas:
6.45% Fixed Series 2000A due June 1, 2021	51			51
5.20% Fixed Series 2001C due May 1, 2028	70			70
5.80% Fixed Series 2003A due July 1, 2022	12			12
6.15% Fixed Series 2003B due August 1, 2022	45			45
Trinity River Authority of Texas:
6.25% Fixed Series 2000A due May 1, 2028	14			14
Unamortized fair value discount related to pollution control revenue bonds (c)	(108		)	(112		)
Other:
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017	45			—
7.46% Fixed Secured Facility Bonds with amortizing payments through January 2015	4			12
7% Fixed Senior Notes due March 15, 2013	—			5
Capital leases	58			64
Other	3			3
Unamortized discount	(116		)	(10		)
Unamortized fair value discount (c)	—			(1		)
Total TCEH	29,703			29,498
Total EFH Corp. consolidated	38,148			37,918
Less amount due currently	(40		)	(103		)
Total long-term debt	$	38,108		$	37,815

___________

(a) Excludes the following debt held by EFIH or EFH Corp. (parent entity) and eliminated in consolidation:

	June 30, 2013		December 31, 2012
EFH Corp. 10.875% Fixed Senior Notes due November 1, 2017	$	—	$	1,685
EFH Corp. 11.25 / 12.00% Senior Toggle Notes due November 1, 2017	—		3,441
EFH Corp. 5.55% Fixed Series P Senior Notes due November 15, 2014	281		279
EFH Corp. 6.50% Fixed Series Q Senior Notes due November 15, 2024	545		516
EFH Corp. 6.55% Fixed Series R Senior Notes due November 15, 2034	456		456
TCEH 4.719% Term Loan Facilities maturing October 10, 2017	19		19
TCEH 10.25% Fixed Senior Notes due November 1, 2015	213		213
TCEH 10.25% Fixed Senior Notes due November 1, 2015, Series B	150		150
Total	$	1,664	$	6,759

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(b) This financing is the obligation of a subsidiary of EFH Corp. and will be serviced with cash drawn by the beneficiary of a letter of credit that was previously issued to secure the obligation.

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

(d) EFCH's obligations with respect to these financings are guaranteed by EFH Corp. and secured on a first-priority basis by, among other things, an undivided interest in the Comanche Peak nuclear generation facility.

(e) Interest rates in effect at June 30, 2013.

(f) Interest rate swapped to fixed on $18.265 billion principal amount of maturities through October 2014 and up to an aggregate $12.6 billion principal amount from October 2014 through October 2017.

(g) 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.

(h) Interest rates in effect at June 30, 2013. 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.

(i) Interest rate in effect at June 30, 2013. 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.

Debt Amounts Due Currently

Amounts due currently (within twelve months) at June 30, 2013 total $40 million and consist of scheduled installment payments on capital leases and debt securities.

Debt Related Activity in 2013

Principal amounts of long-term debt issued in the six months ended June 30, 2013 totaled $1.731 billion and consisted of $340 million principal amount of incremental term loans under the TCEH Term Loan Facilities discussed in “Amendment and Extension of TCEH Revolving Credit Facility” above and $1.302 billion of EFIH 10% Notes and $89 million of EFIH Toggle Notes issued in exchanges discussed below.

Repayments of long-term debt in the six months ended June 30, 2013 totaled $81 million and consisted of $75 million of payments of principal at scheduled maturity or mandatory tender and remarketing dates (including $60 million of pollution control revenue bonds) and $6 million of contractual payments under capital leases.

In April 2013, TCEH acquired for $40 million in cash the owner participant interest in a trust established to lease six natural gas-fueled combustion turbines to TCEH. The interest in the trust was held by an unaffiliated party. The trust was consolidated in the second quarter 2013. No gain or loss was recognized on the transaction. The estimated fair value of the combustion turbine assets of $83 million approximated the total of the estimated fair value of the debt assumed and cash paid. In recording the combustion turbine assets, the fair value was reduced by the remaining deferred lease liability and the unamortized lease valuation reserve established in accounting for the Merger, which were reversed and totaled $18 million. At June 30, 2013, the principal amount of the trust's debt totaled $45 million and is payable in semiannual installments through January 1, 2017.

EFIH Debt Exchanges and Distributions Involving EFH Corp. Debt —In exchanges in January 2013, EFIH and EFIH Finance issued $1.302 billion principal amount of EFIH 10% Senior Secured Notes due 2020 (New EFIH 10% Notes) in exchange for $1.310 billion total principal amount of EFH Corp. and EFIH senior secured notes consisting of: (i) $113 million principal amount of EFH Corp. 9.75% Senior Secured Notes due 2019 (EFH Corp. 9.75% Notes), (ii) $1.058 billion principal amount of EFH Corp. 10% Senior Secured Notes due 2020 (EFH Corp. 10% Notes), and (iii) $139 million principal amount of EFIH 9.75% Senior Secured Notes due 2019 (EFIH 9.75% Notes). The New EFIH 10% Notes have terms and conditions substantially the same as the existing EFIH 10% Notes discussed below. EFIH cancelled the EFIH notes it received in the exchanges.

In connection with these debt exchange transactions, EFH Corp. received the requisite consents from holders of the EFH Corp. 9.75% Notes and EFH Corp. 10% Notes and EFIH received the requisite consents from holders of the EFIH 9.75% Notes to certain amendments to the respective indentures governing such notes. These amendments, among other things, (i) eliminated EFIH's pledge of its 100% ownership of the membership interests it owns in Oncor Holdings as collateral for the EFIH 9.75% Notes, (ii) made EFCH and EFIH unrestricted subsidiaries under the EFH Corp. 9.75% Notes and EFH Corp. 10% Notes, thereby eliminating EFCH's unsecured and EFIH's secured guarantees of the notes, (iii) eliminated substantially all of the restrictive covenants in the indentures and (iv) eliminated certain events of default, modified covenants regarding mergers and consolidations and modified or eliminated certain other provisions in these indentures.

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In additional exchanges in January 2013, EFIH and EFIH Finance issued $89 million principal amount of additional 11.25%/12.25% Toggle Notes due 2018 (EFIH Toggle Notes) in exchange for $95 million total principal amount of EFH Corp. senior notes consisting of: (i) $31 million principal amount of EFH Corp. 10.875% Senior Notes due 2017 (EFH Corp. 10.875% Notes), (ii) $33 million principal amount of EFH Corp. 11.25%/12.00% Senior Toggle Notes due 2017 (EFH Corp. Toggle Notes), (iii) $2 million principal amount of EFH Corp. 5.55% Series P Notes due 2014 (EFH Corp. 5.55% Notes) and (iv) $29 million principal amount of EFH Corp. 6.50% Series Q Notes due 2024 (EFH Corp. 6.50% Notes). The additional EFIH Toggle Notes have the same terms and conditions as the existing EFIH Toggle Notes discussed below.

In the first quarter 2013, EFIH distributed $6.360 billion principal amount of EFH Corp. debt that it previously received in debt exchanges, including $1.235 billion received in January 2013, as a dividend to EFH Corp., which cancelled the notes, leaving $1.361 billion principal amount of affiliate debt still held by EFIH. The dividend included $1.715 billion principal amount of EFH Corp. 10.875% Notes, $3.474 billion principal amount of EFH Corp. Toggle Notes, $1.058 billion principal amount of EFH Corp. 10% Notes and $113 million principal amount of EFH Corp. 9.75% Notes.

Accounting and Income Tax Effects of the January 2013 Debt Exchanges — In consideration of the circumstances and terms of the exchanges, accounting rules require that the net loss on the exchanges, which totaled $21 million, be deferred and amortized to interest expense over the life of the debt issued. The deferred loss is reported as debt discount associated with the EFIH 10% Notes and EFIH Toggle Notes. For federal income tax purposes, the transactions resulted in cancellation of debt income of $11 million that was offset by operating losses.

Information Regarding Other Significant Outstanding Debt

TCEH Senior Secured Facilities —Borrowings under the TCEH Senior Secured Facilities totaled $22.616 billion at June 30, 2013 and consisted of:

• $3.809 billion of TCEH Term Loan Facilities maturing in October 2014 with interest payable at LIBOR plus 3.50%;

• $15.691 billion of TCEH Term Loan Facilities maturing in October 2017 with interest payable at LIBOR plus 4.50%;

• $42 million of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2014 with interest payable at LIBOR plus 3.50% (see discussion under "Credit Facilities" above);

• $1.020 billion of cash borrowed under the TCEH Letter of Credit Facility maturing in October 2017 with interest payable at LIBOR plus 4.50% (see discussion under "Credit Facilities" above), and

• Amounts borrowed under the TCEH Revolving Credit Facility, which may be reborrowed from time to time until October 2016 and represent the entire amount of commitments under the facility totaling $2.054 billion at June 30, 2013. See "Credit Facilities" above for discussion regarding the maturity date extension of $645 million in commitments from 2013 to 2016.

Each of the loans described above that matures in 2016 or 2017 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 at March 31, 2011 to the extent held at the determination date as defined in the Credit Agreement) 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 at March 31, 2011 to the extent held at the determination date as defined in the Credit Agreement), 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 fully and 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.

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TCEH 11.5% Senior Secured Notes —At June 30, 2013, the principal amount of the TCEH 11.5% Senior Secured Notes totaled $1.750 billion. The notes mature in October 2020, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1, at a fixed rate of 11.5% per annum. The notes are fully and 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 notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness of TCEH, (ii) senior in right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of the TCEH Collateral and (iii) 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.

TCEH 15% Senior Secured Second Lien Notes(including Series B)— At June 30, 2013, the principal amount of the TCEH 15% Senior Secured Second Lien Notes totaled $1.571 billion. 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. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Facilities on a first-priority basis, 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 notes are senior obligations of the issuer and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, the TCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

TCEH 10.25% Senior Notes (including Series B) and 10.50/11.25% Senior Toggle Notes (collectively, the TCEH Senior Notes)— At June 30, 2013, the principal amount of the TCEH Senior Notes totaled $4.874 billion, excluding $363 million aggregate principal amount held by EFH Corp. and EFIH, and the notes are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH's direct parent, EFCH (which owns 100% of TCEH), and by each subsidiary that guarantees the TCEH Senior Secured Facilities. 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 TCEH 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 .

EFIH 6.875% Senior Secured Notes — At June 30, 2013, the principal amount of the EFIH 6.875% Notes totaled $503 million. These notes mature in August 2017, with interest payable in cash semiannually in arrears on February 15 and August 15 at a fixed rate of 6.875% per annum. The EFIH 6.875% Notes are secured on a first-priority basis by EFIH's pledge of its 100% ownership of the membership interests in Oncor Holdings (the EFIH Collateral) on an equal and ratable basis with the EFIH 10% Notes.

The EFIH 6.875% Notes are senior obligations of EFIH and rank equally in right of payment with all senior indebtedness of EFIH and are senior in right of payment to any future subordinated indebtedness of EFIH. The EFIH 6.875% Notes are effectively senior to all second lien and unsecured indebtedness of EFIH, to the extent of the value of the EFIH Collateral, and are effectively subordinated to any indebtedness of EFIH secured by assets of EFIH other than the EFIH Collateral, to the extent of the value of such assets. Furthermore, the EFIH 6.875% Notes are structurally subordinated to all indebtedness and other liabilities of EFIH's subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries. The holders of the EFIH 6.875% Notes vote as a separate class from the holders of the EFIH 10% Notes.

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The EFIH 6.875% Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH 6.875% Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH 6.875% Notes. If an exchange offer for the notes is not completed within 365 days after the date (August 14, 2012) the initial EFIH 6.875% Notes were issued (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.

EFIH 10% Senior Secured Notes — At June 30, 2013, the principal amount of the EFIH 10% Notes totaled $3.482 billion. The notes mature in December 2020, with interest payable in cash semiannually in arrears on June 1 and December 1 at a fixed rate of 10% per annum. The notes are secured by the EFIH Collateral on an equal and ratable basis with the EFIH 6.875% Notes.

The EFIH 10% Notes are senior obligations of EFIH and rank equally in right of payment with all existing and future senior indebtedness of EFIH, including the EFIH 6.875% Notes. The EFIH 10% Notes have substantially the same terms, covenants and events of default as the EFIH 6.875% Notes. The holders of the EFIH 10% Notes vote as a separate class from the holders of the EFIH 6.875% Notes.

EFIH 11% Senior Secured Second Lien Notes — At June 30, 2013, the principal amount of the EFIH 11% Notes totaled $406 million. The notes mature in October 2021, with interest payable in cash semiannually in arrears on May 15 and November 15 at a fixed rate of 11% per annum. The EFIH 11% Notes are secured on a second-priority basis by the EFIH Collateral on an equal and ratable basis with the EFIH 11.75% Notes.

The EFIH 11% Notes are senior obligations of EFIH and EFIH Finance 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 have substantially the same terms, covenants and events of default as the EFIH 11.75% Notes discussed below, and the holders of the EFIH 11% Notes will generally vote as a single class with the holders of the EFIH 11.75% Notes.

EFIH 11.75% Senior Secured Second Lien Notes —At June 30, 2013, the principal amount of the EFIH 11.75% Notes totaled $1.750 billion. These notes mature in March 2022, with interest payable in cash semiannually in arrears on March 1 and September 1 at a fixed rate of 11.75% per annum. The EFIH 11.75% Notes are secured on a second-priority basis by the EFIH Collateral on an equal and ratable basis with the EFIH 11% Notes. The EFIH 11.75% Notes have substantially the same covenants as the EFIH 11% Notes, and the holders of the EFIH 11.75% Notes will generally vote as a single class with the holders of the EFIH 11% Notes.

The EFIH 11.75% Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH 11.75% Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH 11.75% Notes. Because the exchange offer has not yet been completed, the annual interest rate on the EFIH 11.75% Notes increased by 25 basis points (to 12.00%) on February 5, 2013 and by an additional 25 basis points (to 12.25%) on May 6, 2013. The interest rate on the EFIH 11.75% Notes will remain at that level until completion of the exchange offer, at which time the interest rate on the notes will revert to 11.75%.

EFIH 11.25%/12.25% Senior Toggle Notes — At June 30, 2013, the principal amount of the EFIH Toggle Notes totaled $1.476 billion. These notes mature in December 2018, with interest payable semiannually in arrears on June 1 and December 1 at a fixed rate of 11.25% per annum for cash interest and 12.25% per annum for PIK Interest. For any interest period until June 1, 2016, EFIH 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 EFIH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once EFIH makes a PIK election, which it did effective with the June 1, 2013 interest payment, the election is valid for each succeeding interest payment period until EFIH revokes the election.

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The EFIH Toggle Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH Toggle Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable notes for the EFIH Toggle Notes. If an exchange offer for the notes is not completed within 365 days after the date (December 5, 2012) the initial EFIH Toggle notes were issued (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.

EFH Corp. 10.875% Senior Notes and 11.25/12.00% Senior Toggle Notes — At June 30, 2013, the collective principal amount of these notes totaled $60 million. The notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by EFCH and EFIH. The 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 at a fixed rate for the Toggle Notes of 11.25% per annum.

Fair Value of Long-Term Debt

At June 30, 2013 and December 31, 2012, the estimated fair value of our long-term debt (excluding capital leases) totaled $25.363 billion and $25.890 billion, respectively, and the carrying amount totaled $38.090 billion and $37.854 billion, respectively. At June 30, 2013 and December 31, 2012, the estimated fair value of our short-term borrowings under the TCEH Revolving Credit Facilities totaled $1.430 billion and $1.500 billion, respectively, and the carrying amount totaled $2.054 billion. We determine fair value in accordance with accounting standards as discussed in Note 8, and at June 30, 2013, our debt fair value represents Level 2 valuations. We obtain security pricing from a vendor who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.

TCEHInterest Rate Swap Transactions

TCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at June 30, 2013, TCEH has entered into the following series of interest rate swap transactions that effectively fix the interest rates at between 5.5% and 9.3%.

Fixed Rates				Expiration Dates	Notional Amount
5.5	%	-	9.3%	September 2013 through October 2014		$	18.265	billion (a)
6.8	%	-	9.0%	October 2015 through October 2017		$	12.600	billion (b)

___________

(a) Swaps related to an aggregate $600 million principal amount of debt expired in 2013. Per the terms of the transactions, the notional amount of swaps entered into in 2011 grew by $405 million in 2013, substantially offsetting the expired swaps.

(b) These swaps are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes $3 billion that expires in October 2015 with the remainder expiring in October 2017.

TCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achieved through the interest rate swaps. Basis swaps in effect at June 30, 2013 totaled $11.967 billion notional amount. The basis swaps relate to debt outstanding through 2014.

The interest rate swap counterparties are secured on an equal and ratable basis by the same collateral pledged to the lenders under the TCEH Senior Secured Facilities.

The interest rate swaps have resulted in net gains (losses) reported in interest expense and related charges as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Realized net loss	$	(155	)	$	(168	)	$	(306	)	$	(337	)
Unrealized net gain (loss)	338			(107		)	486			4
Total	$	183		$	(275	)	$	180		$	(333	)

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.579 billion and $2.065 billion at June 30, 2013 and December 31, 2012, respectively, of which $59 million and $65 million (both pretax), respectively, were reported in accumulated other comprehensive income.

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6. 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 Company operations—In connection with the sale of the assets of TXU Gas Company to Atmos Energy Corporation (Atmos) in October 2004, EFH Corp. agreed to indemnify Atmos, until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas Company, 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.

See Note 5 for discussion of guarantees and security for certain of our debt.

Letters of Credit

At June 30, 2013, TCEH has outstanding letters of credit under its credit facilities totaling $814 million as follows:

• $404 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);

• $65 million to support TCEH's REP financial requirements with the PUCT, and

• $137 million for miscellaneous credit support requirements.

Litigation

Aurelius Capital Master, Ltd. and ACP Master, Ltd. (Aurelius) filed a lawsuit in March 2013, amended in May 2013, in the United States District Court for the Northern District of Texas (Dallas Division) against EFCH as a nominal defendant and each of the current directors and a former director of EFCH. In the lawsuit, Aurelius, as a creditor under the TCEH Senior Secured Facilities and certain TCEH secured bonds, both of which are guaranteed by EFCH, filed a derivative claim against EFCH and its directors. Aurelius alleges that the directors of EFCH breached their fiduciary duties to EFCH and its creditors, including Aurelius, by permitting TCEH to make certain loans "without collecting fair and reasonably equivalent value." The lawsuit seeks recovery for the benefit of EFCH. In June 2013, EFCH and the directors filed a motion to dismiss this lawsuit. We cannot predict the outcome of this proceeding, including the financial effects, if any.

Litigation Related to Generation Facilities —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 sought a reversal of the TCEQ's order and a remand back to the TCEQ for further proceedings. The district court affirmed the TCEQ's issuance of the TPDES permit to Oak Grove. In December 2012, plaintiffs appealed the district court's decision to the Third Court of Appeals in Austin, Texas. The case has been fully briefed, but the Court has not issued a decision and no date for oral argument has been scheduled. While we cannot predict the timing or outcome of this proceeding, we believe the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.

21

In September 2010, the Sierra Club filed a lawsuit in the United States 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 (CAA) at Luminant's Martin Lake generation facility. In May 2012, the Sierra Club filed a lawsuit in the US District Court for the Western District of Texas (Waco Division) against EFH Corp. and Luminant Generation Company LLC for alleged violations of the CAA at Luminant's Big Brown generation facility. Both cases are currently scheduled for trial in November 2013. While we are unable to estimate any possible loss or predict the outcome, we believe that the Sierra Club's claims are without merit, and we intend to vigorously defend these lawsuits. In addition, in December 2010 and again in October 2011, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating CAA provisions in connection with Luminant's Monticello generation facility. In May 2012, the Sierra Club informed us that it may sue us for allegedly violating CAA provisions in connection with Luminant's Sandow 4 generation facility. While we cannot predict whether the Sierra Club will actually file suit regarding Monticello or Sandow 4 or the outcome of any resulting proceedings, we believe we have complied with the requirements of the CAA at all of our generation facilities.

See below for discussion of litigation regarding the CSAPR and the Texas State Implementation Plan.

Regulatory Reviews

In June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of the CAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, we received an additional information request from the EPA under Section 114 related to the Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to the Sandow 4 generation facility. 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.

In July 2012, the EPA sent us a notice of violation alleging noncompliance with the CAA's New Source Review Standards and the air permits at our Martin Lake and Big Brown generation facilities. In September 2012, we filed a petition for review in the United States Court of Appeals for the Fifth Circuit Court (Fifth Circuit Court) seeking judicial review of the EPA's notice of violation. Given recent legal precedent subjecting agency orders like the notice of violation to judicial review, we filed the petition for review to preserve our ability to challenge the EPA's issuance of the notice and its defects. In October 2012, the EPA filed a motion to dismiss our petition. In December 2012, the Fifth Circuit Court issued an order that will delay a ruling on the EPA's motion to dismiss until after the case has been fully briefed and oral argument, if any, is held.

In July 2013, the EPA sent us a second notice of violation alleging noncompliance with the CAA's New Source Review Standards at our Martin Lake and Big Brown generation facilities. In July 2013, we filed a petition for review in the Fifth Circuit Court seeking judicial review of the EPA's July 2013 notice of violation.

While we cannot predict whether the EPA will initiate enforcement proceedings under these notices of violation, we believe that we have complied with all requirements of the CAA at all of our generation facilities. We cannot predict the outcome of any resulting enforcement proceedings or estimate the penalties that might be assessed in connection with any such proceedings. We cannot predict the outcome of these proceedings, including the financial effects, if any.

Cross-State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of sulfur dioxide (SO₂) and nitrogen oxides (NO_x) emissions from our fossil-fueled generation units. In September 2011, we filed a petition for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) challenging the CSAPR as it applies to Texas. If the CSAPR had taken effect, it would have caused us to, among other actions, idle two lignite/coal-fueled generation units and cease certain lignite mining operations by the end of 2011.

22

In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule. In April 2012, we filed in the D.C. Circuit Court a petition for review of the Final Revisions on the ground, among others, that the rules do not include all of the budget corrections we requested from the EPA. The parties to the case agreed that the case should be held in abeyance pending the conclusion of the CSAPR rehearing proceeding discussed below. In June 2012, the EPA finalized the proposed rule (Second Revised Rule). As compared to the proposed revisions to the CSAPR issued by the EPA in October 2011, the Final Revisions and the Second Revised Rule finalize emissions budgets for our generation assets that are approximately 6% lower for SO₂, 3% higher for annual NO_x and 2% higher for seasonal NO_x.

In August 2012, the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for further proceedings. As a result, the CSAPR, the Final Revisions and the Second Revised Rule do not impose any immediate requirements on us, the State of Texas, or other affected parties. The D.C. Circuit Court's order stated that the EPA was expected to continue administering the CAIR (the predecessor rule to the CSAPR) pending the EPA's further consideration of the rule. In October 2012, the EPA and certain other parties that supported the CSAPR filed petitions with the D.C. Circuit Court seeking review by the full court of the panel's decision to vacate and remand the CSAPR. In January 2013, the D.C. Circuit Court denied these requests for rehearing, concluding the CSAPR rehearing proceeding. In March 2013, the EPA and certain other parties that supported the CSAPR submitted petitions to the US Supreme Court seeking its review of the D.C. Circuit Court decision. In June 2013, the US Supreme Court granted review of the D.C. Circuit Court's decision. The court will consider the case during its next term, which begins in October 2013. We cannot predict the outcome of the review by the US Supreme Court.

State Implementation Plan (SIP)

In September 2010, the EPA disapproved a portion of the State Implementation Plan pursuant to which the TCEQ implements its program to achieve the requirements of the CAA. The EPA disapproved the Texas standard permit for pollution control projects. We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. We challenged the EPA's disapproval by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ's adoption of the standard permit conditions for pollution control projects was consistent with the CAA. In March 2012, the Fifth Circuit Court vacated the EPA's disapproval of the Texas standard permit for pollution control projects and remanded the matter to the EPA for reconsideration. We cannot predict the timing or outcome of the EPA's reconsideration, including the financial effects, if any.

In November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacing that exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generation facility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicability of the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and received the generation facility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issued is consistent with the CAA. In July 2012, the Fifth Circuit Court denied our challenge and ruled that the EPA's actions were in accordance with the CAA. In October 2012, the Fifth Circuit Court panel withdrew its opinion and issued a second, expanded opinion that again upheld the EPA's disapproval. In November 2012, we filed a petition with the Fifth Circuit Court asking for review by the full Fifth Circuit Court of the panel's second opinion. Other parties to the proceedings also filed a petition with the Fifth Circuit Court asking the panel to reconsider its decision. In March 2013, the Fifth Circuit Court panel withdrew its second opinion and issued a third opinion that again upheld the EPA's actions. In April 2013, the Fifth Circuit Court also denied our November 2012 petition for rehearing of the panel's second opinion and denied the request by other parties for the panel to reconsider its second decision. Following the issuance of the mandate, we filed a motion to recall the mandate, which was denied in a single-judge order. In June 2013, we submitted a petition to the US Supreme Court seeking its review of the Fifth Circuit Court's decision. We cannot predict whether the US Supreme Court will grant or deny the petition or the outcome of any granted review.

Other Matters

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

23

7. EQUITY

Dividend Restrictions

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

The indenture governing the EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes includes 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, 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 11.9 to 1.0 at June 30, 2013.

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 7.8 to 1.0 at June 30, 2013. In addition, the EFIH Notes generally restrict EFIH's ability to make distributions or loans to EFH Corp., unless such distributions or loans are expressly permitted under the indentures governing the EFIH Notes.

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 distribution, TCEH's consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. At June 30, 2013, the ratio was 10.1 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.

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

Noncontrolling Interests

As discussed in Note 2, we consolidate a joint venture formed in 2009 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, 2013 and 2012.

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Equity

The following table presents the changes to equity for the six months ended June 30, 2013:

	EFH Corp. Shareholders’ Equity
	Common Stock (a)		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total Equity
Balance at December 31, 2012	$	2	$	7,959		$	(18,939	)	$	(47	)	$	102	$	(10,923	)
Net loss	—		—			(640		)	—			—		(640		)
Effects of stock-based incentive compensation plans	—		3			—			—			—		3
Repurchases of stock	—		(5		)	—			—			—		(5		)
Change in unrecognized losses related to pension and OPEB plans (Note 10)	—		—			—			(3		)	—		(3		)
Net effects of cash flow hedges	—		—			—			4			—		4
Net effects related to Oncor	—		—			—			1			—		1
Investment by noncontrolling interests	—		—			—			—			2		2
Balance at June 30, 2013	$	2	$	7,957		$	(19,579	)	$	(45	)	$	104	$	(11,561	)

____________

(a) Authorized shares totaled 2,000,000,000 at June 30, 2013. Outstanding shares totaled 1,669,861,383 and 1,680,539,245 at June 30, 2013 and December 31, 2012, respectively.

The following table presents the changes to equity for the six months ended June 30, 2012:

	EFH Corp. Shareholders’ Equity
	Common Stock (a)		Additional Paid-in Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total Equity
Balance at December 31, 2011	$	2	$	7,947	$	(15,579	)	$	(222	)	$	95	$	(7,757	)
Net loss	—		—		(1,000		)	—			—		(1,000		)
Effects of stock-based incentive compensation plans	—		8		—			—			—		8
Change in unrecognized losses related to pension and OPEB plans	—		—		—			8			—		8
Net effects of cash flow hedges	—		—		—			4			—		4
Net effects related to Oncor	—		—		—			1			—		1
Investment by noncontrolling interests	—		—		—			—			4		4
Other	—		—		(1		)	—			—		(1		)
Balance at June 30, 2012	$	2	$	7,955	$	(16,580	)	$	(209	)	$	99	$	(8,733	)

____________

(a) Authorized shares totaled 2,000,000,000 at June 30, 2012. Outstanding shares totaled 1,678,739,245 and 1,679,539,245 at June 30, 2012 and December 31, 2011, respectively.

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Accumulated Other Comprehensive Income (Loss)

The following table presents the changes to accumulated other comprehensive income (loss) for the six months ended June 30, 2013. There was no other comprehensive income (loss) before reclassification for the period.

	Dedesignated Cash Flow Hedges – Interest Rate Swaps (Note 9)			Pension and Other Postretirement Employee Benefit Liabilities Adjustments (Note 10)			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2012	$	(64	)	$	17		$	(47	)
Amounts reclassified from accumulated other comprehensive income (loss) and reported in:
Operating costs	—			(2		)	(2		)
Depreciation and amortization	1			—			1
Selling, general and administrative expenses	—			(2		)	(2		)
Interest expense and related charges	5			—			5
Other	2			(1		)	1
Income tax benefit (expense)	(2		)	1			(1		)
Total amount reclassified from accumulated other comprehensive income (loss) during the period	6			(4		)	2
Balance at June 30, 2013	$	(58	)	$	13		$	(45	)

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8. FAIR VALUE MEASUREMENTS

Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. 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 that, in the absence of actively quoted market prices, 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. See further discussion below.

Our valuation policies and procedures are developed, maintained and validated by a centralized risk management group that reports to the Chief Financial Officer, who also functions as the Chief Risk Officer. Risk management functions include commodity price reporting and validation, valuation model validation, risk analytics, risk control, credit risk management and risk reporting.

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 (generally non-binding) 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 generally accepted interest rate swap valuation models utilizing month-end interest rate curves.

Probable loss of default by either us or our counterparties is considered in determining the fair value of derivative assets and liabilities. These non-performance risk adjustments take into consideration credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 9 for additional information regarding credit risk associated with our derivatives). We utilize published credit ratings and default rate factors in calculating the fair value measurement adjustments.

27

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. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locations and credit/non-performance risk assumptions. 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.

The significant unobservable inputs and valuation models are developed by employees trained and experienced in market operations and fair value measurement and validated by the company's risk management group, which also further analyzes any significant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upward or downward changes in the fair value measurement.

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.

Assets and liabilities measured at fair value on a recurring basis consisted of the following:

June 30, 2013
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	171	$	1,210	$	130	$	1	$	1,512
Interest rate swaps	—		92		—		—		92
Nuclear decommissioning trust – equity securities (c)	283		165		—		—		448
Nuclear decommissioning trust – debt securities (c)	—		261		—		—		261
Total assets	$	454	$	1,728	$	130	$	1	$	2,313
Liabilities:
Commodity contracts	$	168	$	143	$	42	$	1	$	354
Interest rate swaps	—		1,686		—		—		1,686
Total liabilities	$	168	$	1,829	$	42	$	1	$	2,040

December 31, 2012
	Level 1		Level 2		Level 3 (a)		Total
Assets:
Commodity contracts	$	180	$	1,784	$	83	$	2,047
Interest rate swaps	—		134		—		134
Nuclear decommissioning trust – equity securities (c)	249		144		—		393
Nuclear decommissioning trust – debt securities (c)	—		261		—		261
Total assets	$	429	$	2,323	$	83	$	2,835
Liabilities:
Commodity contracts	$	208	$	121	$	54	$	383
Interest rate swaps	—		2,217		—		2,217
Total liabilities	$	208	$	2,338	$	54	$	2,600

____________

(a) See table below for description of Level 3 assets and liabilities.

(b) Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in the balance sheet.

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

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Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated "normal" purchases or sales. See Note 9 for further discussion regarding the company's use of derivative instruments.

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 5 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, 2013 and 2012. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfers between Level 2 and Level 3.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type (all related to commodity contracts) and the significant unobservable inputs used in the valuations at June 30, 2013 and December 31, 2012:

June 30, 2013
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	2	$	(9	)	$	(7	)	Valuation Model	Illiquid pricing locations (c)	$30 to $45/ MWh
										Hourly price curve shape (d)	$15 to $50/ MWh
Electricity spread options	61		(13		)	48			Option Pricing Model	Gas to power correlation (e)	40% to 95%
										Power volatility (f)	10% to 35%
Electricity congestion revenue rights	57		(5		)	52			Market Approach (g)	Illiquid price differences between settlement points (h)	$0.00 to $30.00
Coal purchases	1		(14		)	(13		)	Market Approach (g)	Illiquid price variances between mines (i)	$0.00 to $1.00
										Probability of default (j)	0% to 40%
										Recovery rate (k)	0% to 40%
Other	9		(1		)	8
Total	$	130	$	(42	)	$	88

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December 31, 2012
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	5	$	(9	)	$	(4	)	Valuation Model	Illiquid pricing locations (c)	$20 to $40/ MWh
										Hourly price curve shape (d)	$20 to $50/ MWh
Electricity spread options	34		(10		)	24			Option Pricing Model	Gas to power correlation (e)	20% to 90%
										Power volatility (f)	20% to 40%
Electricity congestion revenue rights	41		(2		)	39			Market Approach (g)	Illiquid price differences between settlement points (h)	$0.00 to $0.50
Coal purchases	—		(32		)	(32		)	Market Approach (g)	Illiquid price variances between mines (i)	$0.00 to $1.00
										Probability of default (j)	5% to 40%
										Recovery rate (k)	0% to 40%
Other	3		(1		)	2
Total	$	83	$	(54	)	$	29

____________

(a) Electricity purchase and sales contracts include wind generation agreements and hedging positions in the ERCOT west region as well as power contracts, the valuations of which include unobservable inputs related to the hourly shaping of the price curve. Electricity spread option contracts consist of physical electricity call options. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. Coal purchase contracts relate to western (Powder River Basin) coal.

(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.

(c) Based on the historical range of forward average monthly ERCOT West Hub prices.

(d) Based on the historical range of forward average hourly ERCOT North Hub prices.

(e) Estimate of the historical range based on forward natural gas and on-peak power prices for the ERCOT hubs most relevant to our spread options.

(f) Based on historical forward price changes.

(g) While we use the market approach, there is either insufficient market data to consider the valuation liquid or the significance of credit reserves or non-performance risk adjustments results in a Level 3 designation.

(h) Based on the historical price differences between settlement points in the ERCOT North Hub for 2012 and the ERCOT North and West Hubs in 2013.

(i) Based on the historical range of price variances between mine locations.

(j) Estimate of the range of probabilities of default based on past experience and the length of the contract as well as our and counterparties' credit ratings.

(k) Estimate of the default recovery rate based on historical corporate rates.

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The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Net asset (liability) balance at beginning of period	$	59		$	(5	)	$	29		$	53
Total unrealized valuation gains (losses)	(26		)	52			(17		)	(17		)
Purchases, issuances and settlements (a):
Purchases	56			5			60			13
Issuances	(6		)	(4		)	(6		)	(12		)
Settlements	1			3			17			23
Transfers into Level 3 (b)	—			(39		)	1			(46		)
Transfers out of Level 3 (b)	4			—			4			(2		)
Net change (c)	29			17			59			(41		)
Net asset balance at end of period	$	88		$	12		$	88		$	12
Unrealized valuation gains (losses) relating to instruments held at end of period	$	(20	)	$	27		(7		)	(32		)

____________

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

(b) Includes transfers due to changes in the observability of significant inputs. Transfers in and out occur at the end of each quarter, which is when the assessments are performed. Transfers out during 2013 were driven by a decrease in nonperformance risk adjustments. All Level 3 transfers during the periods presented are in and out of Level 2.

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

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9. 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 electricity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a natural gas hedging program and the hedging of interest costs on our long-term debt. See Note 8 for a discussion of the fair value of all derivatives.

Natural Gas Hedging Program — TCEH has a natural gas 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 has generally moved with 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 portion of electricity price exposure related to expected lignite/coal- and nuclear-fueled generation for this period. Unrealized gains and losses arising from changes in the fair value of the instruments under the program as well as realized gains and losses upon settlement of the instruments 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. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in the income statement in interest expense and related charges. See Note 5 for additional information about interest rate swap agreements.

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

Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported in the balance sheets at June 30, 2013 and December 31, 2012:

June 30, 2013
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	1,201		$	92	$	—		$	—		$	1,293
Noncurrent assets	311			—		—			—			311
Current liabilities	—			—		(345		)	(615		)	(960		)
Noncurrent liabilities	(1		)	—		(8		)	(1,071		)	(1,080		)
Net assets (liabilities)	$	1,511		$	92	$	(353	)	$	(1,686	)	$	(436	)

December 31, 2012
	Derivative assets				Derivative liabilities
	Commodity contracts		Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	1,461	$	134	$	—		$	—		$	1,595
Noncurrent assets	586		—		—			—			586
Current liabilities	—		—		(366		)	(678		)	(1,044		)
Noncurrent liabilities	—		—		(17		)	(1,539		)	(1,556		)
Net assets (liabilities)	$	2,047	$	134	$	(383	)	$	(2,217	)	$	(419	)

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At June 30, 2013 and December 31, 2012, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealized effects:

	Three Months Ended June 30,					Six Months Ended June 30,
Derivative (income statement presentation)	2013		2012			2013			2012
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a)	$	157	$	(133	)	$	(43	)	$	225
Interest rate swaps (Interest expense and related charges) (b)	183		(276		)	180			(332		)
Net gain (loss)	$	340	$	(409	)	$	137		$	(107	)

____________

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

(b) Includes unrealized mark-to-market net gain (loss) as well as the net realized effect on interest paid/accrued, both reported in "Interest Expense and Related Charges" (see Note 13).

The following table presents the pretax effect (all losses) 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 and six months ended June 30, 2013 and 2012.

Derivative type (income statement presentation of loss reclassified from accumulated OCI into income)	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Interest rate swaps (Interest expense and related charges)	$	(2	)	$	(2	)	$	(5	)	$	(5	)
Interest rate swaps (Depreciation and amortization)	(1		)	—			(1		)	(1		)
Total	$	(3	)	$	(2	)	$	(6	)	$	(6	)

Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedge) at June 30, 2013 and December 31, 2012 totaled $39 million and $43 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps previously accounted for as cash flow hedges. We expect that $4 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at June 30, 2013 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

Balance Sheet Presentation of Derivatives

Consistent with elections under US GAAP to present amounts on a gross basis, we report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements we have with counterparties. 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.

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet. Margin deposits received from counterparties are either used for working capital or other corporate purposes or are deposited in a separate restricted cash account. At June 30, 2013 and December 31, 2012, essentially all margin deposits held were unrestricted.

We maintain standardized master netting agreements with certain counterparties that allow for the netting of positive and negative exposures. Generally, we utilize the International Swaps and Derivatives Association (ISDA) standardized contract for financial transactions, the Edison Electric Institute standardized contract for physical power transactions and the North American Energy Standards Board (NAESB) standardized contract for physical natural gas transactions. These contain credit enhancements that allow for the right to offset assets and liabilities with other financial instruments and collateral received in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.

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Certain entities are counterparties to both our natural gas hedge program positions and our interest rate swaps and have entered into master agreements that provide for netting and setoff of amounts related to these positions.

The following tables reconcile our derivative assets and liabilities as presented in the consolidated balance sheet to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:

June 30, 2013
	Amounts Presented in Balance Sheet			Offsetting Financial Instruments (a)			Financial Collateral (Received) Pledged (b)			Net Amounts (c)
Derivative assets:
Commodity contracts	$	1,512		$	(905	)	$	(431	)	$	176
Interest rate swaps	92			(92		)	—			—
Total derivative assets	1,604			(997		)	(431		)	176
Derivative liabilities:
Commodity contracts	(354		)	294			26			(34		)
Interest rate swaps	(1,686		)	703			—			(983		)
Total derivative liabilities	(2,040		)	997			26			(1,017		)
Net amounts	$	(436	)	$	—		$	(405	)	$	(841	)

December 31, 2012
	Amounts Presented in Balance Sheet			Offsetting Financial Instruments (a)			Financial Collateral (Received) Pledged (b)			Net Amounts
Derivative assets:
Commodity contracts	$	2,047		$	(1,263	)	$	(597	)	$	187
Interest rate swaps	134			(134		)	—			—
Total derivative assets	2,181			(1,397		)	(597		)	187
Derivative liabilities:
Commodity contracts	(383		)	319			29			(35		)
Interest rate swaps	(2,217		)	1,078			—			(1,139		)
Total derivative liabilities	(2,600		)	1,397			29			(1,174		)
Net amounts	$	(419	)	$	—		$	(568	)	$	(987	)

____________

(a) Offsetting financial instruments with respect to commodity contracts include amounts related to interest rate swaps and vice versa. Amounts exclude trade accounts receivable and payable related to settled financial instruments.

(b) Financial collateral consists entirely of cash margin deposits.

(c) Includes net liability positions totaling approximately $1.1 billion related to counterparties with positions that are secured by a first-lien interest in the assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes.

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Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at June 30, 2013 and December 31, 2012:

	June 30, 2013		December 31, 2012
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed (a)	$	32,565	$	32,760	Million US dollars
Basis	$	11,967	$	11,967	Million US dollars
Natural gas:
Natural gas forward sales and purchases (b)	604		875		Million MMBtu
Locational basis swaps	408		495		Million MMBtu
All other	2,020		1,549		Million MMBtu
Electricity	45,091		76,767		GWh
Congestion Revenue Rights (c)	108,208		111,185		GWh
Coal	14		13		Million tons
Fuel oil	21		47		Million gallons
Uranium	804		441		Thousand pounds

____________

(a) Includes notional amount of interest rate swaps with maturity dates through October 2014 as well as notional amount of swaps effective from October 2014 with maturity dates through October 2017 (see Note 5).

(b) Represents gross notional forward sales, purchases and options transactions in the natural gas hedging program. The net amount of these transactions was approximately 270 million MMBtu and 360 million MMBtu at June 30, 2013 and December 31, 2012, respectively.

(c) Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT.

Credit Risk-Related Contingent Features of Derivatives

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies; however, due to our credit ratings being below investment grade, substantially all of such collateral posting requirements are already effective.

At June 30, 2013 and December 31, 2012, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $118 million and $58 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $30 million and $12 million at June 30, 2013 and December 31, 2012, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, at June 30, 2013 and December 31, 2012, there were no remaining liquidity requirements.

In addition, certain derivative agreements that are collateralized primarily with liens on certain of our assets 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. At June 30, 2013 and December 31, 2012, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.729 billion and $2.299 billion, respectively, before consideration of the amount of assets subject to the liens. No cash collateral or letters of credit were posted with these counterparties at June 30, 2013 and December 31, 2012 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 at June 30, 2013 and December 31, 2012, the remaining related liquidity requirement after reduction for derivative assets under netting arrangements but before consideration of the amount of assets subject to the liens would have totaled $984 million and $1.141 billion, respectively. See Note 5 for a description of other obligations that are supported by liens on certain of our assets.

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As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $1.847 billion and $2.357 billion at June 30, 2013 and December 31, 2012, 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 subject to 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

We have significant concentrations of credit risk with the counterparties to our derivative contracts. At June 30, 2013, total credit risk exposure to all counterparties related to derivative contracts totaled $1.739 billion (including associated accounts receivable). The net exposure to those counterparties totaled $283 million at June 30, 2013 after taking into effect netting arrangements, setoff provisions and collateral. At June 30, 2013, the credit risk exposure to the banking and financial sector represented 88% of the total credit risk exposure and 49% of the net exposure, a significant amount of which is related to the natural gas hedging program, and the largest net exposure to a single counterparty totaled $55 million.

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

We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master 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 changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

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

Net pension and OPEB costs related to plans sponsored by EFH Corp. for the three and six months ended June 30, 2013 and 2012 are comprised of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Components of net pension costs:
Service cost	$	2		$	11		$	4		$	23
Interest cost	3			40			6			80
Expected return on assets	(2		)	(40		)	(4		)	(80		)
Amortization of net loss	2			27			4			54
Pension costs	5			38			10			77
Components of net OPEB costs:
Service cost	3			2			5			4
Interest cost	10			11			21			22
Expected return on assets	(3		)	(3		)	(6		)	(6		)
Amortization of transition obligation	—			1			—			1
Amortization of prior service cost	(8		)	(8		)	(16		)	(16		)
Amortization of net loss	7			3			15			7
OPEB costs	9			6			19			12
Total benefit costs	14			44			29			89
Less amounts expensed by Oncor	(6		)	(9		)	(12		)	(18		)
Less amounts deferred principally as a regulatory asset or property by Oncor	(6		)	(21		)	(12		)	(43		)
Net amounts recognized as expense by EFH Corp. and consolidated subsidiaries	$	2		$	14		$	5		$	28

The decrease in pension costs in 2013 reflects the implementation of certain amendments to EFH Corp.'s pension plan completed in the fourth quarter 2012 that resulted in:

• splitting off assets and liabilities under the plan associated with employees of Oncor and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses) to a new plan sponsored and administered by Oncor (the Oncor Plan) and

• the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities associated with active employees of EFH Corp.'s competitive businesses other than collective bargaining unit employees.

The discount rates reflected in net pension and OPEB costs for 2013 are 4.30% and 4.10%, respectively. The expected rates of return on pension and OPEB plan assets reflected in the 2013 cost amounts are 5.4% and 6.7%, respectively.

Cash contributions in the first six months of 2013 related to the pension plans totaled $6 million, essentially all of which was funded by Oncor, and $8 million related to the OPEB plan, of which $5 million was funded by Oncor. Additional contributions expected in 2013 total $1 million for the pension plans, including amounts related to nonqualified plans, and $9 million for the OPEB plan, of which approximately $6 million is expected to be funded by Oncor.

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11. 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, reported in SG&A expense, totaling $10 million and $9 million for the three months ended June 30, 2013 and 2012, respectively, and $19 million for both the six months ended June 30, 2013 and 2012.

• 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.

• In January 2013, fees paid to Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, for services related to debt exchanges totaled $2 million, described as follows: (i) Goldman acted as a dealer manager for the offers by EFIH and EFIH Finance to exchange new EFIH 10% Notes for EFH Corp. 9.75% Notes, EFH Corp. 10% Notes and EFIH 9.75% Notes (collectively, the Old Notes) and as a solicitation agent in the solicitation of consents by EFH Corp. and EFIH and EFIH Finance to amendments to the Old Notes and indentures governing the Old Notes and (ii) Goldman acted as a dealer manager for the offers by EFIH and EFIH Finance to exchange EFIH Toggle Notes for EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes. See Note 5 for further discussion of these exchange offers.

In February 2012, Goldman acted as a joint book-running manager and initial purchaser in the issuance of $1.15 billion principal amount of EFIH 11.750% Notes for which it received fees totaling $7 million. A broker-dealer affiliate of KKR served as a co-manager and initial purchaser and an affiliate of TPG served as an advisor in the transactions, for which they each received $1 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 sold or acquired, and in the future may sell or acquire, debt or debt securities issued by us in open market transactions or through loan syndications.

• TCEH made loans to EFH Corp. in the form of demand notes (TCEH Demand Notes) that were pledged as collateral under the TCEH Senior Secured Facilities for (i) debt principal and interest payments and (ii) other general corporate purposes (SG&A Note) for EFH Corp. The TCEH Demand Notes totaled $698 million at December 31, 2012, including $233 million in the SG&A Note, and are eliminated in consolidation in these condensed consolidated financial statements. EFH Corp. settled the balance of the TCEH Demand Notes in January 2013 using $680 million of the proceeds from debt issued by EFIH in 2012 that had been held as restricted cash (see Note 13).

• As part of EFH Corp.'s liability management program, EFH Corp. and EFIH have purchased, or received in exchanges, certain debt securities of EFH Corp. and TCEH, which they have held. Principal and interest payments received by EFH Corp. and EFIH on these investments have been used, in part, to service their outstanding debt. These investments are eliminated in consolidation in these consolidated financial statements. At June 30, 2013, EFIH held $1.282 billion principal amount of EFH Corp. debt and $79 million principal amount of TCEH debt. At June 30, 2013, EFH Corp. held $303 million principal amount of TCEH debt. In the first quarter 2013, EFIH distributed as a dividend to EFH Corp. $6.360 billion principal amount of EFH Corp. debt previously received by EFIH in debt exchanges; EFH Corp. cancelled the debt instruments (see Note 5).

• TCEH's retail operations pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services, reported in fuel, purchased power costs and delivery fees, totaled $230 million and $238 million for the three months ended June 30, 2013 and 2012, respectively, and $455 million and $465 million for the six months ended June 30, 2013 and 2012, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at June 30, 2013 and December 31, 2012 reflect amounts due currently to Oncor totaling $139 million and $53 million, respectively (included in net payables due to unconsolidated subsidiary), largely related to these electricity delivery fees. Also see discussion below regarding receivables from Oncor under a tax sharing agreement.

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• In August 2012, TCEH and Oncor agreed to settle at a discount two agreements related to securitization (transition) bonds issued by Oncor's bankruptcy-remote financing subsidiary in 2003 and 2004 to recover generation-related regulatory assets. Under the agreements, TCEH had been reimbursing Oncor as described immediately below.

Oncor collects transition surcharges from its customers to recover the transition bond payment obligations. Oncor's incremental income taxes related to the transition surcharges it collects had been reimbursed by TCEH quarterly under a noninterest bearing note payable to Oncor that was to mature in 2016. TCEH's payments on the note prior to the August 2012 settlement totaled $10 million and $20 million for the three and six months ended June 30, 2012, respectively.

Under an interest reimbursement agreement, TCEH had reimbursed Oncor on a monthly basis for interest expense on the transition bonds. Only the monthly accrual of interest under this agreement was reported as a liability. This interest expense prior to the August 2012 settlement totaled $7 million and $14 million for the three and six months ended June 30, 2012, respectively.

• Oncor pays EFH Corp. subsidiaries for financial and other administrative services and shared facilities at cost. Such amounts reduced reported SG&A expense by $7 million and $9 million for the three months ended June 30, 2013 and 2012, respectively, and $16 million for both the six months ended June 30, 2013 and 2012.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to TCEH for contribution to the trust fund with the intent that the trust fund assets, reported in other investments in our balance sheet, will ultimately be sufficient to fund the actual future decommissioning liability, reported in noncurrent liabilities in our balance sheet. The delivery fee surcharges remitted to TCEH totaled $4 million for both the three months ended June 30, 2013 and 2012 and $8 million for both the six months ended June 30, 2013 and 2012. Income and expenses associated with the trust fund and the decommissioning liability incurred by TCEH are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates. At June 30, 2013 and December 31, 2012, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $329 million and $284 million, respectively, reported in noncurrent liabilities.

• We file a consolidated federal income tax return that includes Oncor Holdings' results. Oncor is not a member of our consolidated tax group, but our consolidated federal income tax return includes our portion of Oncor's results due to our equity ownership in Oncor. We also file a consolidated Texas state margin tax return that includes all of Oncor Holdings' and Oncor's results. However, under a tax sharing agreement, Oncor Holdings' and Oncor's federal income tax and Texas margin tax expense and related balance sheet amounts, including our income taxes receivable from or payable to Oncor Holdings and Oncor, are recorded as if Oncor Holdings and Oncor file their own corporate income tax returns. Our current amount receivable from Oncor Holdings and Oncor related to income taxes (included in net payables due to unconsolidated subsidiary) totaled $47 million and $34 million at June 30, 2013 and December 31, 2012, respectively. EFH Corp. received income tax payments from Oncor Holdings and Oncor totaling $53 million and $37 million for the six months ended June 30, 2013 and 2012, 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, at both June 30, 2013 and December 31, 2012, TCEH had posted letters of credit in the amount of $11 million for the benefit of Oncor.

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• As a result of the pension plan actions discussed in Note 10, in December 2012, Oncor became the sponsor of a new pension plan (the Oncor Plan), the participants in which consist of all of Oncor's active employees and all retirees and terminated vested participants of EFH Corp. and its subsidiaries (including discontinued businesses). Oncor had previously contractually agreed to assume responsibility for pension and OPEB liabilities that are recoverable by Oncor under regulatory rate-setting provisions. As part of the pension plan actions, EFH Corp. fully funded the nonrecoverable pension liabilities under the Oncor Plan. After the pension plan actions, the remaining participants in the EFH Corp. pension plan consist of active employees under collective bargaining agreements (union employees). Oncor continues to be responsible for the recoverable portion of pension obligations to these union employees. EFH Corp. is the sponsor of the OPEB plan and remains liable for the majority of the OPEB plan obligations. Accordingly, EFH Corp.'s balance sheet reflects unfunded pension and OPEB liabilities related to plans that it sponsors, including recoverable and nonrecoverable amounts, but also reflects a receivable from Oncor for that portion of the unfunded liabilities for which Oncor is contractually responsible, substantially all of which is expected to be recovered in Oncor's rates. At June 30, 2013 and December 31, 2012, the receivable amounts totaled $831 million and $825 million, respectively, classified as noncurrent. Under ERISA, EFH Corp. and Oncor remain jointly and severally liable for the funding of the EFH Corp. and Oncor pension plans. We view the risk of the retained liability under ERISA related to the Oncor Plan to be not significant.

• 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 rating below investment grade.

12. 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 consists largely of our investment in Oncor. Oncor 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 2 for discussion of the reporting of Oncor Holdings and, accordingly, the Regulated Delivery segment, as an equity method investment. See Note 11 for discussion of material transactions with Oncor, including payment to Oncor of electricity delivery fees, which are based on rates regulated by the PUCT.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued businesses, general corporate expenses and interest on EFH Corp., 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 our 2012 Form 10-K. We evaluate performance based on net income (loss). We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices or regulated rates.

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Operating revenues (all Competitive Electric)	$	1,419		$	1,385		$	2,679		$	2,607
Equity in earnings of unconsolidated subsidiaries (net of tax) — Regulated Delivery (net of noncontrolling interest of $19, $21, $37 and $36)	$	74		$	83		$	141		$	141
Net income (loss):
Competitive Electric	$	(238	)	$	(668	)	$	(786	)	$	(926	)
Regulated Delivery	74			83			141			141
Corporate and Other	93			(111		)	5			(215		)
Consolidated	$	(71	)	$	(696	)	$	(640	)	$	(1,000	)

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13. SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013			2012
Other income:
Office space rental income (a)	$	3	$	3	$	6		$	6
Consent fee related to novation of hedge positions between counterparties (b)	—		6		—			6
Insurance/litigation settlements (b)	—		—		2			2
All other	4		3		6			5
Total other income	$	7	$	12	$	14		$	19
Other deductions:
Ongoing employee retirement benefit expense related to discontinued businesses (a)	$	—	$	3	$	(1	)	$	6
All other	1		3		5			6
Total other deductions	$	1	$	6	$	4		$	12

____________

(a) Reported in Corporate and Other.

(b) Reported in Competitive Electric segment.

Interest Expense and Related Charges

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	844		$	803		$	1,683		$	1,594
Interest payable with additional toggle notes (Note 5)	42			59			83			117
Unrealized mark-to-market net (gain) loss on interest rate swaps (a)	(339		)	106			(489		)	(9		)
Amortization of interest rate swap losses at dedesignation of hedge accounting	2			2			4			5
Amortization of fair value debt discounts resulting from purchase accounting	5			11			10			22
Amortization of debt issuance, amendment and extension costs and discounts	51			48			105			95
Capitalized interest	(7		)	(11		)	(14		)	(20		)
Total interest expense and related charges	$	598		$	1,018		$	1,382		$	1,804

____________

(a) Three months ended June 30, 2013 and 2012 amounts include net gains totaling $338 million and net losses totaling $107 million, respectively, related to TCEH swaps (see Note 5) and net gains totaling $1 million for both periods related to EFH Corp. swaps substantially closed through offsetting positions. Six months ended June 30, 2013 and 2012 amounts include net gains totaling $486 million and $4 million, respectively, related to TCEH swaps and net gains totaling $3 million and $5 million, respectively, related to EFH Corp. swaps substantially closed through offsetting positions.

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Restricted Cash

	June 30, 2013				December 31, 2012
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts in escrow to settle TCEH Demand Notes (Note 11)	$	—	$	—	$	680	$	—
Amounts related to margin deposits held	1		—		—		—
Amounts related to TCEH's Letter of Credit Facility (Note 5)	—		947		—		947
Other	4		—		—		—
Total restricted cash	$	5	$	947	$	680	$	947

Inventories by Major Category

	June 30, 2013		December 31, 2012
Materials and supplies	$	212	$	201
Fuel stock	194		168
Natural gas in storage	36		24
Total inventories	$	442	$	393

Other Investments

	June 30, 2013		December 31, 2012
Nuclear plant decommissioning trust	$	709	$	654
Assets related to employee benefit plans, including employee savings programs, net of distributions	69		70
Land	40		41
Miscellaneous other	2		2
Total other investments	$	820	$	767

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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 by TCEH in the trust fund. Income and expense associated with the trust fund and the decommissioning liability are offset by a corresponding change in a receivable/payable (currently a payable reported in noncurrent liabilities) that will ultimately be settled through changes in Oncor's delivery fees rates (see Note 11). A summary of investments in the fund follows:

	June 30, 2013
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	257	$	9	$	(5	)	$	261
Equity securities (c)	250		207		(9		)	448
Total	$	507	$	216	$	(14	)	$	709

	December 31, 2012
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	246	$	16	$	(1	)	$	261
Equity securities (c)	245		161		(13		)	393
Total	$	491	$	177	$	(14	)	$	654

____________

(a) Includes realized gains and losses on 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 4.45% and 4.38% at June 30, 2013 and December 31, 2012, respectively, and an average maturity of 7 and 6 years at June 30, 2013 and December 31, 2012, respectively.

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

Debt securities held at June 30, 2013 mature as follows: $78 million in one to five years, $63 million in five to ten years and $120 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,
	2013			2012			2013			2012
Realized gains	$	1		$	1		$	1		$	1
Realized losses	$	—		$	(1	)	$	—		$	(1	)
Proceeds from sales of securities	$	64		$	21		$	105		$	31
Investments in securities	$	(67	)	$	(24	)	$	(112	)	$	(38	)

Property, Plant and Equipment

At June 30, 2013 and December 31, 2012, property, plant and equipment of $18.3 billion and $18.7 billion, respectively, is stated net of accumulated depreciation and amortization of $7.6 billion and $6.9 billion, respectively.

43

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 changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of Oncor's delivery fees.

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, for the six months ended June 30, 2013:

	Nuclear Plant Decommissioning		Mining Land Reclamation			Other		Total
Liability at December 31, 2012	$	368	$	135		$	33	$	536
Additions:
Accretion	11		15			1		27
Reductions:
Payments	—		(49		)	—		(49		)
Liability at June 30, 2013	379		101			34		514
Less amounts due currently	—		(68		)	—		(68		)
Noncurrent liability at June 30, 2013	$	379	$	33		$	34	$	446

Other Noncurrent Liabilities and Deferred Credits

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

	June 30, 2013		December 31, 2012
Uncertain tax positions (including accrued interest)	$	425	$	2,005
Retirement plan and other employee benefits (a)	1,049		1,035
Asset retirement and mining reclamation obligations	446		452
Unfavorable purchase and sales contracts	602		620
Nuclear decommissioning cost over-recovery (Note 11)	329		284
Other	33		30
Total other noncurrent liabilities and deferred credits	$	2,884	$	4,426

____________

(a) Includes $831 million and $825 million at June 30, 2013 and December 31, 2012, respectively, representing pension and OPEB liabilities related to Oncor (see Note 11).

44

Liability for Uncertain Tax Positions— In May 2013, we received approval from the Joint Committee on Taxation of the resolution of all issues arising from the 1997 through 2002 IRS audit, which includes all tax issues related to EFH Corp.'s discontinued Europe operations. This final resolution also affected federal and state returns for periods subsequent to 2002. In the second quarter 2013, we reduced the liability for uncertain tax positions to reflect the effects of the final resolution, resulting in a $524 million reclassification to the accumulated deferred income tax liability and the recording of a $183 million income tax benefit. Other effects included the recording of a $19 million noncurrent federal income tax liability, an $8 million current federal income tax liability, a $15 million current state income tax liability and a $33 million federal income tax receivable from Oncor under the tax sharing agreement (see Note 11). The $183 million income tax benefit reflected a $204 million income tax benefit recorded in Corporate and Other activities and a $21 million income tax expense reported in the Competitive Electric segment results.

In March 2013, EFH Corp. and the IRS agreed on terms to resolve disputed adjustments related to the IRS audit for the years 2003 through 2006, which was concluded in June 2011. The IRS proposed a significant number of adjustments to the originally filed returns for such years. The adjustments relate to one significant accounting method issue and other less significant issues. In the first quarter 2013, we reduced the liability for uncertain tax positions to reflect the terms of the agreement, resulting in a $701 million reclassification to the accumulated deferred income tax liability and a net adjustment of $143 million ($84 million after tax), largely representing a reversal of accrued interest and reported as an increase in income tax benefit. Any cash income tax liability related to this agreement is expected to be immaterial. The $84 million income tax benefit reflected a $62 million income tax benefit recorded in the Competitive Electric segment results and a $22 million income tax benefit recorded in Corporate and Other activities.

The March 2013 settlement and May 2013 final resolution resulted in the expected elimination of all net operating loss carryforwards generated through 2013, as well as elimination of remaining alternative minimum tax credit carryforwards.

Unfavorable Purchase and Sales Contracts – The amortization of unfavorable purchase and sales contracts totaled $7 million for both the three months ended June 30, 2013 and 2012 and $13 million and $14 million for the six months ended June 30, 2013 and 2012, respectively. See Note 3 for intangible assets related to favorable purchase and sales contracts.

The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:

Year	Amount
2013	$	25
2014	$	24
2015	$	23
2016	$	23
2017	$	23

Supplemental Cash Flow Information

	Six Months Ended June 30,
	2013			2012
Cash payments (receipts) related to:
Interest paid (a)	$	1,733		$	1,552
Capitalized interest	(14		)	(20		)
Interest paid (net of capitalized interest) (a)	$	1,719		$	1,532
Income taxes	$	51		$	58
Noncash investing and financing activities:
Principal amount of toggle notes issued in lieu of cash interest (Note 5)	$	83		$	114
Construction expenditures (b)	$	69		$	83
Debt exchange and extension transactions (Note 5)	$	(326	)	$	—
Debt assumed related to acquisition of combustion turbine trust interest	$	(45	)	$	—

____________

(a) Net of amounts received under interest rate swap agreements.

(b) Represents end-of-period accruals.

45

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, 2013 and 2012 should be read in conjunction with our condensed 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

EFH Corp., a Texas corporation, is a Dallas-based holding company that conducts its operations principally through its TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. 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. TCEH is a wholly owned subsidiary of EFCH, which is a holding company and a wholly owned subsidiary of EFH Corp. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Oncor Holdings, a holding company that holds an approximately 80% equity interest in Oncor, is a wholly owned subsidiary of EFIH, which is a holding company and a wholly owned subsidiary of EFH Corp.

Various "ring-fencing" measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 2 to Financial Statements for a discussion of the reporting of our investment in Oncor (and Oncor Holdings) as an equity method investment and a description of the "ring-fencing" measures implemented with respect to Oncor. These measures were put in place to further enhance Oncor's credit quality and mitigate Oncor's exposure to the Texas Holdings Group with the intent to minimize the risk that a court would order any of the assets and liabilities of the Oncor Ring-Fenced Entities to be substantively consolidated with those of any member of the Texas Holdings Group in the event any such member were to become a debtor in a bankruptcy case. We believe, as several major credit rating agencies have acknowledged, that the likelihood of such substantive consolidation of the Oncor Ring-Fenced Entities' assets and liabilities is remote in consideration of the ring-fencing measures and applicable law.

Operating Segments

Our operations are aligned into two reportable businesses: Competitive Electric and Regulated Delivery. The Competitive Electric segment consists largely of TCEH. The Regulated Delivery segment consists largely of our investment in Oncor.

See Note 12 to Financial Statements for further information regarding reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

See Note 1 to Financial Statements for discussion of TCEH liquidity and description of recent discussions with certain creditors. See Note 13 to Financial Statements for discussion of the agreement we reached with the IRS in March 2013 that resolved disputed adjustments from their audit for the years 2003 through 2006 and the approval we received from the Joint Committee on Taxation in May 2013 that resolved all issues from the IRS audit for the years 1997 through 2002. See “Financial Condition — Income Tax Matters” for discussion of the private letter ruling we received from the IRS in April 2013 and our subsequent consummation of internal corporate transactions involving EFH Corp. and EFCH that resulted in the elimination of an excess loss account and a deferred intercompany gain.

46

Natural Gas Hedging Program and Other Hedging Activities — Because wholesale electricity prices in ERCOT have generally moved with natural gas prices, TCEH has a natural gas hedging program designed to mitigate the effect of natural gas price changes on future electricity revenues. Under the program, we have entered into market transactions involving natural gas-related financial instruments, and at June 30, 2013, have effectively sold forward approximately 270 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 32,000 GWh at an assumed 8.5 market heat rate) at weighted average annual hedge prices as shown in the table below; at December 31, 2012 and March 31, 2013, the comparable hedge volumes totaled approximately 360 million MMBtu and 310 million MMBtu, respectively. Volumes and hedge values associated with the hedging program are inclusive of offsetting purchases entered into to take into account new wholesale and retail electricity sales contracts and avoid over-hedging. This activity results in both commodity contract asset and liability balances pending the maturity and settlement of the offsetting transactions.

Taking together forward wholesale and retail electricity sales with the natural gas positions in the hedging program, we have effectively hedged an estimated 94% and 51% of the price exposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2013 and 2014, respectively (assuming an 8.5 market heat rate). The natural gas positions were entered into with the continuing expectation that wholesale electricity prices in ERCOT will generally move with prices of natural gas, which we expect to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOT market. If the relationship changes in the future, the cash flows targeted under the natural gas hedging program may not be achieved.

TCEH has entered into related put and call transactions (referred to as collars), primarily for 2014, that result in hedge prices that fall within a range. These transactions represented 56% (in MMbtu) of the positions in the hedging program at June 30, 2013, 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.

We currently have no natural gas positions in the hedging program that mature after 2014. The following table summarizes the positions in the program at June 30, 2013:

	Measure	Balance 2013 (a)	2014	Total
Natural gas hedge volumes (b)	mm MMBtu	~123	~146	~269
Weighted average hedge price (c)	$/MMBtu	~6.89	~7.80	—
Average market price (d)	$/MMBtu	~3.64	~3.91	—
Realization of hedge gains (e)	$ billions	~$0.5	~$0.6	~$1.1

___________

(a) Balance of 2013 is from July 1, 2013 through December 31, 2013.

(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 150 million MMBtu in 2014.

(c) Weighted average hedge prices are based on prices of positions in the natural gas hedging program (excluding offsetting purchases to avoid over-hedging). Where collars are reflected, sales price represents the collar floor price.

(d) Based on NYMEX Henry Hub prices.

(e) Based on cumulative unrealized mark-to-market gain at June 30, 2013.

Changes in the fair value of the instruments in the hedging program are 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 hedging program at June 30, 2013, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $270 million in pretax unrealized mark-to-market gains or losses.

The hedging program has resulted in reported net gains (losses) as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Realized net gain	$	224		$	506		$	480		$	1,019
Unrealized net loss including reversals of previously recorded amounts related to positions settled	(116		)	(577		)	(482		)	(705		)
Total	$	108		$	(71	)	$	(2	)	$	314

47

The cumulative unrealized mark-to-market net gain related to positions in the natural gas hedging program totaled $1.102 billion and $1.584 billion at June 30, 2013 and December 31, 2012, respectively. The decline was driven by settlement of maturing positions.

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 the future. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost.

The significant cumulative unrealized mark-to-market net gain related to positions in the hedging program reflects the sustained decline in forward market natural gas prices as presented in the table below. Forward natural gas prices have generally trended downward over the past several years. While the hedging program is designed to mitigate the effect on earnings of low wholesale electricity prices, depressed forward natural gas prices are challenging to our liquidity and the long-term profitability of EFH Corp.'s competitive businesses. Specifically, low natural gas prices and their effect in ERCOT on wholesale electricity prices could have a material impact on our liquidity and TCEH's overall profitability for periods in which TCEH does not have significant hedge positions. See Note 1 to Financial Statements.

	Forward Market Prices for Calendar Year ($/MMBtu) (a)
Date	2013 (b)		2014		2015		2016
December 31, 2008	$	7.15	$	7.15	$	7.21	$	7.30
December 31, 2009	$	6.67	$	6.84	$	7.05	$	7.24
December 31, 2010	$	5.33	$	5.49	$	5.64	$	5.79
December 31, 2011	$	3.94	$	4.34	$	4.60	$	4.85
March 31, 2012	$	3.47	$	3.96	$	4.26	$	4.51
June 30, 2012	$	3.58	$	3.95	$	4.13	$	4.29
September 30, 2012	$	3.84	$	4.18	$	4.37	$	4.55
December 31, 2012	$	3.54	$	4.03	$	4.23	$	4.42
March 31, 2013	$	4.12	$	4.23	$	4.30	$	4.38
June 30, 2013	$	3.64	$	3.91	$	4.14	$	4.33

___________

(a) Based on NYMEX Henry Hub prices.

(b) For March 31, 2013 and June 30, 2013, natural gas prices for 2013 represent the average of forward prices for April through December and July through December, respectively.

The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas prices, market heat rates and diesel fuel prices on realized pretax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH's unhedged position and forward prices at June 30, 2013, which for natural gas reflects estimates of electricity generation less amounts hedged through the natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling basis, generally twelve-months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

	Balance 2013 (a)	2014	2015
$1.00/MMBtu change in natural gas price (b)	$ ~12	$ ~225	$ ~470
0.1/MMBtu/MWh change in market heat rate (c)	$ ~2	$ ~25	$ ~30
$1.00/gallon change in diesel fuel price	$ ~3	$ ~45	$ ~50

___________

(a) Balance of 2013 is from August 1, 2013 through December 31, 2013.

(b) Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally being on the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). Excludes the impact of economic backdown.

(c) Based on Houston Ship Channel natural gas prices at June 30, 2013.

48

TCEHInterest Rate Swap Transactions — TCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, as of June 30, 2013, TCEH has entered into the following series of interest rate swap transactions that effectively fix the interest rates at between 5.5% and 9.3%:

Fixed Rates				Expiration Dates	Notional Amount
5.5	%	-	9.3%	September 2013 through October 2014		$	18.265	billion (a)
6.8	%	-	9.0%	October 2015 through October 2017		$	12.600	billion (b)

___________

(a) Swaps related to an aggregate $600 million principal amount of debt expired in 2013. Per the terms of the transactions, the notional amount of swaps entered into in 2011 grew by $405 million in 2013, substantially offsetting the expired swaps.

(b) These swaps are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes $3 billion that expires in October 2015 with the remainder expiring in October 2017.

We may enter into additional interest rate hedges from time to time.

TCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achieved through the interest rate swaps. Basis swaps in effect at June 30, 2013 totaled $11.967 billion notional amount. The basis swaps relate to debt outstanding through 2014.

The interest rate swaps have resulted in net gains (losses) reported in interest expense and related charges as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Realized net loss	$	(155	)	$	(168	)	$	(306	)	$	(337	)
Unrealized net gain (loss) including reversals of previously recorded amounts related to settled positions	338			(107		)	486			4
Total	$	183		$	(275	)	$	180		$	(333	)

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.579 billion and $2.065 billion at June 30, 2013 and December 31, 2012, respectively. The decline in the net liability reflected unrealized gains due to higher interest rates and swap settlements. This mark-to-market position can change materially in value as market conditions change, which could result in significant volatility in reported net income. For example, at June 30, 2013, a one percent change in interest rates would result in an increase or decrease of approximately $575 million in our cumulative unrealized mark-to-market net liability.

First-Lien Security for Natural Gas Hedging Program and Interest Rate Swaps — Approximately 90% of the positions in the natural gas hedging program and all of the TCEH interest rate swaps are secured by a first-lien interest in the assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes. Certain entities are counterparties to both our natural gas hedging program positions and our interest rate swaps and have entered into master agreements that provide for netting and setoff of amounts related to these positions. At June 30, 2013, our net liability positions related to these counterparties together with liability positions related to entities that are counterparties to only our interest rate swaps totaled approximately $1.1 billion. This amount is subject to change based on changes in interest rates and natural gas prices.

Seasonal Suspension of Certain Generation Operations — In July 2013, we filed notice with ERCOT that we intend to suspend operations at two of the three generation units at our Monticello generation facility for approximately seven months beginning October 1, 2013, due to low wholesale power prices and other market conditions. The suspension requires approval by ERCOT, and both units are expected to return to service during the peak demand months in the summer of 2014. Our mines that support the Monticello generation facility will continue year-round operations. At current wholesale market prices of electricity, we do not expect the suspension of operations to significantly impact our results of operations, liquidity or financial condition. The previously disclosed seasonal suspension of two generation units at Monticello that began December 1, 2012 ended June 1, 2013 as planned.

49

Natural Gas-Fueled Generation Development — In May 2013, Luminant filed an air permit application with the TCEQ to build two natural gas combustion turbines totaling 420 MW to 460 MW at its existing Tradinghouse generation facility. This application is in addition to the previously disclosed permit application filed by Luminant in December 2012 for two natural gas combustion turbines totaling 420 MW to 460 MW at its existing DeCordova generation facility. While we believe current market conditions do not provide adequate economic returns for the development or construction of these facilities, we believe additional generation resources will be needed to support future electricity demand growth and reliability in the ERCOT market.

Liability Management Program — At June 30, 2013, EFH Corp. and its consolidated subsidiaries had $38.3 billion principal amount of long-term debt outstanding. In October 2009, we implemented a liability management program designed to reduce debt, capture debt discount and extend debt maturities through debt exchanges, repurchases and extensions. 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 and January 2013 resulted in the extension of $16.4 billion in loan maturities under the TCEH Term Loan Facilities and the TCEH Letter of Credit Facility from October 2014 to October 2017 and $2.05 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:

Security (except where noted, debt amounts are principal amounts)	Debt Acquired		Debt Issued/Cash Paid
EFH Corp. 10.875% Notes due 2017	$	1,967	$	—
EFH Corp. Toggle Notes due 2017	3,126		53
EFH Corp. 5.55% Series P Senior Notes due 2014	910		—
EFH Corp. 6.50% Series Q Senior Notes due 2024	549		—
EFH Corp. 6.55% Series R Senior Notes due 2034	459		—
TCEH 10.25% Notes due 2015	1,875		—
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	252		256
EFH Corp 10% Notes due 2020	1,058		561
EFIH 11% Notes due 2021	—		406
EFIH 10% Notes due 2020	—		3,482
EFIH Toggle Notes due 2018	—		1,392
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)	—		1,062
Total (c)	$	12,570	$	10,037

____________

(a) Debt issued amount represents $1.750 billion principal amount less $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. The net proceeds amount of $1.604 billion was used to repay borrowings under the TCEH Senior Secured Facilities, and the remaining transaction costs were funded with cash on hand.

(b) Includes $100 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. The total $390 million of proceeds was used to repurchase debt.

(c) Total debt acquired includes an aggregate $2.228 billion principal amount that is held by EFH Corp. and EFIH, including $564 million of EFH Corp. debt held by EFH Corp. All other debt acquired has been canceled.

In January 2013, EFIH issued $1.391 billion principal amount of debt in exchange for $1.266 billion principal amount of EFH Corp. debt and $139 million principal amount of EFIH debt. See Note 5 to Financial Statements for discussion of these and other debt-related transactions and Note 1 to Financial Statements regarding "Liquidity Considerations" and "Discussions with Creditors." Since inception, the transactions in the liability management program have resulted in the capture of $2.5 billion of debt discount and the extension of approximately $25.7 billion of debt maturities to 2017-2021.

50

EFH Corp. and its subsidiaries (other than Oncor Holdings and its subsidiaries) continue to consider and evaluate possible transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and will likely from time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives. These transactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debt of EFIH, EFCH and TCEH into equity of EFH Corp., EFCH, TCEH and/or any of their subsidiaries.

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

Environmental Matters— See Note 6 to Financial Statements for a discussion of the CSAPR and other EPA actions as well as related litigation.

Greenhouse Gas Emissions — In June 2013, President Obama instructed the EPA to issue by September 2013 a new proposal for greenhouse gas emission standards for new electricity generation units. The EPA had previously issued but not finalized a proposal for such standards. The EPA has sent a new proposal to the White House Office of Management and Budget for review, but the details have not been released. It is uncertain how (if at all) any such proposal would affect our results of operations, liquidity or financial condition.

The President also directed the EPA to propose standards, regulations, or guidelines that address greenhouse gas emissions from modified, reconstructed, and existing power plants by June 2014 and finalize them by June 2015. The proposal is to include guidelines that require states to submit to the EPA their implementing plans and regulations by June 2016. We cannot predict the outcome of this rulemaking. It is uncertain how (if at all) any such proposal would affect our results of operations, liquidity or financial condition.

Mercury and Air Toxics Standard (MATS) — In December 2011 the EPA finalized the MATS rule, which regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases. Any additional control equipment retrofits on our lignite/coal-fueled generation units required to comply with the MATS rule as finalized would need to be installed within three to four years from the April 2012 effective date of the rule. In April 2012, we filed a petition for review of the MATS rule in the D.C. Circuit Court. Certain states and industry participants have also filed petitions for review in the D.C. Circuit Court. We cannot predict the timing or outcome of the D.C. Circuit Court's review of these petitions. In November 2012, the EPA proposed revised standards for new coal-fired generation units and other minor changes to the MATS rule, including changes to the work practice standards affecting all units. In March 2013, the EPA finalized the revised standards for new coal-fired units and certain other minor changes but did not address the work practice standards. In June 2013, the EPA solicited comments on certain proposed changes to these work practice standards. We cannot predict the outcome of this rulemaking.

Regional Haze — SO₂ and NO_X reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions are required either on a unit-by-unit basis or by state participation in an EPA-approved regional trading program such as the CAIR. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze to the EPA, which we believe would not have a material impact on our generation facilities. In December 2011, the EPA proposed a limited disapproval of the SIP due to its reliance on the CAIR and a Federal Implementation Plan for Texas providing that the inclusion in the CSAPR programs meets the regional haze requirements for SO₂ and NO_X reductions. In June 2012, the EPA finalized the limited disapproval of the Texas regional haze SIP, but did not finalize a Federal Implementation Plan for Texas. We cannot predict whether or when the EPA will finalize a Federal Implementation Plan for Texas regarding regional haze or its impact on our results of operations, liquidity or financial condition. In August 2012, we filed a petition for review in the Fifth Circuit Court challenging the EPA's limited disapproval of the Texas regional haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court's decision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of Federal Implementation Plans regarding regional haze. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending regional haze appeals. The consolidated cases now in the D.C. Circuit Court are held in abeyance pending completion of the CSAPR rehearing proceeding described in Note 6 to Financial Statements. We cannot predict when or how the D.C. Circuit Court will rule on these petitions. In May 2013, the TCEQ finalized a required five-year revision to its Regional Haze (SIP), and a court-ordered deadline for the EPA to propose a decision on the Texas Regional Haze SIP was extended to May 2014.

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Financial Services Reform Legislation — In July 2010, the US Congress enacted financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act). The primary purposes of the Financial Reform Act are, among other things: to address systemic risk in the financial system; to establish a Bureau of Consumer Financial Protection with broad powers to enforce consumer protection laws and promulgate rules against unfair, deceptive or abusive practices; to enhance regulation of the derivatives markets, including the requirement for central clearing of over-the-counter derivative instruments and additional capital and margin requirements for certain derivative market participants and to implement a number of new corporate governance requirements for companies with listed or, in some cases, publicly traded securities. While the legislation is broad and detailed, a few key rulemaking decisions remain to be made by federal governmental agencies to fully implement the Financial Reform Act.

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives (Swaps) market. The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we use to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, under the end-user clearing exemption, entities are exempt from these clearing requirements if they (i) are not "Swap Dealers" or "Major Swap Participants" and (ii) use Swaps to hedge or mitigate commercial risk. Existing swaps are grandfathered from the clearing requirements. The legislation mandates significant compliance requirements for any entity that is determined to be a Swap Dealer or Major Swap Participant and additional reporting and recordkeeping requirements for all entities that participate in the derivative markets.

In May 2012, the CFTC published its final rule defining the terms Swap Dealer and Major Swap Participant. Additionally, in July 2012, the CFTC approved the final rules defining the term Swap and the end-user clearing exemption. The definition of the term Swap and the Swap Dealer/Major Swap Participant rule became effective in October 2012. Accordingly, we are required to continually assess our activity to determine if we will be required to register as a Swap Dealer or Major Swap Participant. Based on our assessments to date, we are not a Swap Dealer or Major Swap Participant.

The reporting requirements for entities that are not Swap Dealers or Major Swap Participants became effective in April 2013. However, in April 2013, the CFTC issued a no action letter that precluded any enforcement action on the reporting of Swaps for entities that are not Swap Dealers or Major Swap Participants until August 2013. We are prepared to meet the reporting requirement.

In September 2012, the District Court for the District of Columbia issued an order that vacated and remanded to the CFTC its Position Limit Rule (PLR), which would have been effective in October 2012. The PLR provided for specific position limits related to 28 Core Referenced Futures Contracts, including the NYMEX Henry Hub Natural Gas Futures Contract, the NYMEX Light Sweet Crude Oil Futures Contract and the NYMEX New York Harbor No. 2 Heating Oil Futures Contract. If the PLR had been approved by the court, we would have been required to comply with the portion of the PLR applicable to the contracts noted above, which would result in increased monitoring and reporting requirements. We cannot predict when, or in what form, the CFTC will change the PLR.

The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. However, the final rule for margin requirements for Swap Dealers and Major Swap Participants has not been issued, thus we have not been able to assess the impact of the final rule on our operations. If we were required to post cash collateral on our swap transactions with Swap Dealers and Major Swap Participants, our liquidity would likely be materially impacted, and our ability to enter into OTC derivatives to hedge our commodity and interest rate risks would be significantly limited.

Sunset Review / 2013 Texas Legislative Session — Sunset review is the regular assessment of the continuing need for a state agency to exist, and is grounded in the premise that an agency will be abolished unless legislation is passed to continue its functions. On a specified time schedule, the Texas Sunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agency to the Texas Legislature, which action may include modifying or even abolishing the agency. The PUCT and the RCT were subject to review by the Sunset Commission in 2013.

During the 2013 legislative session that ended in May 2013, the Texas Legislature passed the PUCT Sunset bill and extended the life of the PUCT for 10 years through 2023. The bill did not fundamentally change the management or operation of the PUCT related to electricity issues. The bill included various electric service regulation changes, including clarification on PUCT oversight of ERCOT, protections regarding customer privacy related to advanced meter data and new PUCT authority to issue cease and desist orders. The Legislature did not pass the RCT Sunset bill, but it did extend the life of the RCT until 2017 at which time the RCT will undergo another full Sunset review.

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No legislation passed during the 2013 Texas legislative session, including the Sunset Review actions described above, is expected to have a material impact on our results of operations, liquidity or financial condition.

Oncor Matters with the PUCT —Competitive Renewable Energy Zones (CREZs) — In 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 the western part of 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. At June 30, 2013, Oncor's cumulative CREZ-related capital expenditures totaled $1.772 billion, including $312 million in 2013. Oncor expects that all necessary permitting actions and other requirements and all line and station construction activities for Oncor's CREZ construction projects will be completed by the end of 2013. Additional voltage support projects are expected to be completed by early 2014, with the exception of one series capacitor project that is scheduled to be completed in December 2015.

Transmission Cost Recovery and Rates(PUCT Docket Nos. 41543, 41002 and 40451)—In order to reflect increases or decreases in its wholesale transmission costs, including fees paid to other transmission service providers, Oncor is required to file an update to the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs twice a year. In June 2013, Oncor filed an application to update the TCRF, which will become effective September 1, 2013. This application was designed to increase Oncor's billings for the period from September 2013 through February 2014 by $88 million. In November 2012, Oncor filed an application to update the TCRF, which became effective March 1, 2013. This application was designed to reduce Oncor's billings for the period from March 2013 through August 2013 by $47 million. In June 2012, Oncor filed an application to update the TCRF, which became effective in September 2012. This application was designed to increase Oncor's billings for the period from September 2012 through February 2013 by $129 million.

Transmission Interim Rate Update Applications(PUCT Docket Nos. 41706 and 41166)—In order to reflect changes in its invested transmission capital, PUCT rules allow Oncor to update its transmission cost of service (TCOS) rates by filing up to two interim TCOS rate adjustments in a calendar year. The TCOS rate is charged directly to third-party wholesale transmission providers benefiting from Oncor's transmission system and, through the TCRF component of Oncor's delivery rates, to REPs with retail customers in Oncor's service territory. In July 2013, Oncor filed an application for an interim update of its TCOS rate. Oncor anticipates PUCT approval of the new rate in September 2013. Oncor's annualized revenues will increase by an estimated $71 million with approximately $45 million of this increase recoverable through transmission costs charged to wholesale customers and $26 million recoverable from REPs through the TCRF component of Oncor's delivery rates. In January 2013, Oncor filed an application for an interim update of its TCOS rate. The new rate was approved by the PUCT and became effective in March 2013. Oncor's annualized revenues increased by an estimated $27 million with approximately $17 million of this increase recoverable through transmission costs charged to wholesale customers and $10 million recoverable from REPs through the TCRF component of Oncor's delivery rates.

Application for 2014 Energy Efficiency Cost Recovery Factor(PUCT Docket No. [41544]) — In May 2013, Oncor filed an application with the PUCT to request approval of the energy efficiency cost recovery factor (EECRF) for 2014. PUCT rules require Oncor to make an annual EECRF filing by the first business day in June in each year for implementation on March 1 of the next calendar year. The requested 2014 EECRF was $73 million, which is the same amount established for 2013, and would result in a monthly charge for residential customers of $1.01 as compared to the 2013 residential charge of $1.23 per month. PUCT approval is expected in the third quarter 2013.

Summary—We cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly affect our results of operations, liquidity or financial condition.

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RESULTS OF OPERATIONS

Consolidated Financial Results — Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

See "Competitive Electric Segment — Financial Results" below for a discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities; operating costs; depreciation and amortization and franchise and revenue-based taxes.

SG&A expenses increased $20 million, or 13%, to $177 million in 2013. The increase was driven by the Competitive Electric segment. See "Competitive Electric Segment — Financial Results" below for discussion of variance.

See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges decreased $420 million to $598 million in 2013. The decrease was driven by $339 million in unrealized mark-to-market net gains on interest rate swaps in 2013 compared to $106 million in net losses in 2012. This change was partially offset by $25 million in higher interest expense driven by higher average borrowings. See Note 13 to Financial Statement for details of interest expense and related charges.

Income tax benefit totaled $351 million and $403 million in 2013 and 2012, respectively. Excluding the $183 million income tax benefit recorded in the second quarter 2013 as a result of the approval received from the Joint Committee on Taxation related to the 1997 through 2002 IRS audit (see Note 13 to Financial Statements regarding uncertain tax positions), the effective tax rate was 33.9% and 34.1% in 2013 and 2012, respectively. There were no significant drivers of this change in the effective tax rate.

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) decreased $9 million to $74 million in 2013. Equity in earnings in 2013 included a $3 million favorable tax effect due to resolution of certain income tax positions at Oncor. The decline reflected the effect of milder weather on revenues, lower interest income and higher depreciation, partially offset by higher revenues reflecting higher transmission rates and growth in points of delivery. See Note 2 to Financial Statements.

Net loss decreased $625 million to $71 million in 2013.

• Net loss in the Competitive Electric segment decreased $430 million to $238 million.

• Earnings from the Regulated Delivery segment decreased $9 million to $74 million as discussed above.

• After-tax net income from Corporate and Other activities totaled $93 million in 2013 compared to net expense of $111 million 2012. The change reflects $204 million of income tax benefit, which represents the portion applicable to Corporate and Other activities, recorded in the second quarter 2013 as discussed in Note 13. The amounts in 2013 and 2012 include recurring interest expense on outstanding debt, as well as corporate general and administrative expenses.

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Consolidated Financial Results — Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

See "Competitive Electric Segment — Financial Results" below for a discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities; operating costs; depreciation and amortization and franchise and revenue-based taxes.

SG&A expenses increased $23 million, or 7%, to $338 million in 2013. The increase was driven by the Competitive Electric segment. See "Competitive Electric Segment — Financial Results" below for discussion of variance.

See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges decreased $422 million to $1.382 billion in 2013. The decrease reflected $480 million in higher unrealized mark-to-market net gains on interest rate swaps, partially offset by $58 million in higher interest expense driven by higher average borrowings. See Note 13 to Financial Statements for details of interest expense and related charges.

Income tax benefit totaled $825 million and $583 million in 2013 and 2012, respectively. Excluding the $267 million in total income tax benefit recorded in the first and second quarters of 2013 as a result of resolution of disputed adjustments related to the 1997 through 2002 and 2003 through 2006 IRS audits (see Note 13 to Financial Statements regarding uncertain tax positions), the effective tax rate was 34.7% and 33.8% in 2013 and 2012, respectively. The increase in the effective tax rate reflected $12 million in lower accrued interest on uncertain tax positions.

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) totaled $141 million in both 2013 and 2012. Equity in earnings in 2013 included an $11 million favorable tax effect due to resolution of certain income tax positions at Oncor. The results also reflected higher depreciation, lower interest income and the effect of milder weather, partially offset by higher revenues reflecting higher transmission rates and growth in points of delivery. See Note 2 to Financial Statements.

Net loss decreased $360 million to $640 million in 2013.

• Net loss in the Competitive Electric segment decreased $140 million to $786 million.

• Earnings from the Regulated Delivery segment totaled $141 million in both periods as discussed above.

• After-tax net income from Corporate and Other activities totaled $5 million in 2013 compared to net expense of $215 million in 2012. The change reflects $227 million of income tax benefit, which represents the portion applicable to Corporate and Other activities, recorded in the second quarter 2013 as discussed in Note 13. The amounts in 2013 and 2012 include recurring interest expense on outstanding debt, as well as corporate general and administrative expenses.

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 and analyze 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, and 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 under certain debt securities covenants (see "Financial Condition — Financial Covenants, Credit Rating Provisions and Cross Default Provisions" below).

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Competitive Electric Segment

Financial Results

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Operating revenues	$	1,419		$	1,385		$	2,679		$	2,607
Fuel, purchased power costs and delivery fees	(687		)	(674		)	(1,323		)	(1,302		)
Net gain (loss) from commodity hedging and trading activities	168			(136		)	(29		)	232
Operating costs	(266		)	(228		)	(496		)	(435		)
Depreciation and amortization	(337		)	(334		)	(681		)	(663		)
Selling, general and administrative expenses	(169		)	(156		)	(327		)	(311		)
Franchise and revenue-based taxes	(16		)	(17		)	(33		)	(36		)
Other income	3			7			6			10
Other deductions	(1		)	(4		)	(4		)	(6		)
Interest income	1			9			5			26
Interest expense and related charges	(439		)	(866		)	(1,060		)	(1,521		)
Loss before income taxes	(324		)	(1,014		)	(1,263		)	(1,399		)
Income tax benefit	86			346			477			473
Net loss	$	(238	)	$	(668	)	$	(786	)	$	(926	)

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Competitive Electric Segment

Sales Volume and Customer Count Data

	Three Months Ended June 30,				% Change		Six Months Ended June 30,				% Change
	2013		2012				2013		2012
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential	5,475		6,131		(10.7	)%	10,080		10,791		(6.6	)%
Small business (a)	1,332		1,599		(16.7	)%	2,522		2,937		(14.1	)%
Large business and other customers	2,481		2,596		(4.4	)%	4,799		5,046		(4.9	)%
Total retail electricity	9,288		10,326		(10.1	)%	17,401		18,774		(7.3	)%
Wholesale electricity sales volumes (b)	8,467		5,935		42.7	%	17,536		14,748		18.9	%
Total sales volumes	17,755		16,261		9.2	%	34,937		33,522		4.2	%
Average volume (kilowatt-hours) per residential customer (c)	3,556		3,854		(7.7	)%	6,534		6,736		(3.0	)%
Weather (North Texas average) – percent of normal (d):
Cooling degree days	97.9	%	122.7	%	(20.2	)%	98.2	%	128.1	%	(23.3	)%
Customer counts:
Retail electricity customers (end of period, in thousands) (e):
Residential							1,532		1,578		(2.9	)%
Small business (a)							176		178		(1.1	)%
Large business and other customers							17		16		6.3	%
Total retail electricity customers							1,725		1,772		(2.7	)%

____________

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

(b) Includes net amounts related to sales and purchases of balancing energy in the ERCOT 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 the 10-year period from 2000 to 2010.

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

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Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Three Months Ended June 30,						% Change		Six Months Ended June 30,						% Change
	2013			2012					2013			2012
Operating revenues:
Retail electricity revenues:
Residential	$	714		$	762		(6.3	)%	$	1,311		$	1,340		(2.2	)%
Small business (a)	168			194			(13.4	)%	326			369			(11.7	)%
Large business and other customers	176			180			(2.2	)%	337			354			(4.8	)%
Total retail electricity revenues	1,058			1,136			(6.9	)%	1,974			2,063			(4.3	)%
Wholesale electricity revenues (b) (c)	297			194			53.1	%	571			424			34.7	%
Amortization of intangibles (d)	6			5			20.0	%	11			9			22.2	%
Other operating revenues	58			50			16.0	%	123			111			10.8	%
Total operating revenues	$	1,419		$	1,385		2.5	%	$	2,679		$	2,607		2.8	%
Net gain (loss) from commodity hedging and trading activities:
Realized net gains on settled positions	$	214		$	477		(55.1	)%	$	510		$	998		(48.9	)%
Unrealized net losses	(46		)	(613		)	(92.5	)%	(539		)	(766		)	(29.6	)%
Total	$	168		$	(136	)	—	%	$	(29	)	$	232		—	%

____________

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

(b) Upon settlement of physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, rather than contract price. As a result, these line item amounts include a noncash component that 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,
	2013		2012			2013			2012
Reported in revenues	$	—	$	(3	)	$	(1	)	$	4
Reported in fuel and purchased power costs	4		3			11			(3		)
Net gain	$	4	$	—		$	10		$	1

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

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

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Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Three Months Ended June 30,						% Change		Six Months Ended June 30,						% Change
	2013			2012					2013			2012
Fuel, purchased power costs and delivery fees ($ millions):
Fuel for nuclear facilities	$	39		$	46		(15.2	)%	$	84		$	93		(9.7	)%
Fuel for lignite/coal facilities	208			179			16.2	%	401			354			13.3	%
Total nuclear and lignite/coal facilities	247			225			9.8	%	485			447			8.5	%
Fuel for natural gas facilities and purchased power costs (a)	71			80			(11.3	)%	125			150			(16.7	)%
Amortization of intangibles (b)	10			13			(23.1	)%	19			26			(26.9	)%
Other costs	49			44			11.4	%	98			88			11.4	%
Fuel and purchased power costs	377			362			4.1	%	727			711			2.3	%
Delivery fees (c)	310			312			(0.6	)%	596			591			0.8	%
Total	$	687		$	674		1.9	%	$	1,323		$	1,302		1.6	%
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
Nuclear facilities	$	8.43		$	8.88		(5.1	)%	$	8.45		$	8.83		(4.3	)%
Lignite/coal facilities (d)	$	20.12		$	22.91		(12.2	)%	$	20.44		$	21.59		(5.3	)%
Natural gas facilities and purchased power (e)	$	47.50		$	47.63		(0.3	)%	$	46.84		$	45.43		3.1	%
Delivery fees per MWh	$	33.22		$	30.12		10.3	%	$	34.09		$	31.39		8.6	%
Production and purchased power volumes (GWh):
Nuclear facilities	4,666			5,159			(9.6	)%	9,897			10,497			(5.7	)%
Lignite/coal facilities (f)	12,244			10,057			21.7	%	23,530			20,750			13.4	%
Total nuclear and lignite/coal facilities	16,910			15,216			11.1	%	33,427			31,247			7.0	%
Natural gas facilities	187			381			(50.9	)%	242			523			(53.7	)%
Purchased power (g)	658			664			(0.9	)%	1,268			1,752			(27.6	)%
Total energy supply volumes	17,755			16,261			9.2	%	34,937			33,522			4.2	%
Capacity factors:
Nuclear facilities	92.9		%	102.7		%	(9.5	)%	99.1		%	104.5		%	(5.2	)%
Lignite/coal facilities (f)	69.9		%	57.4		%	21.8	%	67.6		%	59.3		%	14.0	%
Total	75.0		%	67.5		%	11.1	%	74.6		%	69.4		%	7.5	%

____________

(a) See note (b) to the "Revenue and Commodity Hedging and Trading Activities" table 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 and excludes unrealized amounts as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table on previous page.

(e) Excludes volumes related to line loss and power imbalances and unrealized amounts referenced in footnote (d) immediately above.

(f) Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal-fueled units totaling 2,580 GWh and 2,050 GWh for the three months ended June 30, 2013 and 2012, respectively, and 6,930 GWh and 4,970 GWh for the six months ended June 30, 2013 and 2012, respectively.

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

Competitive Electric Segment — Financial Results — Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Operating revenues increased $34 million, or 2%, to $1.419 billion in 2013.

Retail electricity revenues decreased $78 million, or 7%, to $1.058 billion reflecting a $114 million decline in sales volumes partially offset by $36 million in higher average prices. Sales volumes fell 10% driven by declines in residential and business markets. Residential volumes declined 11% reflecting lower average consumption driven by milder weather and a 3% decrease in customer counts reflecting competitive activity. Business market volumes declined 9% reflecting competitive intensity and changes in customer mix. Overall average retail pricing increased 4% driven by residential markets and due in part to higher delivery fees incurred and passed on to customers.

Wholesale electricity revenues increased $103 million, or 53%, to $297 million in 2013 reflecting an $83 million increase due to higher sales volumes and a $20 million increase due to higher average prices. A 43% increase in sales volumes reflected higher volumes generated due to fewer outage days and lower volumes sold in our retail operations. Higher average prices reflected an increase in natural gas prices.

Fuel, purchased power costs and delivery fees increased $13 million, or 2%, to $687 million in 2013. Lignite/coal fuel costs increased $29 million reflecting higher generation volumes and increased western coal in fuel blend. Natural gas fuel costs decreased $12 million and nuclear fuel costs decreased $7 million largely reflecting decreases in generation volumes.

A 22% increase in lignite/coal-fueled generation volumes reflected fewer planned and unplanned outage days in 2013, while nuclear-fueled generation volumes decreased 10% reflecting a planned refueling outage in 2013.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $168 million in net gains and $136 million in net losses for the three months ended June 30, 2013 and 2012, respectively, and is largely reflective of the natural gas hedging program discussed above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program and Other Hedging Activities":

	Three Months Ended June 30, 2013
	Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Total
Hedging positions	$	252		$	(81	)	$	171
Trading positions	(38		)	35			(3		)
Total	$	214		$	(46	)	$	168

	Three Months Ended June 30, 2012
	Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Total
Hedging positions	$	482		$	(640	)	$	(158	)
Trading positions	(5		)	27			22
Total	$	477		$	(613	)	$	(136	)

The decreases in net realized gains and unrealized losses reflected lower volumes and prices of maturing positions in the natural gas hedging program. Lower net unrealized losses also reflected the effect of declining forward natural gas prices in the second quarter 2013 on the value of positions not yet settled.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as purchased power costs, as required by accounting rules, totaled $4 million in net gains in 2013 (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).

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Operating costs increased $38 million, or 17%, to $266 million in 2013. The increase reflected $39 million in higher nuclear generation maintenance costs reflecting activities performed during the planned refueling outage in 2013 and the absence of a spring refueling outage in 2012.

SG&A expenses increased $13 million, or 8%, to $169 million in 2013. The increase reflected $21 million in higher legal and consulting services costs primarily associated with our liability management program, partially offset by $8 million in lower employee-related costs.

Interest income decreased $8 million to $1 million in 2013. The decrease was driven by EFH Corp.'s settlement of the TCEH Demand Notes. See Note 11 to Financial Statements.

Interest expense and related charges decreased $427 million to $439 million in 2013. The decrease was driven by unrealized mark-to-market net gains on interest rate swaps in 2013 compared to unrealized net losses in 2012.

Income tax benefit totaled $86 million and $346 million on pretax losses in 2013 and 2012, respectively. The effective tax rate was 26.5% and 34.1% in 2013 and 2012, respectively. The decrease in the effective tax rate was driven by $21 million in income tax expense recorded as a result of the approval received from the Joint Committee on Taxation related to the 1997 through 2002 IRS audit (see Note 13 to Financial Statements regarding uncertain tax positions).

After-tax loss for the segment decreased $430 million to $238 million in 2013 driven by unrealized gains on interest rate swaps in 2013 and lower unrealized losses from commodity hedging activities.

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Competitive Electric Segment — Financial Results — Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Operating revenues increased $72 million, or 3%, to $2.679 billion in 2013.

Retail electricity revenues decreased $89 million, or 4%, to $1.974 billion reflecting a $151 million decline in sales volumes partially offset by $62 million in higher average prices. Sales volumes fell 7% driven by declines in business and residential markets. Business market volumes were 8% lower reflecting competitive intensity and changes in customer mix. Residential volumes declined 7% driven by a 3% decline in customer counts and milder weather in the second quarter. Overall average retail pricing increased 3% driven by residential markets and due in part to higher delivery fees incurred and passed on to customers.

Wholesale electricity revenues increased $147 million, or 35%, to $571 million in 2013 reflecting an $80 million increase in sales volumes and a $67 million increase due to higher average prices. Sales volumes increased 19% reflecting higher available generation due to fewer outage days and lower volumes sold in our retail operations. Higher average prices reflected an increase in natural gas prices.

Fuel, purchased power costs and delivery fees increased $21 million, or 2%, to $1.323 billion in 2013. Lignite/coal fuel costs increased $47 million reflecting higher generation volumes and increased western coal in fuel blend. Natural gas fuel costs decreased $15 million and nuclear fuel costs decreased $9 million reflecting decreases in generation volumes.

A 13% increase in lignite/coal-fueled generation volumes was driven by fewer unplanned outage days, while nuclear-fueled generation volumes decreased 6% reflecting a planned refueling outage in 2013.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $29 million in net losses and $232 million in net gains for the six months ended June 30, 2013 and 2012, respectively, and is largely reflective of the natural gas hedging program discussed above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program and Other Hedging Activities":

	Six Months Ended June 30, 2013
	Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Total
Hedging positions	$	547		$	(562	)	$	(15	)
Trading positions	(37		)	23			(14		)
Total	$	510		$	(539	)	$	(29	)

	Six Months Ended June 30, 2012
	Net Realized Gains		Net Unrealized Gains (Losses)			Total
Hedging positions	$	993	$	(818	)	$	175
Trading positions	5		52			57
Total	$	998	$	(766	)	$	232

The decreases in net realized gains and unrealized losses reflected lower volumes and prices of maturing positions in the natural gas hedging program. Net unrealized losses in 2012 were mitigated by the effect of unrealized gains on unsettled positions due to decreases in forward natural gas prices.

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 $1 million in net gains in 2013 and 2012, respectively (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).

Operating costs increased $61 million, or 14%, to $496 million in 2013. The increase reflected $50 million in higher nuclear generation maintenance costs reflecting activities performed during the planned refueling outage in 2013 and the absence of a spring refueling outage in 2012. The balance of the increase was driven by higher maintenance costs associated with coal/lignite-fueled generation unit outages, reflecting timing and scope of the activities.

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Depreciation and amortization increased $18 million, or 3%, to $681 million in 2013. The increase primarily reflected early retirements of generation assets during outages at lignite/coal-fueled generation facilities.

SG&A expenses increased $16 million, or 5%, to $327 million in 2013. The increase reflected $34 million in higher legal and consulting services costs primarily associated with our liability management program, partially offset by $12 million in lower employee-related costs and $5 million in lower retail marketing expenses.

Interest income decreased $21 million to $5 million in 2013, driven by EFH Corp.'s settlement of the TCEH Demand Notes. See Note 11 to Financial Statements.

Interest expense and related charges decreased $461 million, or 30%, to $1.060 billion in 2013. The decrease was driven by higher unrealized mark-to-market net gains on interest rate swaps.

Income tax benefit totaled $477 million and $473 million on pretax losses in 2013 and 2012, respectively. The effective tax rate was 37.8% and 33.8% in 2013 and 2012, respectively. The increase in the effective tax rate was driven by $40 million in net income tax benefit recorded in 2013 as a result of resolution in 2013 of disputed adjustments related to the 1997 through 2002 and the 2003 through 2006 IRS audits (see Note 13 to Financial Statements regarding uncertain tax positions).

After-tax loss for the segment decreased $140 million to $786 million in 2013 driven by higher unrealized mark-to-market net gains on interest rate swaps and the income tax benefit related to audit resolutions partially offset by lower net results from commodity hedging activities.

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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, 2013 and 2012. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $530 million and $765 million in unrealized net losses in 2013 and 2012, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. The portfolio consists primarily of economic hedges but also includes proprietary trading positions.

	Six Months Ended June 30,
	2013			2012
Commodity contract net asset at beginning of period	$	1,664		$	3,190
Settlements of positions (a)	(487		)	(990		)
Changes in fair value of positions in the portfolio (b)	(43		)	225
Other activity (c)	24			(31		)
Commodity contract net asset at end of period	$	1,158		$	2,394

____________

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

(b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in forward natural gas prices on the value of positions in the natural gas hedging program (see discussion above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program and Other Hedging Activities"), as well as changes in value of other hedging positions. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.

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

Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values at June 30, 2013, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract net asset at June 30, 2013
Source of fair value	Less than 1 year			1-3 years			Total
Prices actively quoted	$	4		$	(1	)	$	3
Prices provided by other external sources	775			292			1,067
Prices based on models	78			10			88
Total	$	857		$	301		$	1,158
Percentage of total fair value	74		%	26		%	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's North Hub that are deemed active markets extend through 2015 and over-the-counter quotes for natural gas generally extend through 2016, depending upon delivery point. The "prices based on models" category contains the value of all non-exchange-traded options valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 8 to Financial Statements for fair value disclosures and discussion of fair value measurements.

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FINANCIAL CONDITION

Cash Flows — Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012 — Cash used in operating activities totaled $621 million in 2013 compared to cash provided by operating activities of $51 million in 2012. The change of $672 million reflected a decrease of $488 million in net realized gains from commodity hedging and trading activities, and a net use of cash related to margin deposits totaling $199 million primarily due to margin deposits returned in 2013 as positions in the natural gas hedging program matured. The change in cash flows also reflected an increase of $187 million in interest payments, offset by a decrease of approximately $175 million in working capital used reflecting timing of accounts payable and accrued expense payments.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $82 million and $98 million for the six months ended June 30, 2013 and 2012, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice, and amortization of intangible net assets arising from purchase accounting that is reported in various other income statement line items including operating revenues and fuel and purchased power costs and delivery fees.

Cash used in financing activities totaled $52 million in 2013 and cash provided by financing activities totaled $640 million in 2012. Activity in 2012 reflected the issuance of $1.150 billion of EFIH 11.75% Notes, the majority of the proceeds from which were used to repay $950 million in borrowings under the TCEH Revolving Credit Facility.

See Note 5 to Financial Statements for further detail of short-term borrowings and long-term debt.

Cash provided by investing activities totaled $323 million in 2013 and cash used in investing activities totaled $454 million in 2012. Amounts provided in 2013 reflected the use by EFH Corp. of $680 million of cash previously in escrow (reported as restricted cash at December 31, 2012) to repay the balance of the TCEH Demand Notes (see Note 11 to Financial Statements). Capital expenditures (excluding nuclear fuel purchases) decreased $130 million to $274 million in 2013 reflecting decreased environmental-related spending, partially offset by increased spending on lignite mine development and generation plant projects. Nuclear fuel purchases decreased $69 million to $27 million due to timing of refueling cycles. Cash used in investing activities in 2013 also included $40 million used to acquire the owner participant interest in a trust established to lease six natural gas-fired combustion turbines to TCEH. See Note 5 to Financial Statements and discussion below under "Debt Financing Activity" regarding the debt obligation of the trust.

Debt Activity— Activities related to short-term borrowings and long-term debt during the six months ended June 30, 2013 are as follows (all amounts presented are principal, and settlements include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

	Borrowings		Settlements
TCEH (a)	$	385	$	(79	)
EFCH	—		(2		)
EFIH (b)	1,474		(139		)
EFH Corp. (c)	—		(1,269		)
Total long-term	1,859		(1,489		)
Total short-term – TCEH (d)	37		—
Total	$	1,896	$	(1,489	)

___________

(a) Borrowings represent noncash principal increases of TCEH Term Loan Facilities for fees in consideration of the extension of $645 million of commitments under the TCEH Revolving Credit Facility and debt assumed of $45 million in connection with the purchase of the interest in a trust holding certain combustion turbines as discussed above. Settlements represent $73 million of payments of principal at scheduled maturity or mandatory tender dates and $6 million of payments of capital lease liabilities.

(b) Borrowings represent $1.391 billion of EFIH debt issued in exchanges for EFH Corp. and EFIH debt in January 2013 and $83 million of noncash principal increases of EFIH Toggle Notes issued in June 2013 in payment of accrued interest as discussed below under "EFIH Toggle Notes Interest Election." Settlements represent noncash retirements related to January 2013 debt exchanges.

(c) Settlements include $1.266 billion of noncash retirements related to January 2013 debt exchanges.

(d) Short-term amount represents net borrowings under the accounts receivable securitization program (see Note 4 to Financial Statements).

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See Note 5 to Financial Statements for further detail of long-term debt and other financing arrangements.

Available Liquidity — The following table summarizes changes in available liquidity for the six months ended June 30, 2013:

	Available Liquidity
	June 30, 2013		December 31, 2012		Change
Cash and cash equivalents – EFH Corp. (parent entity)	$	103	$	314	$	(211	)
Cash and cash equivalents – EFIH (a)	389		1,104		(715		)
Cash and cash equivalents – TCEH	1,071		1,175		(104		)
TCEH Letter of Credit Facility	133		183		(50		)
Total liquidity	$	1,696	$	2,776	$	(1,080	)

___________

(a) December 31, 2012 includes $680 million in cash held in escrow that was used in January 2013 to settle the TCEH Demand Notes.

The decrease in available liquidity of $1.080 million in the six months ended June 30, 2013 was driven by $621 million in cash used in operating activities and $301 million in cash used for capital expenditures, including nuclear fuel purchases. See discussion of cash flows above.

Debt Capacity—We believe that EFH Corp., EFIH and TCEH are permitted under applicable debt agreements to issue additional debt (in each case, subject to certain exceptions and conditions set forth in our applicable debt documents) as follows:

• EFH Corp. and EFIH collectively are permitted to issue up to approximately $250 million of additional aggregate principal amount of debt secured by EFIH's equity interest in Oncor Holdings on a second-priority basis;

• EFIH is permitted under its debt agreements to issue up to approximately $375 million of additional principal amount of senior unsecured debt (subject to certain exceptions and conditions set forth in its debt agreements). Such unsecured debt may be incurred for, among other things, exchanges for EFH Corp. unsecured debt;

• TCEH is permitted to issue approximately $2.3 billion of additional aggregate principal amount of debt secured by substantially all of the assets of TCEH and certain of its subsidiaries (of which $410 million can be on a first-priority basis and the remainder on a second-priority basis), and

• TCEH is permitted to issue an unlimited amount of additional first-priority debt in order to refinance the first-priority debt outstanding under the TCEH Senior Secured Facilities.

These amounts are estimates based on our current interpretation of the covenants set forth in our debt agreements and do not take into account exceptions in the debt agreements that may allow for the incurrence of additional secured or unsecured debt, including, but not limited to, acquisition debt, refinancing debt, capital leases and hedging obligations. Moreover, such amounts could change from time to time as a result of, among other things, the termination of any debt agreement (or specific terms therein) or amendments to the debt agreements that result from negotiations with new or existing lenders. In addition, covenants included in agreements governing additional future debt may impose greater restrictions on our incurrence of secured or unsecured debt. Consequently, the actual amount of senior secured or unsecured debt that we are permitted to incur under our debt agreements could be materially different than the amounts provided above.

Pension and OPEB Plan Funding — See Note 10 to Financial Statements.

EFIH Toggle Notes Interest Election — EFIH has the option every six months at its discretion, ending with the interest payment due June 2016, to use the payment-in-kind (PIK) feature of its toggle notes ($1.393 billion aggregate principal amount issued in December 2012 and January 2013) in lieu of making cash interest payments. Once EFIH makes a PIK election, the election is valid for each succeeding interest payment period until it revokes 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.

EFIH made its June 2013 interest payment and expects to make its December 2013 interest payment on the EFIH Toggle Notes by using the PIK feature of those notes. During the applicable PIK interest periods, the interest rate on these notes is increased from 11.25% to 12.25%. As a result of the PIK election, EFIH increased the aggregate principal amount of the notes by $83 million in June 2013 and is expected to issue an additional $90 million in December 2013. See Note 5 to Financial Statements for further discussion of the EFIH Toggle Notes.

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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 posting obligations. At June 30, 2013, approximately 90% of the 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 posting requirements for those hedging transactions. See Note 5 to Financial Statements for more information about the TCEH Senior Secured Facilities.

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. At June 30, 2013, essentially all cash collateral held was unrestricted. 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, which would reduce liquidity in the event the cash was not restricted.

At June 30, 2013, approximately 24 million MMBtu of positions related to the natural gas hedging program were not directly secured on an asset-lien basis and thus are subject to cash collateral or letter of credit posting requirements if natural gas prices increase.

At June 30, 2013, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $15 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $69 million posted at December 31, 2012;

• $404 million in cash has been received from counterparties, net of $2 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $598 million received, net of $2 million in cash posted, at December 31, 2012;

• $404 million in letters of credit have been posted with counterparties, as compared to $376 million posted at December 31, 2012, and

• $3 million in letters of credit have been received from counterparties, as compared to $22 million received at December 31, 2012.

Income Tax Matters — EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. EFH Corp. is a corporate member of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH is classified as a disregarded entity for US federal income tax purposes. Prior to the restructuring transaction in April 2013 discussed below, EFCH was a corporate member of the group. Oncor is a partnership for US federal income tax purposes and is not a corporate member of the EFH Corp. consolidated group. Pursuant to applicable US Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.

EFH Corp. and its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) are parties to a Federal and State Income Tax Allocation Agreement, which provides, among other things, that any corporate member or disregarded entity in the group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. EFH Corp., Oncor Holdings and Oncor are parties to a separate tax sharing agreement, which governs the computation of federal income tax liability between EFH Corp., on one hand, and Oncor Holdings and Oncor and its subsidiary, on the other hand, and similarly provides, among other things, that each of Oncor Holdings and Oncor will make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return.

In April 2013, we received a private letter ruling from the IRS in which the IRS ruled that upon the consummation of certain internal corporate transactions (the Transactions) involving EFH Corp. and EFCH, an excess loss account (ELA) and a deferred intercompany gain (DIG), described immediately below, would be eliminated without causing the recognition of tax gain or loss. On April 15, 2013, EFH Corp. and EFCH completed the Transactions, resulting in the elimination of the ELA and the DIG.

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An ELA and a DIG were reflected in the tax basis of the EFCH stock held by EFH Corp. The ELA, totaling approximately $19 billion, was created in connection with financing transactions related to the Merger. The DIG, totaling approximately $4 billion, was created as a result of an internal corporate reorganization prior to the Merger. The financing transactions and internal corporate reorganization that created the ELA and DIG involved TCEH and its assets, but not EFIH or Oncor Holdings. The difference between EFH Corp.'s tax basis in the stock of EFCH and the amount of the stock investment for financial reporting purposes represented an outside basis difference. Because we had tax strategies available to us that we believed would avoid triggering income tax payments upon a transaction involving our investment in EFCH, we did not record deferred income tax liabilities with respect to this outside basis difference.

In consummating the Transactions, (i) EFH Corp. contributed all of the stock of EFCH to a newly formed wholly owned subsidiary, EFH2 Corp. (EFH2) (a Texas corporation), (ii) EFCH was converted from a Texas corporation into a Delaware limited liability company and was renamed Energy Future Competitive Holdings Company LLC and (iii) EFH Corp. merged with and into EFH2, with EFH2 continuing as the surviving corporation. In connection with the Transactions, EFH2 was renamed Energy Future Holdings Corp.

Immediately after the consummation of the Transactions, each of EFH2 and EFCH had the same management, assets, businesses and operations as EFH Corp. and EFCH had, respectively, immediately prior to the consummation of the Transactions. The Transactions had no, and will have no, effect on EFH2's or EFCH's (or their respective subsidiaries') results of operations, liquidity or financial statements. EFH2 and EFH Corp. are both referred to as EFH Corp. throughout this quarterly report on Form 10-Q.

Income Tax Payments — In the next twelve months, income tax payments related to the Texas margin tax are expected to total approximately $62 million, and we expect to pay approximately $8 million to the IRS. Income tax payments (all Texas margin tax) totaled $51 million and $58 million for the six months ended June 30, 2013 and 2012, respectively.

See Note 13 to Financial Statements for discussion of uncertain tax positions.

Interest Rate Swap Transactions — See Note 5 to Financial Statements for discussion of TCEH's interest rate swaps.

Accounts Receivable Securitization Program— See Note 4 to Financial Statements for discussion of the Accounts Receivable Securitization Program.

Distributions of Earnings from Oncor Holdings —Oncor Holdings' distributions of earnings to us totaled $80 million and $69 million for the six months ended June 30, 2013 and 2012, respectively. Oncor Holdings' board of directors also declared a distribution to us totaling $68 million payable on August 1, 2013. See Note 2 to Financial Statements for discussion of limitations on amounts Oncor can distribute to its members.

Oncor has credit risk exposure to trade accounts receivable from TXU Energy, which relate to delivery services provided by Oncor to TXU Energy. These trade accounts receivable amounts totaled $133 million, net of $7 million in letters of credit posted by TCEH, at June 30, 2013. Because Oncor had committed to the PUCT, in connection with the Merger, that it would not seek regulatory rate recovery for credit losses associated with affiliated REPs, Oncor's earnings would be reduced by the amount (after-tax) of any default by TXU Energy.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of the TCEH Senior Secured Facilities and the accounts receivable securitization program (see Note 4 to Financial Statements) contain an identical maintenance covenant with respect to leverage ratio. At June 30, 2013, we were in compliance with such covenants.

Covenants and Restrictions under Financing Arrangements— The TCEH Senior Secured Facilities and the indentures governing substantially all of the debt EFH Corp.'s subsidiaries (excluding Oncor) have issued in connection with, and subsequent to, the Merger contain covenants that could have a material impact on our liquidity and operations. In particular, the TCEH Senior Secured Facilities include a requirement to timely deliver to the lenders copies of audited annual financial statements that are not qualified as to the status of TCEH and its subsidiaries as a going concern. We need to refinance the $3.8 billion of maturities due in October 2014 under the TCEH Senior Secured Facilities in order to satisfy this covenant (or obtain a waiver of the covenant) with respect to our audited annual financial statements for the year ended December 31, 2013.

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Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes) for the twelve months ended June 30, 2013 totaled $4.759 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, 2013 and 2012.

The table below summarizes TCEH's secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and the TCEH accounts receivable securitization program and other EFH Corp., EFIH and TCEH financial ratios that are applicable under certain thresholds 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. 10.875% Notes and EFH Corp. Toggle Notes and the EFIH Notes. The debt incurrence and restricted payments/limitations on investments covenants thresholds presented below represent levels that must be met in order for EFH Corp., EFIH or TCEH to incur certain debt or make certain restricted payments and/or investments. See "Debt Capacity" above for discussion regarding additional debt EFH Corp., EFIH and TCEH are permitted to issue under applicable debt agreements. TCEH is in compliance with its maintenance covenants. In January 2013, in accordance with amendments to the terms of the EFH Corp. 9.75% Notes and EFH Corp. 10% Notes and their governing indentures, restrictive covenants under those notes were removed (see Note 5 to Financial Statements).

	June 30, 2013	December 31, 2012	Threshold Level at June 30, 2013
Maintenance Covenant:
TCEH Senior Secured Facilities and TCEH's accounts receivable securitization program:
Secured debt to Adjusted EBITDA ratio	7.06 to 1.00	5.88 to 1.00	Must not exceed 8.00 to 1.00 (a)
Debt Incurrence Thresholds:
EFIH Notes:
EFIH fixed charge coverage ratio (b)	0.2 to 1.0	0.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes:
TCEH fixed charge coverage ratio	1.0 to 1.0	1.2 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.0 to 1.0	1.2 to 1.0	At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Thresholds:
EFH Corp. 10.875% Notes and Toggle Notes:
General restrictions (Sponsor Group payments):
EFH Corp. leverage ratio	11.9 to 1.0	10.1 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 (b) (c)	1.7 to 1.0	2.1 to 1.0	At least 2.0 to 1.0
General restrictions (EFH Corp. payments):
EFIH fixed charge coverage ratio (b) (c)	0.2 to 1.0	0.3 to 1.0	At least 2.0 to 1.0
EFIH leverage ratio	7.8 to 1.0	7.0 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	1.0 to 1.0	1.2 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	10.1 to 1.0	8.5 to 1.0	Equal to or less than 6.5 to 1.0

___________

(a) Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities and up to $1.5 billion ($906 million excluded at June 30, 2013) 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.

(b) Calculations exclude interest income on the EFH Corp. 10.875% Notes and Toggle Notes that EFIH distributed as a dividend to EFH Corp. in January 2013 (see Note 5 to Financial Statements).

(c) The EFIH fixed charge coverage ratio for paying dividends or repurchasing or making distributions in respect of capital stock (EFH Corp. payments) excludes the results of Oncor Holdings and its subsidiaries. The EFIH fixed charge coverage ratio for making investments (non-EFH Corp. payments) includes 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, at June 30, 2013, counterparties to those contracts could have required TCEH to post up to an aggregate of $13 million in additional collateral. This amount largely represents the below market terms of these contracts at June 30, 2013; 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. At June 30, 2013, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $24 million, with $11 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, at June 30, 2013, TCEH posted letters of credit in the amount of $65 million, which are subject to adjustments.

The RCT has rules in place to assure that parties can meet their mining reclamation obligations, including through self-bonding when appropriate. If Luminant Generation Company LLC (a subsidiary of TCEH) does not continue to meet the self-bonding requirements as applied by the RCT, TCEH may be required to post cash, letter of credit or other tangible assets as collateral support in an amount currently estimated to be approximately $850 million to $1.1 billion. The actual amount (if required) could vary depending upon numerous factors, including the amount of Luminant Generation Company LLC's self-bond accepted by the RCT and the level of mining reclamation obligations. The estimated posting amount relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts. As disclosed in Note 13 to Financial Statements, our mining reclamation liability totaled $101 million at June 30, 2013, which represents the present value of estimated costs to complete reclamation of land mined or being mined.

ERCOT has rules in place to assure adequate credit worthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $200 million at June 30, 2013 (which is subject to daily adjustments based on settlement activity with ERCOT).

Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH 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.

Other arrangements of EFH Corp. and its subsidiaries, including Oncor's credit facility, the accounts receivable securitization program (see Note 4 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.

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

A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the accounts receivable securitization program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.616 billion at June 30, 2013, excluding $19 million held by EFH Corp.) 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.

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Under the terms of a TCEH rail car lease, which has $39 million in remaining lease payments at June 30, 2013 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in an aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Under the terms of another TCEH rail car lease, which has $43 million in remaining lease payments at June 30, 2013 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 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 or of any debt that EFIH guarantees 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 Energy Receivables Company (a direct subsidiary of TCEH) has a cross default threshold of $50,000. If any of these cross default provisions were triggered, the program could be terminated.

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

Each ofTCEH'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 and TCEH Senior Secured Notes contain 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.

Guarantees — See Note 6 to Financial Statements for discussion of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

See Notes 2 and 6 to Financial Statements regarding VIEs and guarantees, respectively.

COMMITMENTS AND CONTINGENCIES

See Note 6 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, 2013 that are expected to materially impact our financial statements.

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Item3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Market risk is the risk that in the ordinary course of business we may experience a loss in value as a result of changes in market conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. 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 hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices.

Risk Oversight

We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive 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, position review, Value at Risk (VaR) methodologies and stress test scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validation and reporting, and 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.

Natural Gas Hedging Program —See "Significant Activities and Events and Items Influencing Future Performance" above and Note 9 to Financial Statements 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 days.

	June 30, 2013		December 31, 2012
Month-end average Trading VaR:	$	3	$	7
Month-end high Trading VaR:	$	4	$	12
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.

	June 30, 2013		December 31, 2012
Month-end average MtM VaR:	$	83	$	132
Month-end high MtM VaR:	$	97	$	206
Month-end low MtM VaR:	$	68	$	96

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), based on a 95% confidence level and an assumed holding period of five to 60 days.

	June 30, 2013		December 31, 2012
Month-end average EaR:	$	28	$	109
Month-end high EaR:	$	31	$	161
Month-end low EaR:	$	23	$	77

The decrease in the Trading VaR risk measure above reflected lower market volatility and a decrease in trading positions. The decreases in the MtM VaR and EaR risk measures above reflected a reduction of positions in the natural gas hedging program due to maturities and lower market volatility.

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Interest Rate Risk

At June 30, 2013, 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 $16 million, taking into account the interest rate swaps discussed in Note 5 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 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 setoff. 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. Further, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material 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 $1.239 billion at June 30, 2013. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at June 30, 2013 include $520 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $61 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. At June 30, 2013, the exposure to credit risk from these counterparties totaled $719 million taking into account the netting provisions of the master agreements described above but before taking into account $433 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $286 million increased $31 million in the six months ended June 30, 2013.

Of this $286 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 at June 30, 2013 arising from wholesale trade receivables, commodity contracts and hedging and trading activities, all of which matures in two years or less. This credit exposure represents wholesale trade accounts receivable and net asset positions in the balance sheet arising from hedging and trading activities after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 9 to Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

	Exposure Before Credit Collateral			Credit Collateral		Net Exposure
Investment grade	$	714		$	431	$	283
Noninvestment grade	5			2		3
Totals	$	719		$	433	$	286
Investment grade	99.3		%			99.0		%
Noninvestment grade	0.7		%			1.0		%

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 impact on future results of operations, liquidity and financial condition.

Significant (10% or greater) concentration of credit exposure exists with four counterparties, which represented 19%, 17%, 15% and 13% of the $286 million net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, each of which is rated as investment grade, and the importance of our business relationship with the counterparties.

With respect to credit risk related to the natural gas hedging program, all of the transaction volumes are with counterparties that have an investment grade credit rating. 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 may occur in the future, including such matters as activities under our liability management program, financial or operational 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," "unlikely," "expected," "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 our 2012 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 US Federal Energy Regulatory Commission, the NERC, the TRE, the PUCT, the RCT, the NRC, the EPA, the TCEQ, the US Mine Safety and Health Administration 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;

◦ self-bonding requirements;

◦ acquisition and disposal of assets and facilities;

◦ development, construction and operation of facilities;

◦ decommissioning costs;

◦ present or prospective wholesale and retail competition;

◦ changes in tax laws and policies;

◦ changes in and compliance with environmental and safety laws and policies, including the CSAPR, MATS, and greenhouse gas and other 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 an economic downturn;

• our ability to collect trade receivables from counterparties;

• 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, including the price of natural gas;

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

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

• our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;

• weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cybersecurity threats or activities;

• population growth or decline, or changes in market supply or 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;

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

• 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;

• the willingness of our lenders to extend the maturities of our debt instruments and the terms and conditions of any such extensions;

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

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

• 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, reach agreement with our creditors on the terms of any change in our capital structure, or otherwise address our significant interest payments and debt maturities, including through the potential exchange of debt securities for debt or equity securities or potential waiver of any covenants contained in our debt agreements;

• any defaults under certain of our financing arrangements that could trigger cross default or cross acceleration provisions under other financing arrangements;

• our ability to make intercompany loans or otherwise transfer funds among different entities in our corporate structure;

• 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, including joint and several liability exposure under ERISA;

• 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;

• adverse claims by our creditors or holders of our debt securities;

• our ability to effectively execute our operational strategy, and

• our ability to implement cost reduction initiatives.

Any forward-looking statement speaks only at 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 at the end of the current period included in this quarterly report. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this quarterly report, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Reference is made to the discussion in Note 6 to Financial Statements regarding legal proceedings.

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the risk factors discussed under Item 1A, "Risk Factors" in our 2012 Form 10-K. The risks described in such report are not the only risks facing our Company.

Item 4. MINE SAFETY DISCLOSURES

We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects US mines, including ours, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 95(a) to this quarterly report on Form 10-Q.

Item 5. OTHER INFORMATION

In June 2013, in recognition of Paul Keglevic's, EFH Corp. Chief Financial Officer, leadership of the company's efforts to eliminate the ELA and DIG tax attributes and effectively resolve the 2003-2006 IRS audit as well as on-going contributions to our liability management program, the Organization and Compensation Committee of the EFH Corp. Board of Directors approved a discretionary cash bonus of $375,000, which was paid in June 2013.

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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
(3(i))	Articles of Incorporation
3(a)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	3(a)	—	Restated Certificate of Formation of Energy Future Holdings Corp.
(3(ii))	By-laws
3(b)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	3(b)	—	Amended and Restated Bylaws of Energy Future Holdings Corp.
(31)	Rule 13a - 14(a)/15d-14(a) Certifications
31(a)			—	Certification of John F. Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32)	Section 1350 Certifications
32(a)			—	Certification of John F. 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.
(95)	Mine Safety Disclosures
95(a)			—	Mine Safety Disclosures
(99)	Additional Exhibits
99(a)			—	Condensed Statement of Consolidated Income – Twelve Months Ended June 30, 2013.
99(b)			—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2013 and 2012.
99(c)			—	Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2013 and 2012.
99(d)			—	Energy Future Intermediate Holding Company LLC Consolidated Adjusted EBITDA reconciliation for the six and twelve months ended June 30, 2013 and 2012.

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Exhibits	Previously Filed With File Number*	As Exhibit
	XBRL Data Files
101.INS			—	XBRL Instance Document**
101.SCH			—	XBRL Taxonomy Extension Schema Document**
101.CAL			—	XBRL Taxonomy Extension Calculation Document**
101.DEF			—	XBRL Taxonomy Extension Definition Document**
101.LAB			—	XBRL Taxonomy Extension Labels Document**
101.PRE			—	XBRL Taxonomy Extension Presentation Document**

____________

* Incorporated herein by reference

** Furnished herewith

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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: August 1, 2013

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