Energy Future Competitive 10-Q 2013 Q3 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 SEPTEMBER 30, 2013

— OR —

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

Commission File Number 001-34543

Energy Future Competitive Holdings Company LLC

(formerly Energy Future Competitive Holdings Company)

(Exact name of registrant as specified in its charter)

Delaware	75-1837355
(State 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 October 31, 2013, the outstanding membership interest in Energy Future Competitive Holdings Company LLC was directly held by Energy Future Holdings Corp.

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

TABLE OF CONTENTS

		PAGE
GLOSSARY		ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Statements of Consolidated Income (Loss) — Three and Nine Months Ended September 30, 2013 and 2012	1
	Condensed Statements of Consolidated Comprehensive Income (Loss) — Three and Nine Months Ended September 30, 2013 and 2012	1
	Condensed Statements of Consolidated Cash Flows — Nine Months Ended September 30, 2013 and 2012	2
	Condensed Consolidated Balance Sheets — September 30, 2013 and December 31, 2012	3
	Notes to Condensed Consolidated Financial Statements	4
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	52
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	75
Item 4.	Controls and Procedures	80
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	80
Item 1A.	Risk Factors	80
Item 4.	Mine Safety Disclosures	80
Item 6.	Exhibits	82
SIGNATURE		84

Energy Future Competitive Holdings Company LLC's (EFCH) (formerly known as Energy Future Holdings Company) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the Energy Future Holdings Corp. (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. EFCH also from time to time makes available to the public, free of charge, on the EFH Corp. website certain financial statements of its wholly owned subsidiary, Texas Competitive Electric Holdings Company LLC. 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 EFCH has filed as an exhibit to this quarterly report on Form 10-Q or that EFCH has 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 EFCH and its subsidiaries occasionally make references to EFH Corp., EFCH (or "we," "our," "us" or "the company"), TCEH, TXU Energy or Luminant when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the relevant parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

i

GLOSSARY

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

2012 Form 10-K	EFCH'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 debt arrangements of TCEH and EFH Corp. 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 TCEH's and EFH Corp.'s Adjusted EBITDA in this Form 10-Q (see reconciliations in Exhibits 99(b) and 99(c)) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in the debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with US GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management's discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
CAIR	Clean Air Interstate Rule
CFTC	US Commodity Futures Trading Commission
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
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
Fifth Circuit Court	US Court of Appeals for the Fifth Circuit
GAAP	generally accepted accounting principles
GWh	gigawatt-hours
ICE	the IntercontinentalExchange, a commodity exchange
IRS	US Internal Revenue Service
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

ii

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
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
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.
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
SG&A	selling, general and administrative
SO2	sulfur dioxide

iii

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.
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 COMPETITIVE HOLDINGS COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(millions of dollars)
Operating revenues	$	1,893		$	1,752		$	4,572		$	4,358
Fuel, purchased power costs and delivery fees	(852		)	(850		)	(2,175		)	(2,153		)
Net gain (loss) from commodity hedging and trading activities	58			(3		)	29			229
Operating costs	(189		)	(201		)	(685		)	(636		)
Depreciation and amortization	(331		)	(328		)	(1,012		)	(992		)
Selling, general and administrative expenses	(175		)	(174		)	(502		)	(484		)
Franchise and revenue-based taxes	(18		)	(19		)	(51		)	(55		)
Other income (Note 12)	1			2			7			12
Other deductions (Note 12)	(8		)	(30		)	(12		)	(37		)
Interest income	1			10			5			36
Interest expense and related charges (Note 12)	(340		)	(772		)	(1,338		)	(2,268		)
Income (loss) before income taxes	40			(613		)	(1,162		)	(1,990		)
Income tax benefit	17			228			476			692
Net income (loss)	$	57		$	(385	)	$	(686	)	$	(1,298	)

See Notes to Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013			2012
	(millions of dollars)
Net income (loss)	$	57	$	(385	)	$	(686	)	$	(1,298	)
Other comprehensive income, net of tax effects – cash flow hedges derivative value net loss related to hedged transactions recognized during the period and reported in interest expense and related charges (net of tax benefit of $1, $1, $3 and $3)	1		1			5			5
Comprehensive income (loss)	$	58	$	(384	)	$	(681	)	$	(1,293	)

See Notes to Financial Statements.

1

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)
	Nine Months Ended September 30,
	2013			2012
	(millions of dollars)
Cash flows — operating activities:
Net loss	$	(686	)	$	(1,298	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation and amortization	1,142			1,137
Deferred income tax benefit, net	(401		)	(716		)
Income tax benefit due to audit resolutions (Note 12)	(80		)	—
Unrealized net loss from mark-to-market valuations of commodity positions	693			1,290
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps (Note 5)	(899		)	16
Interest expense on toggle notes payable in additional principal (Notes 5 and 12)	—			136
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 12)	209			152
Interest expense related to pushed-down debt of parent (Notes 5 and 12)	5			57
Asset impairments (Note 12)	3			24
Bad debt expense (Note 4)	23			20
Accretion expense related primarily to mining reclamation obligations (Note 12)	24			27
Stock-based incentive compensation expense	1			5
Other, net	2			10
Changes in operating assets and liabilities:
Margin deposits, net	(197		)	(321		)
Other operating assets and liabilities	40			(210		)
Cash provided by (used in) operating activities	(121		)	329
Cash flows — financing activities:
Repayments/repurchases of long-term debt (Note 5)	(94		)	(30		)
Net short-term borrowings under accounts receivable securitization program (Note 4)	90			80
Decrease in other short-term borrowings (Note 5)	—			(385		)
Notes/advances due to affiliates	4			—
Decrease in income tax-related note payable to Oncor (Note 11)	—			(20		)
Settlement of reimbursement agreements with Oncor (Note 11)	—			(159		)
Contributions from noncontrolling interests (Note 7)	3			6
Sale/leaseback of equipment	—			15
Other, net	(10		)	—
Cash used in financing activities	(7		)	(493		)
Cash flows — investing activities:
Capital expenditures	(353		)	(498		)
Nuclear fuel purchases	(59		)	(155		)
Settlements of notes due from affiliates	698			922
Purchase of right to use certain computer-related assets from parent (Note 11)	(6		)	—
Proceeds from sales of assets	3			1
Acquisition of combustion turbine trust interest (Note 5)	(40		)	—
Changes in restricted cash	—			112
Purchases of environmental allowances and credits	(13		)	(19		)
Proceeds from sales of nuclear decommissioning trust fund securities	128			56
Investments in nuclear decommissioning trust fund securities	(140		)	(68		)
Other, net	(3		)	2
Cash provided by investing activities	215			353
Net change in cash and cash equivalents	87			189
Cash and cash equivalents — beginning balance	1,175			120
Cash and cash equivalents — ending balance	$	1,262		$	309

See Notes to Financial Statements.

2

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
	September 30, 2013			December 31, 2012
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	1,262		$	1,175
Trade accounts receivable — net (includes $573 and $445 in pledged amounts related to a VIE (Notes 2 and 4))	796			710
Notes receivable from parent (Note 11)	—			698
Income taxes receivable from parent	7			—
Inventories (Note 12)	400			393
Commodity and other derivative contractual assets (Note 9)	973			1,463
Margin deposits related to commodity positions	21			71
Other current assets	34			120
Total current assets	3,493			4,630
Restricted cash (Note 12)	947			947
Investments (Note 12)	787			710
Property, plant and equipment — net (Note 12)	17,961			18,556
Goodwill (Note 3)	4,952			4,952
Identifiable intangible assets — net (Note 3)	1,736			1,781
Commodity and other derivative contractual assets (Note 9)	159			586
Other noncurrent assets, primarily unamortized debt amendment and issuance costs	859			811
Total assets	$	30,894		$	32,973
LIABILITIES AND MEMBERSHIP INTERESTS/EQUITY
Current liabilities:
Short-term borrowings (includes $172 and $82 related to a VIE (Notes 2 and 5))	$	2,226		$	2,136
Long-term debt due currently (Note 5)	32			96
Trade accounts payable	354			389
Trade accounts and other payables to affiliates	205			139
Notes payable to parent (Note 11)	92			81
Commodity and other derivative contractual liabilities (Note 9)	594			894
Margin deposits related to commodity positions	353			600
Accumulated deferred income taxes	36			49
Accrued income taxes payable to parent (Note 11)	—			31
Accrued taxes other than income	95			17
Accrued interest	532			407
Other current liabilities	219			255
Total current liabilities	4,738			5,094
Accumulated deferred income taxes	3,347			3,759
Commodity and other derivative contractual liabilities (Note 9)	782			1,556
Notes or other liabilities due to affiliates	2			5
Long-term debt held by affiliates (Note 11)	382			382
Long-term debt, less amounts due currently (Note 5)	29,770			29,928
Affiliate tax sharing liability (Note 12)	723			—
Other noncurrent liabilities and deferred credits (Note 12)	1,793			2,643
Total liabilities	41,537			43,367
Commitments and Contingencies (Note 6)
Membership interests/equity (Note 7):
EFCH shareholder's equity	—			(10,506		)
EFCH membership interests	(10,748		)	—
Noncontrolling interests in subsidiaries	105			112
Total membership interests/equity	(10,643		)	(10,394		)
Total liabilities and membership interests/equity	$	30,894		$	32,973

See Notes to Financial Statements.

3

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC

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 EFCH and/or its subsidiaries, as apparent in the context. See "Glossary" for defined terms.

EFCH, a wholly owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. In April 2013, EFCH was converted from a Texas corporation to a Delaware limited liability company. The conversion did not result in a change in the management, assets, businesses or operations of EFCH. We conduct our operations almost entirely through our wholly owned subsidiary, TCEH. 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. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently, there are no reportable business segments.

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.

Liquidity Considerations

EFCH 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 EFCH's and its subsidiaries' business 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 debt activity in 2013 and the principal amounts and maturity dates of EFCH's and its consolidated subsidiaries' short-term borrowings and long-term debt, which includes the maturity of $3.8 billion of the TCEH Term Loan Facilities in October 2014. At September 30, 2013, TCEH has $1.3 billion of cash and cash equivalents and $171 million of available capacity under its letter of credit facility. Based on forward wholesale power prices in ERCOT, which are subject to the effects of changing market conditions, TCEH may not have sufficient liquidity, absent any financing transactions, to meet its obligations within the next twelve months.

EFH Corp. Discussions with Creditors

EFH Corp. and its subsidiaries, other than Oncor Holdings and its subsidiaries (the Oncor Ring-Fenced Entities) continue to consider and evaluate possible transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and have entered 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 exchanges or conversions of debt for preferred or common equity or warrants, including exchanges or conversions of debt of EFH Corp., EFIH, EFCH and TCEH into preferred or common equity or warrants 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.

4

In March and April 2013, EFH Corp. engaged in discussions with certain unaffiliated holders of first lien senior secured claims against EFCH, TCEH and certain of TCEH's subsidiaries (the TCEH Creditors) with respect to proposed changes to its capital structure. No agreement was reached as part of those discussions, and in September and October 2013, EFH Corp. engaged in further discussions with the TCEH Creditors, certain unaffiliated holders of unsecured claims against EFIH and a significant creditor with claims against TCEH, EFCH, EFIH and EFH Corp. (collectively, the Creditors) with respect to its capital structure, including the possibility of a consensual, prepackaged restructuring transaction. EFH Corp.'s objectives in these discussions were to promote a sustainable capital structure and maximize enterprise value of EFH Corp. and its subsidiaries by, among other things, encouraging agreement on a restructuring plan that would minimize time spent in a restructuring through a proactive and organized solution; minimizing any potential adverse tax impacts of a restructuring; maintaining EFH Corp. in one consolidated group; maintaining focus on operating its businesses, and maintaining EFH Corp.'s high-performing work force.

EFH Corp. and the Creditors discussed a number of proposed changes to EFH Corp.'s capital structure. Certain proposals contemplated that some combination of EFH Corp. and certain of its subsidiaries (including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities) would implement a plan of reorganization by commencing one or more voluntary cases under Chapter 11 of the United States Bankruptcy Code (the Code). Such proposals would have resulted in a prenegotiated restructuring of EFCH’s approximately $32.2 billion principal amount of debt, EFH Corp.’s approximately $650 million principal amount of debt and EFIH’s approximately $7.6 billion principal amount of debt (each as of September 30, 2013 and excluding debt held by affiliates) and contemplated that after the restructuring 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. Another proposal contemplated that EFIH (excluding Oncor Holdings and its subsidiaries) would implement a plan of reorganization by commencing a stand-alone voluntary case under the Code. Such proposal contemplated that after the restructuring certain creditors of EFIH would own a substantial majority of, and certain creditors of EFH Corp. and the equity holders of EFH Corp. would collectively own a minority of, the equity interests in EFIH. The confirmation of any plans of reorganization in such cases would be subject to applicable regulatory approvals. EFH Corp. and the Creditors have not reached agreement on the terms of any change in our capital structure.

EFH Corp. is not currently engaged in ongoing negotiations with the principals of any of the Creditors. Although the Creditors are not currently engaged in ongoing negotiations with EFH Corp., certain of the Creditors have directed their advisors to continue to work with EFH Corp. and its advisors to explore further whether the parties can reach an agreement on the terms of a consensual restructuring. EFH Corp. will continue to consider and evaluate a range of future changes to its capital structure, in addition to the proposed changes described above, which may include filing a voluntary case under Chapter 11 of the 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. 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.

5

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. There are no material investments accounted for under the equity or cost method.

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.

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:	September 30, 2013		December 31, 2012		Liabilities:	September 30, 2013		December 31, 2012
Cash and cash equivalents	$	37	$	43	Short-term borrowings	$	172	$	82
Accounts receivable	573		445		Trade accounts payable	1		1
Property, plant and equipment	138		134		Other current liabilities	13		7
Other assets, including $3 million and $12 million of current assets	12		16
Total assets	$	760	$	638	Total liabilities	$	186	$	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.

6

3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

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

Goodwill before impairment charges	$	18,322
Accumulated impairment charges	(13,370		)
Balance at September 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 that was recorded in the fourth quarter 2012. No additional impairment was recorded.

We have determined that in consideration of our most recent forecasts of wholesale power prices in ERCOT, the likelihood of a goodwill impairment has increased. We have initiated an evaluation of goodwill as of September 30, 2013, which will be completed in the fourth quarter 2013 and could result in a noncash goodwill impairment charge in that period.

Identifiable Intangible Assets

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

	September 30, 2013						December 31, 2012
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	396	$	67	$	463	$	378	$	85
Favorable purchase and sales contracts	551		333		218		552		314		238
Software and other computer-related assets	348		145		203		320		112		208
Environmental allowances and credits	598		407		191		594		393		201
Mining development costs	196		105		91		163		82		81
Total identifiable intangible assets subject to amortization	$	2,156	$	1,386	770		$	2,092	$	1,279	813
Retail trade name (not subject to amortization)					955						955
Mineral interests (not currently subject to amortization)					11						13
Total identifiable intangible assets					$	1,736					$	1,781

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

Identifiable Intangible Asset	Income Statement Line	Three Months Ended September 30,				Nine Months Ended September 30,
		2013		2012		2013		2012
Retail customer relationship	Depreciation and amortization	$	6	$	8	$	18	$	25
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	6		5		19		20
Software and other computer-related assets	Depreciation and amortization	14		9		33		24
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	5		6		11		15
Mining development costs	Depreciation and amortization	8		7		23		20
Total amortization expense		$	39	$	35	$	104	$	104

7

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

Year	Estimated Amortization Expense
2013	$	143
2014	$	138
2015	$	126
2016	$	101
2017	$	78

8

4. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

On October 29, 2013, we terminated the Accounts Receivable Securitization Program, described in the following paragraphs, and repaid all outstanding obligations under the program. In connection with the termination of the program, TXU Energy repurchased $491 million in accounts receivable from TXU Energy Receivables Company LLC (TXU Energy Receivables Company) for an aggregate purchase price of $474 million, TXU Energy Receivables Company paid TXU Energy $11 million, constituting repayment in full of its outstanding obligations under its subordinated note with TXU Energy, and TXU Energy Receivables Company repaid all of its borrowings from a financial institution providing the financing for the program totaling $126 million.

Under the Accounts Receivable Securitization Program, TXU Energy (originator) sold all of its trade accounts receivable to TXU Energy Receivables Company, which was 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 borrowed 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 available under the program at September 30, 2013 was $200 million, which approximated the expected usage and applied only to receivables related to non-executory retail sales contracts. Program funding increased to $172 million at September 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 was reduced by the amount of customer deposits held by the originator, which totaled $33 million at September 30, 2013.

TXU Energy Receivables Company issued 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 was limited to 25% of the uncollected accounts receivable purchased, and the amount of borrowings was limited by terms of the financing agreement, any additional funding to purchase the receivables was sourced from cash on hand, which totaled $37 million at September 30, 2013, and/or capital contributions from TCEH. Under the program, the subordinated note issued by TXU Energy Receivables Company was subordinated to the security interests of the financial institution. The balance of the subordinated note payable, which was eliminated in consolidation, totaled $93 million and $97 million at September 30, 2013 and December 31, 2012, respectively.

All new trade receivables under the program generated by the originator were 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 reflected 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 funded program fees paid to the financial institution. The program fees consisted primarily of interest costs on the underlying financing and are reported as interest expense and related charges. The discount also funded a servicing fee, which is reported as SG&A expense, paid by TXU Energy Receivables Company to TXU Energy, which provided recordkeeping services and was the collection agent under the program.

Program fee amounts were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Program fees	$	3		$	2		$	6		$	6
Program fees as a percentage of average funding (annualized)	5.1		%	4.9		%	5.8		%	6.2		%

9

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

	Nine Months Ended September 30,
	2013			2012
Cash collections on accounts receivable	$	3,200		$	3,501
Face amount of new receivables purchased (a)	(3,328		)	(3,571		)
Discount from face amount of purchased receivables	29			8
Program fees paid to financial institution	(6		)	(6		)
Servicing fees paid for recordkeeping and collection services	—			(2		)
Decrease in subordinated notes payable	(4		)	(10		)
Increase in cash held	17			—
Other — net	2			—
Cash flows provided to originator under the program	$	(90	)	$	(80	)

_______________

(a) Net of allowance for uncollectible accounts.

Trade Accounts Receivable

	September 30, 2013			December 31, 2012
Wholesale and retail trade accounts receivable	$	813		$	719
Allowance for uncollectible accounts	(17		)	(9		)
Trade accounts receivable — reported in balance sheet, including $573 and $445 in pledged retail receivables	$	796		$	710

Gross trade accounts receivable at September 30, 2013 and December 31, 2012 included unbilled revenues of $272 million and $260 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Nine Months Ended September 30,
	2013			2012
Allowance for uncollectible accounts receivable at beginning of period	$	9		$	27
Increase for bad debt expense	23			20
Decrease for account write-offs	(15		)	(32		)
Allowance for uncollectible accounts receivable at end of period	$	17		$	15

10

5. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At September 30, 2013, outstanding short-term borrowings totaled $2.226 billion, which included $2.054 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.68%, excluding customary fees, and $172 million under the accounts receivable securitization program. On October 29, 2013, we terminated the accounts receivable securitization program and repaid all outstanding obligations under the program (see 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 September 30, 2013 are presented below. Available letter of credit capacity totaled $171 million at September 30, 2013 as discussed below. The facilities are all senior secured facilities of TCEH.

		September 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 September 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 September 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 September 30, 2013, the restricted cash supports $776 million in letters of credit outstanding, leaving $171 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.

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Long-Term Debt

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

	September 30, 2013			December 31, 2012
TCEH
Senior Secured Facilities:
3.710% TCEH Term Loan Facilities maturing October 10, 2014 (a)(b)	$	3,809		$	3,809
3.679% TCEH Letter of Credit Facility maturing October 10, 2014 (b)	42			42
4.709% TCEH Term Loan Facilities maturing October 10, 2017 (a)(b)(c)	15,710			15,370
4.679% TCEH Letter of Credit Facility maturing October 10, 2017 (b)	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 (c)	2,046			2,046
10.25% Fixed Senior Notes due November 1, 2015, Series B (c)	1,442			1,442
10.50 / 11.25% Senior Toggle Notes due November 1, 2016	1,749			1,749
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 (d)	—			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
0.089% Floating Series 2001D-2 due May 1, 2033 (e)	97			97
0.210% Floating Taxable Series 2001I due December 1, 2036 (f)	62			62
0.089% Floating Series 2002A due May 1, 2037 (e)	45			45
6.75% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (d)	—			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 (d)	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 (g)	(107		)	(112		)
Other:
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017	36			—
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	56			64
Other	3			3
Unamortized discount	(110		)	(10		)
Unamortized fair value discount (g)	—			(1		)
Total TCEH	30,081			29,880

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	September 30, 2013			December 31, 2012
EFCH (parent entity)
9.58% Fixed Notes due in annual installments through December 4, 2019 (h)	$	35		$	35
8.254% Fixed Notes due in quarterly installments through December 31, 2021 (h)	35			39
1.065% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (b)	1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037	8			8
Unamortized fair value discount (g)	(6		)	(7		)
Subtotal	73			76
EFH Corp. debt pushed down (i)
10% Fixed Senior Notes due January 15, 2020	—			330
9.75% Fixed Senior Notes due October 15, 2019	—			58
10.875% Fixed Senior Notes due November 1, 2017	16			32
11.25 / 12.00% Senior Toggle Notes due November 1, 2017	14			30
Subtotal — EFH Corp. debt pushed down	30			450
Total EFCH (parent entity)	103			526
Total EFCH consolidated	30,184			30,406
Less amount due currently	(32		)	(96		)
Less amount held by affiliates (Note 11)	(382		)	(382		)
Total long-term debt	$	29,770		$	29,928

____________

(a) Interest rate swapped to fixed on $18.140 billion principal amount of maturities through October 2014 and up to an aggregate $12.6 billion principal amount from October 2014 through October 2017.

(b) Interest rates in effect at September 30, 2013.

(c) As discussed below and in Note 11, principal amounts of notes/term loans totaling $382 million at both September 30, 2013 and December 31, 2012 were held by EFH Corp. and EFIH.

(d) 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.

(e) Interest rates in effect at September 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.

(f) Interest rate in effect at September 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.

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

(h) 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.

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

Debt Amounts Due Currently

Amounts due currently (within twelve months) at September 30, 2013 total $32 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 nine months ended September 30, 2013 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.

Repayments of long-term debt in the nine months ended September 30, 2013 totaled $94 million and consisted of $86 million of payments of principal at scheduled maturity or mandatory tender and remarketing dates (including $60 million of pollution control revenue bond and $17 million of fixed secured facility bond payments) and $8 million of contractual payments under capital leases.

13

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 Guaranteed by EFCH (see discussion of debt guarantee below)—In exchanges in January 2013, EFIH and EFIH Finance issued $1.302 billion principal amount of EFIH 10% Senior Secured Notes due 2020 (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 senior secured notes.

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 to certain amendments to the respective indentures governing these notes. These amendments, among other things, made EFCH and EFIH unrestricted subsidiaries under the EFH Corp. 9.75% Notes and EFH Corp. 10% Notes, thereby eliminating EFCH's and EFIH's guarantees of the notes.

In additional exchanges in January 2013, EFIH and EFIH Finance issued $89 million principal amount of 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) and (iii) $31 million principal amount of other EFH Corp. unsecured debt.

EFIH received a total of $1.266 billion principal amount of EFH Corp. debt in these exchanges.

In the first quarter 2013, EFIH distributed $6.360 billion principal amount of EFH Corp. debt guaranteed by EFCH that EFIH previously received in debt exchanges, including $1.235 billion (of the $1.266 billion) received in January 2013, as a dividend to EFH Corp., which cancelled the notes. 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.

Guarantee and Push Down of EFH Corp. Debt

Merger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing at the time of the Merger. Debt issued in exchange for Merger-related debt is considered Merger-related. Debt issuances for cash are considered Merger-related debt to the extent the proceeds are used to repurchase Merger-related debt. EFCH and EFIH (excluding their subsidiaries) fully and unconditionally guarantee on a joint and several basis the Merger-related debt of EFH Corp. (parent). Such debt is subject to push down in accordance with SEC Staff Accounting Bulletin Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected in our financial statements. Merger-related debt of EFH Corp. held by its subsidiaries is not subject to push down.

As a result of transactions in the first quarter 2013 discussed above, debt guaranteed and subject to push down at September 30, 2013 totals $60 million and consists of $33 million principal amount of EFH Corp. 10.875% Senior Notes and $27 million principal amount of EFH Corp. 11.25%/12.00% Senior Toggle Notes. The amount reflected in our balance sheet as pushed down debt ($30 million and $450 million at September 30, 2013 and December 31, 2012, respectively, as shown in the long-term debt table above) represents 50% of the principal amount of the EFH Corp. Merger-related debt guaranteed. This percentage reflects the fact that at the time of the Merger, the equity investments of EFCH and EFIH in their respective operating subsidiaries were essentially equal amounts. Because payment of principal and interest on the debt is the responsibility of EFH Corp., we record the settlement of such amounts as noncash capital contributions from EFH Corp.

14

The following table presents an analysis of the total outstanding principal amount of EFH Corp. debt guaranteed by EFCH and EFIH at December 31, 2012 and September 30, 2013, respectively.

	December 31, 2012
Securities Guaranteed (principal amounts)	Held by EFIH		Subject to Push Down		Not Merger-Related		Total Guaranteed		Debt Cancelled in 2013		Total Guaranteed September 30, 2013 (c)
EFH Corp. 9.75% Senior Notes (a)	$	—	$	115	$	—	$	115	113		$	—
EFH Corp. 10% Senior Notes (a)	—		661		400		1,061		1,058		—
EFH Corp. 10.875% Senior Notes	1,685		64		—		1,749		1,715		33
EFH Corp. 11.25/12.00% Senior Toggle Notes	3,441		60		—		3,501		3,474		27
Subtotal	$	5,126	$	900	$	400	6,426		$	6,360	60
TCEH Demand Notes (b)							698				—
Total							$	7,124			$	60

____________

(a) As a result of transactions completed in the first quarter 2013, as discussed above, the guarantees of the EFH Corp. 9.75% Notes and EFH Corp. 10% Notes were eliminated.

(b) The TCEH Demand Notes were settled in January 2013. See Note 11.

(c) These amounts are subject to push down.

Information Regarding Other Significant Outstanding Debt

TCEH Senior Secured Facilities —Borrowings under the TCEH Senior Secured Facilities totaled $22.635 billion at September 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%;

• $15.710 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 September 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.

15

TCEH 11.5% Senior Secured Notes —At September 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 September 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 September 30, 2013, the principal amount of the TCEH Senior Notes totaled $5.237 billion, including $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.

Fair Value of Long-Term Debt

At September 30, 2013 and December 31, 2012, the estimated fair value of our long-term debt (excluding capital leases) totaled $15.873 billion and $17.858 billion, respectively, and the carrying amount totaled $30.128 billion and $30.342 billion, respectively. At September 30, 2013 and December 31, 2012, the estimated fair value of our short-term borrowings under the TCEH Revolving Credit Facilities totaled $1.371 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 September 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.

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TCEHInterest Rate Swap Transactions

TCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at September 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%	October 2013 through October 2014		$	18.140	billion (a)
6.8	%	-	9.0%	October 2015 through October 2017		$	12.600	billion (b)

___________

(a) Swaps related to an aggregate $1.6 billion principal amount of debt expired in 2013. Per the terms of the transactions, the notional amount of swaps entered into in 2011 grew by $1.280 billion 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 September 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 and the TCEH Senior Secured Notes.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Realized net loss	$	(160	)	$	(168	)	$	(466	)	$	(505	)
Unrealized net gain (loss)	413			(20		)	899			(16		)
Total	$	253		$	(188	)	$	433		$	(521	)

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.167 billion and $2.065 billion at September 30, 2013 and December 31, 2012, respectively, of which $57 million and $65 million (both pretax), respectively, were reported in accumulated other comprehensive income. See Note 8.

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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.

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

Letters of Credit

At September 30, 2013, TCEH had outstanding letters of credit under its credit facilities totaling $776 million as follows:

• $353 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

• $150 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. EFCH and the directors have filed a motion to dismiss this lawsuit, which has been fully briefed and is pending before the district court. 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.

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. The Big Brown case is currently scheduled for trial in February 2014. The Martin Lake case does not have a trial date. 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.

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Litigation Related to EPA 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 (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. In September 2013, the Fifth Circuit Court consolidated the petitions for review of the July 2012 and July 2013 notices of violation and established a briefing schedule for the consolidated cases.

In August 2013, the United States Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant Generation Company LLC and Big Brown Power Company LLC in federal district court in Dallas, alleging violations of the CAA at our Big Brown and Martin Lake generation facilities. In September 2013, we filed a motion to stay this lawsuit pending the outcome of the Fifth Circuit Court's review of the July 2012 and July 2013 notices of violation. We believe that we have complied with all requirements of the CAA and intend to vigorously defend these allegations. 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.

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 is scheduled to hear oral arguments in the case in December 2013. We cannot predict the outcome of the review by the US Supreme Court.

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State Implementation Plan (SIP)

In September 2010, the EPA disapproved a portion of the SIP 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 (PCP). 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 expedited reconsideration. In September 2013, the State of Texas filed a motion with the Fifth Circuit Court requesting that the Court amend and enforce its judgment in this case by requiring the EPA to satisfy the Court's judgment by taking action on the pending SIP revision regarding Texas' PCP standard permit no later than December 31, 2013. 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 of Texas' affirmative defense for planned maintenance, startup and shutdown 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 to uphold EPA's disapproval of Texas' affirmative defense for planned maintenance, startup and shutdown. In October 2013, the US Supreme Court denied our petition for review of that portion of the Fifth Circuit Court's decision. The decision is not anticipated to have a material effect on our results of operations, liquidity or financial condition.

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.

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7. MEMBERSHIP INTERESTS/EQUITY

Dividend Restrictions

While EFCH has no contractual dividend restrictions, the TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash distribution on their ownership interests 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 September 30, 2013, the ratio was 10.6 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.

In addition, under applicable law, we are prohibited from paying any distribution to the extent that immediately following payment of such distribution, 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 nine months ended September 30, 2013 and 2012.

Membership Interests/Equity

In April 2013, EFCH was converted from a Texas corporation to a Delaware limited liability company. The following tables present the changes to membership interests/equity for the nine months ended September 30, 2013 and 2012.

Nine Months Ended September 30, 2013
	EFCH Shareholder's Equity/Membership Interests
	Common Stock			Retained Earnings (Deficit)			Membership Interests			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total Equity
Balance at December 31, 2012	$	7,665		$	(18,129	)	$	—		$	(42	)	$	112		$	(10,394	)
Net loss	—			(526		)	(160		)	—			—			(686		)
Net effect of cash flow hedges	—			—			—			5			—			5
Investment by noncontrolling interests	—			—			—			—			3			3
Effect of debt push-down from EFH Corp. (a)	434			—			3			—			—			437
Dissolution of TXU Receivables Company	—			—			—			—			(10		)	(10		)
Capital structure conversion	(8,099		)	18,655			(10,556		)	—			—			—
Other				—			2			—			—			2
Balance at September 30, 2013	$	—		$	—		$	(10,711	)	$	(37	)	$	105		$	(10,643	)

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Nine Months Ended September 30, 2012
	EFCH Shareholder's Equity
	Common Stock			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total Equity
Balance at December 31, 2011	$	7,351		$	(15,121	)	$	(49	)	$	103	$	(7,716	)
Net loss	—			(1,298		)	—			—		(1,298		)
Gain on settlement of reimbursement agreement with Oncor (Note 11)	2			—			—			—		2
Effect of stock-based incentive compensation plans	6			—			—			—		6
Net effect of cash flow hedges	—			—			5			—		5
Investment by noncontrolling interests	—			—			—			6		6
Effect of debt push-down from EFH Corp. (a)	30			—			—			—		30
Other	(1		)	—			—			1		—
Balance at September 30, 2012	$	7,388		$	(16,419	)	$	(44	)	$	110	$	(8,965	)

 _______________

(a) Represents the interest and income tax effects of debt pushed down from EFH Corp. (Note 5).

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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, some of our derivatives are NYMEX or ICE 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 an EFH Corp. centralized risk management group that reports to the EFH Corp. 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, default rate factors and bond trading values in calculating these fair value measurement adjustments.

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Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including, but not limited to, commodity prices, volatility factors, discount rates and other market based factors. 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 consisted of the following:

September 30, 2013
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	140	$	941	$	48	$	2	$	1,131
Interest rate swaps	—		1		—		—		1
Nuclear decommissioning trust – equity securities (c)	299		172		—		—		471
Nuclear decommissioning trust – debt securities (c)	—		266		—		—		266
Total assets	$	439	$	1,380	$	48	$	2	$	1,869
Liabilities:
Commodity contracts	$	129	$	26	$	52	$	2	$	209
Interest rate swaps	—		—		1,167		—		1,167
Total liabilities	$	129	$	26	$	1,219	$	2	$	1,376

December 31, 2012
	Level 1		Level 2		Level 3 (a)		Total
Assets:
Commodity contracts	$	180	$	1,784	$	83	$	2,047
Interest rate swaps	—		2		—		2
Nuclear decommissioning trust – equity securities (c)	249		144		—		393
Nuclear decommissioning trust – debt securities (c)	—		261		—		261
Total assets	$	429	$	2,191	$	83	$	2,703
Liabilities:
Commodity contracts	$	208	$	121	$	54	$	383
Interest rate swaps	—		2,067		—		2,067
Total liabilities	$	208	$	2,188	$	54	$	2,450

_______________

(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 investments line in the balance sheet. See Note 12.

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.

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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 nine months ended September 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 and the significant unobservable inputs used in the valuations at September 30, 2013 and December 31, 2012:

September 30, 2013
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	5	$	(2	)	$	3		Valuation Model	Illiquid pricing locations (c)	$30 to $45/MWh
										Hourly price curve shape (d)	$20 to $70/MWh
Electricity spread options	—		(19		)	(19		)	Option Pricing Model	Gas to power correlation (e)	45% to 100%
										Power volatility (f)	10% to 30%
Electricity congestion revenue rights	37		(5		)	32			Market Approach (g)	Illiquid price differences between settlement points (h)	$0.00 to $30.00
Coal purchases	1		(12		)	(11		)	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%
Interest rate swaps	—		(1,167		)	(1,167		)	Valuation Model	Nonperformance risk adjustment (l)	30% to 35%
Other	5		(14		)	(9		)
Total	$	48	$	(1,219	)	$	(1,171	)

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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. Interest rate swaps are held by TCEH to hedge exposure to its variable rate debt.

(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 and the ERCOT West Hub.

(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.

(l) Estimate of nonperformance risk adjustment based on TCEH senior secured bond trading values. See discussion immediately below regarding transfers into Level 3.

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The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and nine months ended September 30, 2013 and 2012. Transfers into Level 3 during 2013 as noted below reflect a nonperformance risk adjustment in the valuation of the TCEH interest rate swaps, which are secured by a first-lien interest in the same assets of TCEH (on a pari passu basis) with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes (see Note 5). At September 30, 2013, the estimated fair value of these interest rate swaps totaled $1.518 billion before consideration of nonperformance risk adjustment and $1.167 billion after consideration of such adjustment. The amount of the nonperformance risk adjustment was after consideration of derivative assets related to contracts with the same counterparties that are also secured by a first-lien interest in the assets of TCEH, and a master netting agreement is in place that provides for netting and setoff of amounts related to these contracts.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net asset balance at beginning of period	$	88		$	12		$	29		$	53
Total unrealized valuation gains (losses)	(24		)	12			(41		)	(5		)
Purchases, issuances and settlements (a):
Purchases	6			17			66			30
Issuances	—			(4		)	(6		)	(15		)
Settlements	(62		)	(56		)	(45		)	(34		)
Transfers into Level 3 (b)	(1,179		)	3			(1,178		)	(42		)
Transfers out of Level 3 (b)	—			—			4			(3		)
Net change (c)	(1,259		)	(28		)	(1,200		)	(69		)
Net liability balance at end of period	$	(1,171	)	$	(16	)	$	(1,171	)	$	(16	)
Unrealized valuation gains (losses) relating to instruments held at end of period	$	254		$	15		$	280		$	(22	)

____________

(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. 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. Changes in values of interest rate swaps are reported in the income statement in interest expense and related charges. 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 September 30, 2013 and December 31, 2012:

September 30, 2013
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	972		$	1	$	—		$	—		$	973
Noncurrent assets	159			—		—			—			159
Current liabilities	(2		)	—		(204		)	(388		)	(594		)
Noncurrent liabilities	—			—		(3		)	(779		)	(782		)
Net assets (liabilities)	$	1,129		$	1	$	(207	)	$	(1,167	)	$	(244	)

December 31, 2012
	Derivative assets				Derivative liabilities
	Commodity contracts		Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	1,461	$	2	$	—		$	—		$	1,463
Noncurrent assets	586		—		—			—			586
Current liabilities	—		—		(366		)	(528		)	(894		)
Noncurrent liabilities	—		—		(17		)	(1,539		)	(1,556		)
Net assets (liabilities)	$	2,047	$	2	$	(383	)	$	(2,067	)	$	(401	)

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At September 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 September 30,					Nine Months Ended September 30,
Derivative (income statement presentation)	2013		2012			2013		2012
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a)	$	98	$	(95	)	$	54	$	130
Interest rate swaps (Interest expense and related charges) (b)	253		(188		)	433		(521		)
Net gain (loss)	$	351	$	(283	)	$	487	$	(391	)

_______________

(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 12).

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 nine months ended September 30, 2013 and 2012.

	Three Months Ended September 30,						Nine Months Ended September 30,
Derivative (income statement presentation)	2013			2012			2013			2012
Interest rate swaps (Interest expense and related charges)	$	(1	)	$	(1	)	$	(6	)	$	(6	)
Interest rate swaps (Depreciation and amortization)	(1		)	(1		)	(2		)	(2		)
Total	$	(2	)	$	(2	)	$	(8	)	$	(8	)

Accumulated other comprehensive income related to cash flow hedges at September 30, 2013 and December 31, 2012 totaled $37 million and $42 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 $2 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at September 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 September 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.

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.

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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:

September 30, 2013
	Amounts Presented in Balance Sheet			Offsetting Financial Instruments (a)			Financial Collateral (Received) Pledged (b)			Net Amounts (c)
Derivative assets:
Commodity contracts	$	1,131		$	(613	)	$	(351	)	$	167
Interest rate swaps	1			(1		)	—			—
Total derivative assets	1,132			(614		)	(351		)	167
Derivative liabilities:
Commodity contracts	(209		)	180			11			(18		)
Interest rate swaps	(1,167		)	434			—			(733		)
Total derivative liabilities	(1,376		)	614			11			(751		)
Net amounts	$	(244	)	$	—		$	(340	)	$	(584	)

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	2			(2		)	—			—
Total derivative assets	2,049			(1,265		)	(597		)	187
Derivative liabilities:
Commodity contracts	(383		)	319			29			(35		)
Interest rate swaps	(2,067		)	946			—			(1,121		)
Total derivative liabilities	(2,450		)	1,265			29			(1,156		)
Net amounts	$	(401	)	$	—		$	(568	)	$	(969	)

____________

(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 $1.2 billion (before nonperformance risk adjustment) related to counterparties with positions that are secured by a first-lien interest in the same 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 September 30, 2013 and December 31, 2012:

	September 30, 2013		December 31, 2012
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed (a)	$	30,740	$	31,060	Million US dollars
Basis	$	11,967	$	11,967	Million US dollars
Natural gas:
Natural gas forward sales and purchases (b)	452		875		Million MMBtu
Locational basis swaps	337		495		Million MMBtu
All other	2,021		1,549		Million MMBtu
Electricity	21,663		76,767		GWh
Congestion Revenue Rights (c)	82,156		111,185		GWh
Coal	11		14		Million US tons
Fuel oil	28		47		Million gallons
Uranium	575		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 210 million MMBtu and 360 million MMBtu at September 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 September 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 $40 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 $9 million and $12 million at September 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 September 30, 2013 and December 31, 2012, the remaining liquidity requirements would have totaled $8 million and none, respectively.

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 September 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 $1.192 billion and $2.150 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 September 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 September 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 $1.087 billion and $1.122 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 $1.232 billion and $2.208 billion at September 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

TCEH has concentrations of credit risk with the counterparties to its derivative contracts. At September 30, 2013, total credit risk exposure to all counterparties related to derivative contracts totaled $1.258 billion (including associated accounts receivable). The net exposure to those counterparties totaled $275 million at September 30, 2013 after taking into effect netting arrangements, setoff provisions and collateral. At September 30, 2013, the credit risk exposure to the banking and financial sector represented 88% of the total credit risk exposure and 59% 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 $50 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

Our subsidiaries are participating employers in the EFH Retirement Plan, a defined benefit pension plan sponsored by EFH Corp. that is described further below. Our subsidiaries also participate with EFH Corp. and certain other subsidiaries of EFH Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. The net allocated pension and OPEB costs applicable to us totaled $3 million and $10 million for the three months ended September 30, 2013 and 2012, respectively, and $9 million and $31 million for the nine months ended September 30, 2013 and 2012, respectively.

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.

In the first nine months of 2013 we made a $50 million payment to EFH Corp. to settle TCEH's allocation of 2012 pension-related charges resulting from the amendments. We expect to make additional contributions in 2013 of $2 million for the pension and OPEB plans.

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11. RELATED-PARTY TRANSACTIONS

The following represent our significant related-party transactions.

• 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 $273 million and $281 million for the three months ended September 30, 2013 and 2012, respectively, and $728 million and $746 million for the nine months ended September 30, 2013 and 2012, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at September 30, 2013 and December 31, 2012 reflect amounts due currently to Oncor totaling $158 million and $53 million, respectively, (included in trade accounts and other payables to affiliates) largely related to these electricity delivery fees.

• 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. Under the settlement, TCEH paid, and Oncor received, $159 million in cash.

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 zero and $20 million for the three and nine months ended September 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 $2 million and $16 million for the three and nine months ended September 30, 2012, respectively.

• Notes receivable from EFH Corp. were payable to TCEH on demand (TCEH Demand Notes) and arose from cash loaned for debt principal and interest payments and other general corporate purposes of EFH Corp. At September 30, 2013 and December 31, 2012, the notes consisted of:

	September 30, 2013		December 31, 2012
Note related to debt principal and interest payments (P&I Note)	$	—	$	465
Note related to general corporate purposes (SG&A Note)	—		233
Total	$	—	$	698

The TCEH Demand Notes were guaranteed by EFIH and EFCH on a senior unsecured basis. The TCEH Demand Notes were pledged as collateral under the TCEH Senior Secured Facilities. In January 2013, EFIH used $680 million of the proceeds from its August 2012 debt issuance to pay a dividend to EFH Corp., which EFH Corp. used with cash on hand to repay the entire balance of the TCEH Demand Notes. The average daily balance of the TCEH Demand Notes totaled $683 million for the three months ended September 30, 2012 and $77 million and $822 million for the nine months ended September 30, 2013 and 2012, respectively. The TCEH Demand Notes carried interest at a rate based on the one-month LIBOR rate plus 5.00%, and interest income related to the TCEH Demand Notes totaled $9 million for the three months ended September 30, 2012 and $3 million and $33 million for the nine months ended September 30, 2013 and 2012, respectively.

• EFCH has a demand note payable to EFH Corp., the proceeds from which were used to repay outstanding debt. The note totaled $92 million and $81 million at September 30, 2013 and December 31, 2012, respectively, and carried interest at a rate based on the one-month LIBOR rate plus 5.00%. Interest expense related to this note totaled $1 million for both the three months ended September 30, 2013 and 2012 and $3 million for both the nine months ended September 30, 2013 and 2012.

• Receivables from affiliates are measured at historical cost and primarily consisted of notes receivable for cash loaned to EFH Corp. for debt principal and interest payments and other general corporate purposes of EFH Corp. as discussed above. TCEH reviews economic conditions, counterparty credit scores and historical payment activity to assess the overall collectability of its affiliated receivables. There were no credit loss allowances at September 30, 2013 and December 31, 2012.

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• A subsidiary of EFH Corp. bills our subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges, which are settled in cash and primarily reported in SG&A expenses, totaled $59 million and $61 million for the three months ended September 30, 2013 and 2012, respectively, and $176 million and $178 million for the nine months ended September 30, 2013 and 2012, respectively. Beginning in the fourth quarter 2012, TCEH reimburses a subsidiary of EFH Corp. for an allocated share of computer equipment purchased by the subsidiary. Amounts paid by TCEH in the nine months ended September 30, 2013 related to new computer equipment totaled $6 million and were accounted for as an intangible asset to be amortized over the life of the equipment. Previously, the depreciation of such equipment was included in the administrative cost billings.

• 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 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 $5 million for both the three months ended September 30, 2013 and 2012 and $12 million for both the nine months ended September 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 September 30, 2013 and December 31, 2012, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $352 million and $284 million, respectively, reported in other noncurrent liabilities.

• EFH Corp. files consolidated federal income tax and Texas state margin tax returns that include our results; however, under a tax sharing agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if we file our own corporate income tax return. As of September 30, 2013, we had current income tax receivables of $7 million and noncurrent income tax liabilities of $723 million payable to EFH Corp. As of December 31, 2012, we had current income tax liabilities of $31 million payable to EFH Corp. (see Note 12). We made tax payments to EFH Corp. of $134 million and $83 million for the nine months ended September 30, 2013 and 2012, respectively. The 2013 payment included $84 million related to the 1997 through 2002 IRS appeals settlement.

• Certain transmission and distribution utilities in Texas have requirements in place to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, 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 September 30, 2013 and December 31, 2012, TCEH had posted letters of credit in the amount of $10 million and $11 million, respectively, for the benefit of Oncor.

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

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

• 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.

35

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

	September 30, 2013		December 31, 2012
TCEH Senior Notes:
Held by EFH Corp.	$	284	$	284
Held by EFIH	79		79
TCEH Term Loan Facilities:
Held by EFH Corp.	19		19
Total	$	382	$	382

Interest expense on the notes totaled $10 million for both the three months ended September 30, 2013 and 2012 and $29 million for both the nine months ended September, 30, 2013 and 2012.

See Notes 5 and 6 for guarantees and push-down of certain EFH Corp. debt and Note 10 for allocation of EFH Corp. pension and OPEB costs to us.

36

12. SUPPLEMENTARY FINANCIAL INFORMATION

Other Income

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Other income:
Consent fee related to novation of hedge positions between counterparties	$	—	$	—	$	—	$	6
Insurance/litigation settlements	—		—		2		2
All other	1		2		5		4
Total other income	$	1	$	2	$	7	$	12
Other deductions:
Impairment of mineral interests	$	—	$	24	$	—	$	24
Other asset impairments	3		—		3		—
Counterparty contract settlement	—		4		—		4
Other	5		2		9		9
Total other deductions	$	8	$	30	$	12	$	37

Interest Expense and Related Charges

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	688		$	647		$	2,042		$	1,938
Interest related to pushed down debt	1			19			5			57
Interest payable with additional toggle notes (Note 5)	—			47			—			136
Unrealized mark-to-market net (gain) loss on interest rate swaps	(413		)	20			(899		)	16
Amortization of interest rate swap losses at dedesignation of hedge accounting	2			2			6			7
Amortization of fair value debt discounts resulting from purchase accounting	3			3			8			8
Amortization of debt issuance, amendment and extension costs and discounts	64			45			195			137
Capitalized interest	(5		)	(11		)	(19		)	(31		)
Total interest expense and related charges	$	340		$	772		$	1,338		$	2,268

Restricted Cash

At September 30, 2013 and December 31, 2012, all restricted cash on the balance sheet related to TCEH's Letter of Credit Facility (see Note 5).

Inventories by Major Category

	September 30, 2013		December 31, 2012
Materials and supplies	$	216	$	201
Fuel stock	155		168
Natural gas in storage	29		24
Total inventories	$	400	$	393

37

Investments

	September 30, 2013		December 31, 2012
Nuclear plant decommissioning trust	$	737	$	654
Assets related to employee benefit plans, including employee savings programs, net of distributions	1		8
Land	40		41
Miscellaneous other	9		7
Total investments	$	787	$	710

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:

	September 30, 2013
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	261	$	9	$	(4	)	$	266
Equity securities (c)	252		227		(8		)	471
Total	$	513	$	236	$	(12	)	$	737

	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 Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.97% and 4.38% at September 30, 2013 and December 31, 2012, respectively, and an average maturity of 6 years at both September 30, 2013 and December 31, 2012.

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

Debt securities held at September 30, 2013 mature as follows: $103 million in one to five years, $58 million in five to ten years and $105 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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Realized gains	$	1		$	—		$	2		$	1
Realized losses	$	(3	)	$	(1	)	$	(3	)	$	(2	)
Proceeds from sales of securities	$	23		$	25		$	128		$	56
Investments in securities	$	(28	)	$	(30	)	$	(140	)	$	(68	)

Property, Plant and Equipment

At September 30, 2013 and December 31, 2012, property, plant and equipment of $18.0 billion and $18.6 billion, respectively, is stated net of accumulated depreciation and amortization of $7.7 billion and $6.8 billion, respectively.

38

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 nine months ended September 30, 2013:

	Nuclear Plant Decommissioning		Mining Land Reclamation			Other			Total
Liability at December 31, 2012	$	368	$	135		$	33		$	536
Additions:
Accretion	17		23			1			41
Reductions:
Payments	—		(72		)	(1		)	(73		)
Liability at September 30, 2013	385		86			33			504
Less amounts due currently	—		(60		)	—			(60		)
Noncurrent liability at September 30, 2013	$	385	$	26		$	33		$	444

Other Noncurrent Liabilities and Deferred Credits

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

	September 30, 2013		December 31, 2012
Uncertain tax positions (including accrued interest)	$	384	$	1,250
Asset retirement and mining reclamation obligations	444		452
Unfavorable purchase and sales contracts	596		620
Nuclear decommissioning cost over-recovery (Note 11)	352		284
Other, including retirement and other employee benefits	17		37
Total other noncurrent liabilities and deferred credits	$	1,793	$	2,643

Liability for Uncertain Tax Positions — In May 2013, EFH Corp. received approval from the Joint Committee on Taxation of the IRS appeals settlement of all issues arising from the 1997 through 2002 IRS audit. The settlement 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 settlement, resulting in a $411 million reclassification to the accumulated deferred income tax liability and the recording of a $20 million income tax expense. Other effects included the recording of current federal income tax and state income tax liabilities to EFH Corp. of $78 million and $14 million, respectively, and a reduction of $392 million of the noncurrent federal income tax liability to EFH Corp., all under the tax sharing agreement (see Note 11). In the third quarter 2013, we recorded an additional $38 million tax benefit, with an offset to accumulated deferred income tax liability, related to the settlement.

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 net reduction of the liability for uncertain tax positions totaling $794 million. This reduction consisted of a $685 million reclassification to a noncurrent affiliate tax sharing liability and a net adjustment of $109 million ($62 million after tax), largely representing a reversal of accrued interest and reported as an increase in income tax benefit. In addition, in accordance with the provisions of the tax sharing agreement with EFH Corp., amounts previously recorded as accumulated deferred income taxes totaling $430 million were reclassified to the affiliate tax sharing liability, the total amount of which is not expected to be settled within the next twelve months.

39

Unfavorable Purchase and Sales Contracts – The amortization of unfavorable purchase and sales contracts totaled $6 million for both the three months ended September 30, 2013 and 2012 and $19 million and $20 million for the nine months ended September 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

	Nine Months Ended September 30,
	2013			2012
Cash payments (receipts) related to:
Interest paid (a)	$	1,901		$	1,788
Capitalized interest	(19		)	(31		)
Interest paid (net of capitalized interest) (a)	$	1,882		$	1,757
Income taxes	$	134		$	83
Noncash investing and financing activities:
Effect of Parent's payment of interest, net of tax, on pushed down debt	$	21		$	30
Principal amount of TCEH Toggle Notes issued in lieu of cash interest	$	—		$	88
Construction expenditures (b)	$	62		$	52
Contribution related to EFH Corp. stock-based compensation	$	1		$	6
Debt assumed related to acquisition of combustion turbine trust interest	$	(45	)	$	—
Effect of push down of debt from parent	$	(420	)	$	—
Debt extension transactions	$	(340	)	$	—

____________

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

(b) Represents end-of-period accruals.

40

13. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

At September 30, 2013 TCEH and TCEH Finance, as Co-Issuers, had outstanding $5.237 billion aggregate principal amount of 10.25% Senior Notes Due 2015, 10.25% Senior Notes due 2015 Series B and Toggle Notes (collectively, the TCEH Senior Notes) and $1.571 billion aggregate principal amount of 15% Senior Secured Second Lien Notes due 2021 and 15% Senior Secured Second Lien Notes due 2021 (Series B) (collectively, the TCEH Senior Secured Second Lien Notes). The TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes are unconditionally guaranteed by EFCH and by each subsidiary (all 100% owned by TCEH) that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes. The guarantees of the TCEH Senior Notes rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. The guarantees of the TCEH Senior Secured Second Lien Notes rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, the TCEH Senior Secured Notes 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 (see Note 5). All other subsidiaries of EFCH, either direct or indirect, do not guarantee the TCEH Senior Notes or TCEH Senior Secured Second Lien Notes (collectively the Non-Guarantors). The indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes contain certain restrictions, subject to certain exceptions, on EFCH's ability to pay dividends or make investments. See Note 7.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, "Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered" in order to present the condensed consolidating statements of income for the three and nine months ended September 30, 2013 and 2012 and of cash flows for the nine months ended September 30, 2013 and 2012 of EFCH (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors and the condensed consolidating balance sheets at September 30, 2013 and December 31, 2012 of the Parent, Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5J, "Push Down Basis of Accounting Required in Certain Limited Circumstances," including the effects of the push down of $30 million and $62 million of the EFH Corp. 10.875% Notes and Toggle Notes to the Parent at September 30, 2013 and December 31, 2012, respectively, $388 million of the EFH Corp. 9.75% Notes and 10% Notes to the Parent at December 31, 2012, and the TCEH Senior Notes, TCEH Senior Secured Notes, TCEH Senior Secured Second Lien Notes and TCEH Senior Secured Facilities to the Other Guarantors at September 30, 2013 and December 31, 2012 (see Note 5 for further details of this debt, including the elimination of EFCH's guarantees of the EFH Corp. 9.75% Notes and 10% Notes in January 2013). TCEH Finance's sole function is to be the co-issuer of the certain TCEH debt securities; therefore, it has no other independent assets, liabilities or operations.

EFCH received no dividends/distributions from its consolidated subsidiaries for the three or nine months ended September 30, 2013 and 2012.

41

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

Three Months Ended September 30, 2013

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	1,893		$	27		$	(27	)	$	1,893
Fuel, purchased power costs and delivery fees	—			—			(852		)	—			—			(852		)
Net gain from commodity hedging and trading activities	—			20			38			—			—			58
Operating costs	—			—			(192		)	—			3			(189		)
Depreciation and amortization	—			—			(332		)	1			—			(331		)
Selling, general and administrative expenses	—			(14		)	(173		)	(11		)	23			(175		)
Franchise and revenue-based taxes	—			—			(18		)	—			—			(18		)
Other income	—			—			1			—			—			1
Other deductions	—			—			(8		)	—			—			(8		)
Interest income	—			62			206			—			(267		)	1
Interest expense and related charges	(4		)	(541		)	(619		)	(4		)	828			(340		)
Income (loss) before income taxes	(4		)	(473		)	(56		)	13			560			40
Income tax (expense) benefit	1			165			46			(5		)	(190		)	17
Equity earnings of subsidiaries	60			368			1			—			(429		)	—
Net income (loss)	57			60			(9		)	8			(59		)	57
Other comprehensive income	1			1			—			—			(1		)	1
Comprehensive income (loss)	$	58		$	61		$	(9	)	$	8		$	(60	)	$	58

42

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

Three Months Ended September 30, 2012

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	1,752		$	3		$	(3	)	$	1,752
Fuel, purchased power costs and delivery fees	—			—			(850		)	—			—			(850		)
Net gain (loss) from commodity hedging and trading activities	—			(98		)	95			—			—			(3		)
Operating costs	—			—			(201		)	—			—			(201		)
Depreciation and amortization	—			—			(328		)	—			—			(328		)
Selling, general and administrative expenses	—			(4		)	(172		)	(1		)	3			(174		)
Franchise and revenue-based taxes	—			—			(19		)	—			—			(19		)
Other income	—			—			2			—			—			2
Other deductions	—			—			(30		)	—			—			(30		)
Interest income	—			91			232			—			(313		)	10
Interest expense and related charges	(24		)	(982		)	(606		)	(2		)	842			(772		)
Loss before income taxes	(24		)	(993		)	(125		)	—			529			(613		)
Income tax benefit	8			347			54			—			(181		)	228
Equity earnings (losses) of subsidiaries	(369		)	277			—			—			92			—
Net loss	(385		)	(369		)	(71		)	—			440			(385		)
Other comprehensive income	1			1			—			—			(1		)	1
Comprehensive loss	$	(384	)	$	(368	)	$	(71	)	$	—		$	439		$	(384	)

43

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

Nine Months Ended September 30, 2013

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	4,572		$	59		$	(59	)	$	4,572
Fuel, purchased power costs and delivery fees	—			—			(2,175		)	—			—			(2,175		)
Net gain (loss) from commodity hedging and trading activities	—			(3		)	32			—			—			29
Operating costs	—			—			(690		)	—			5			(685		)
Depreciation and amortization	—			—			(1,011		)	(1		)	—			(1,012		)
Selling, general and administrative expenses	—			(49		)	(481		)	(25		)	53			(502		)
Franchise and revenue-based taxes	—			—			(51		)	—			—			(51		)
Other income	—			—			7			—			—			7
Other deductions	—			—			(12		)	—			—			(12		)
Interest income	1			182			591			—			(769		)	5
Interest expense and related charges	(15		)	(1,920		)	(1,842		)	(8		)	2,447			(1,338		)
Income (loss) before income taxes	(14		)	(1,790		)	(1,060		)	25			1,677			(1,162		)
Income tax (expense) benefit	7			630			420			(9		)	(572		)	476
Equity earnings (losses) of subsidiaries	(679		)	481			1			—			197			—
Net income (loss)	(686		)	(679		)	(639		)	16			1,302			(686		)
Other comprehensive income	5			5			—			—			(5		)	5
Comprehensive income (loss)	$	(681	)	$	(674	)	$	(639	)	$	16		$	1,297		$	(681	)

44

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

Nine Months Ended September 30, 2012

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	4,358		$	8		$	(8	)	$	4,358
Fuel, purchased power costs and delivery fees	—			—			(2,153		)	—			—			(2,153		)
Net gain from commodity hedging and trading activities	—			173			56			—			—			229
Operating costs	—			—			(636		)	—			—			(636		)
Depreciation and amortization	—			—			(992		)	—			—			(992		)
Selling, general and administrative expenses	—			(4		)	(486		)	(2		)	8			(484		)
Franchise and revenue-based taxes	—			—			(55		)	—			—			(55		)
Other income	—			6			6			—			—			12
Other deductions	—			—			(36		)	(1		)	—			(37		)
Interest income	—			242			593			—			(799		)	36
Interest expense and related charges	(69		)	(2,794		)	(1,778		)	(5		)	2,378			(2,268		)
Loss before income taxes	(69		)	(2,377		)	(1,123		)	—			1,579			(1,990		)
Income tax benefit	23			829			379			—			(539		)	692
Equity earnings (losses) of subsidiaries	(1,252		)	296			—			—			956			—
Net loss	(1,298		)	(1,252		)	(744		)	—			1,996			(1,298		)
Other comprehensive income	5			5			—			—			(5		)	5
Comprehensive loss	$	(1,293	)	$	(1,247	)	$	(744	)	$	—		$	1,991		$	(1,293	)

45

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Nine Months Ended September 30, 2013

(millions of dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(8	)	$	(1,764	)	$	1,736		$	(85	)	$	—		$	(121	)
Cash flows – financing activities:
Notes/advances due to affiliates	11			1,913			—			—			(1,920		)	4
Repayments/repurchases of long-term debt	(3		)	(64		)	(27		)	—			—			(94		)
Net short-term borrowings under accounts receivable securitization program	—			—			—			90			—			90
Contributions from noncontrolling interests	—			—			—			3			—			3
Other, net	—			—			—			(10		)	—			(10		)
Cash provided by (used in) financing activities	8			1,849			(27		)	83			(1,920		)	(7		)
Cash flows – investing activities:
Capital expenditures	—			—			(349		)	(4		)	—			(353		)
Nuclear fuel purchases	—			—			(59		)	—			—			(59		)
Notes due from affiliates	—			—			(1,222		)	—			1,920			698
Purchase of right to use certain computer-related assets from parent	—			—			(6		)	—			—			(6		)
Proceeds from sales of assets	—			—			3			—			—			3
Acquisition of combustion turbine trust interest	—			—			(40		)	—			—			(40		)
Purchases of environmental allowances and credits	—			—			(13		)	—			—			(13		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			—			128			—			—			128
Investments in nuclear decommissioning trust fund securities	—			—			(140		)	—			—			(140		)
Other, net	—			—			(3		)	—			—			(3		)
Cash provided by (used in) investing activities	—			—			(1,701		)	(4		)	1,920			215
Net change in cash and cash equivalents	—			85			8			(6		)	—			87
Cash and cash equivalents – beginning balance	—			1,115			15			45			—			1,175
Cash and cash equivalents – ending balance	$	—		$	1,200		$	23		$	39		$	—		$	1,262

46

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Nine Months Ended September 30, 2012

(millions of dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(7	)	$	(471	)	$	885		$	(78	)	$	—		$	329
Cash flows – financing activities:
Notes due to affiliates	11			1,029			—			—			(1,040		)	—
Repayments/repurchases of long-term debt	(4		)	—			(26		)	—			—			(30		)
Net short-term borrowings under accounts receivable securitization program	—			—			—			80			—			80
Decrease in other short-term borrowings	—			(385		)	—			—			—			(385		)
Decrease in income tax-related note payable to Oncor	—			—			(20		)	—			—			(20		)
Settlement of reimbursement agreements with Oncor	—			—			(159		)	—			—			(159		)
Contributions from noncontrolling interests	—			—			—			6			—			6
Sale/leaseback of equipment	—			—			15			—			—			15
Cash provided by (used in) financing activities	7			644			(190		)	86			(1,040		)	(493		)
Cash flows – investing activities:
Capital expenditures	—			—			(491		)	(7		)	—			(498		)
Nuclear fuel purchases	—			—			(155		)	—			—			(155		)
Notes/loans due from affiliates	—			—			(118		)	—			1,040			922
Proceeds from sales of assets	—			—			1			—			—			1
Changes in restricted cash	—			—			112			—			—			112
Purchases of environmental allowances and credits	—			—			(19		)	—			—			(19		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			—			56			—			—			56
Investments in nuclear decommissioning trust fund securities	—			—			(68		)	—			—			(68		)
Other, net	—			—			2			—			—			2
Cash provided by (used in) investing activities	—			—			(680		)	(7		)	1,040			353
Net change in cash and cash equivalents	—			173			15			1			—			189
Cash and cash equivalents – beginning balance	—			87			23			10			—			120
Cash and cash equivalents – ending balance	$	—		$	260		$	38		$	11		$	—		$	309

47

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES Condensed Consolidating Balance Sheets September 30, 2013 (millions of dollars)
	Parent Guarantor			Issuer		Other Guarantors		Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	1,200	$	23	$	39	$	—		$	1,262
Advances to affiliates	—			—		74		—		(74		)	—
Trade accounts receivable – net	—			1		315		574		(94		)	796
Income taxes receivable	7			—		84		—		(84		)	7
Accounts receivable from affiliates	—			13		—		5		(18		)	—
Inventories	—			—		400		—		—			400
Commodity and other derivative contractual assets	—			726		247		—		—			973
Accumulated deferred income taxes	3			—		—		3		(6		)	—
Margin deposits related to commodity positions	—			—		21		—		—			21
Other current assets	—			2		32		—		—			34
Total current assets	10			1,942		1,196		621		(276		)	3,493
Restricted cash	—			947		—		—		—			947
Investments	(10,467		)	23,885		867		9		(13,507		)	787
Property, plant and equipment – net	—			—		17,760		201		—			17,961
Advances to affiliates	—			—		9,972		—		(9,972		)	—
Goodwill	—			4,952		—		—		—			4,952
Identifiable intangible assets – net	—			—		1,736		5		(5		)	1,736
Commodity and other derivative contractual assets	—			147		12		—		—			159
Accumulated deferred income taxes	—			490		—		3		(493		)	—
Other noncurrent assets, principally unamortized amendment/issuance costs	—			834		849		7		(831		)	859
Total assets	$	(10,457	)	$	33,197	$	32,392	$	846	$	(25,084	)	$	30,894
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Short-term borrowings	$	—		$	2,054	$	2,054	$	172	$	(2,054	)	$	2,226
Notes/advances from affiliates	1			10,045		—		—		(10,046		)	—
Long-term debt due currently	11			—		10		11		—			32
Trade accounts payable	—			5		348		95		(94		)	354
Trade accounts and other payables to affiliates	—			—		223		—		(18		)	205
Notes payable to parent	92			—		—		—		—			92
Commodity and other derivative contractual liabilities	—			413		181		—		—			594

48

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES Condensed Consolidating Balance Sheets September 30, 2013 (millions of dollars)
	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors		Eliminations			Consolidated
Margin deposits related to commodity positions	$	—		$	335		$	18		$	—	$	—		$	353
Accumulated deferred income taxes	—			3			39			—		(6		)	36
Accrued income taxes payable to parent	—			70			—			14		(84		)	—
Accrued taxes other than income	—			—			95			—		—			95
Accrued interest	3			528			401			1		(401		)	532
Other current liabilities	—			—			219			—		—			219
Total current liabilities	107			13,453			3,588			293		(12,703		)	4,738
Accumulated deferred income taxes	84			—			2,782			—		481			3,347
Commodity and other derivative contractual liabilities	—			779			3			—		—			782
Notes or other liabilities due affiliates	—			—			2			—		—			2
Long-term debt held by affiliates	—			382			—			—		—			382
Long-term debt, less amounts due currently	92			29,604			28,704			22		(28,652		)	29,770
Affiliate tax sharing liability	—			(571		)	1,294			—		—			723
Other noncurrent liabilities and deferred credits	8			17			1,774			—		(6		)	1,793
Total liabilities	291			43,664			38,147			315		(40,880		)	41,537
EFCH membership interests	(10,748		)	(10,467		)	(5,755		)	426		15,796			(10,748		)
Noncontrolling interests in subsidiaries	—			—			—			105		—			105
Total membership interests	(10,748		)	(10,467		)	(5,755		)	531		15,796			(10,643		)
Total liabilities and membership interests	$	(10,457	)	$	33,197		$	32,392		$	846	$	(25,084	)	$	30,894

49

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES Condensed Consolidating Balance Sheets December 31, 2012 (millions of dollars)
	Parent Guarantor			Issuer		Other Guarantors		Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	1,115	$	15	$	45	$	—		$	1,175
Advances to affiliates	—			—		36		—		(36		)	—
Trade accounts receivable – net	—			2		360		445		(97		)	710
Notes receivable from parent	—			698		—		—		—			698
Income taxes receivable	—			—		410		—		(410		)	—
Accounts receivable from affiliates	—			95		—		—		(95		)	—
Inventories	—			—		393		—		—			393
Commodity and other derivative contractual assets	—			1,127		336		—		—			1,463
Accumulated deferred income taxes	3			—		—		3		(6		)	—
Margin deposits related to commodity positions	—			—		71		—		—			71
Other current assets	—			—		112		8		—			120
Total current assets	3			3,037		1,733		501		(644		)	4,630
Restricted cash	—			947		—		—		—			947
Investments	(9,794		)	23,382		747		9		(13,634		)	710
Property, plant and equipment – net	—			—		18,422		134		—			18,556
Advances to affiliates	—			—		8,794		—		(8,794		)	—
Goodwill	—			4,952		—		—		—			4,952
Identifiable intangible assets – net	—			—		1,781		—		—			1,781
Commodity and other derivative contractual assets	—			575		11		—		—			586
Accumulated deferred income taxes	—			828		—		3		(831		)	—
Other noncurrent assets, principally unamortized amendment/issuance costs	4			781		806		3		(783		)	811
Total assets	$	(9,787	)	$	34,502	$	32,294	$	650	$	(24,686	)	$	32,973
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	2,054	$	2,054	$	82	$	(2,054	)	$	2,136
Notes/advances from affiliates	—			8,830		—		—		(8,830		)	—
Long-term debt due currently	11			64		21		—		—			96
Trade accounts payable	—			2		387		97		(97		)	389
Trade accounts and other payables to affiliates	—			—		231		3		(95		)	139
Notes payable to parent/affiliate	80			—		1		—		—			81
Commodity and other derivative contractual liabilities	—			610		284		—		—			894

50

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES Condensed Consolidating Balance Sheets December 31, 2012 (millions of dollars)
	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors		Eliminations			Consolidated
Margin deposits related to commodity positions	$	—		$	596		$	4		$	—	$	—		$	600
Accumulated deferred income taxes	—			3			52			—		(6		)	49
Accrued income taxes payable to parent	2			433			—			6		(410		)	31
Accrued taxes other than income	—			—			17			—		—			17
Accrued interest	18			389			281			—		(281		)	407
Other current liabilities	1			4			253			—		(3		)	255
Total current liabilities	112			12,985			3,585			188		(11,776		)	5,094
Accumulated deferred income taxes	79			—			3,569			—		111			3,759
Commodity and other derivative contractual liabilities	—			1,539			17			—		—			1,556
Notes or other liabilities due affiliates	—			—			5			—		—			5
Long-term debt held by affiliates	—			382			—			—		—			382
Long-term debt, less amounts due currently	515			29,355			28,486			—		(28,428		)	29,928
Other noncurrent liabilities and deferred credits	13			36			2,594			—		—			2,643
Total liabilities	719			44,297			38,256			188		(40,093		)	43,367
EFCH shareholder's equity	(10,506		)	(9,795		)	(5,962		)	350		15,407			(10,506		)
Noncontrolling interests in subsidiaries	—			—			—			112		—			112
Total equity	(10,506		)	(9,795		)	(5,962		)	462		15,407			(10,394		)
Total liabilities and equity	$	(9,787	)	$	34,502		$	32,294		$	650	$	(24,686	)	$	32,973

51

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

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 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

EFCH, a wholly owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. In April 2013, EFCH was converted from a Texas corporation to a Delaware limited liability company; the directors and officers and consolidated assets, businesses and operations are unchanged. We conduct our operations almost entirely through our wholly owned subsidiary, TCEH. 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. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently, there are no 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 EFH Corp.'s discussions with creditors.

Income Tax Matters — See Note 12 to Financial Statements for discussion of the agreement EFH Corp. reached with the IRS Appeals in March 2013 that resolved disputed adjustments from the IRS audit for the years 2003 through 2006 and the approval EFH Corp. received from the Joint Committee on Taxation of the IRS appeals settlement 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 EFH Corp. received from the IRS in April 2013 and its 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.

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 September 30, 2013, have effectively sold forward approximately 210 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 25,000 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, March 31, 2013 and June 30, 2013, the comparable hedge volumes totaled approximately 360 million MMBtu, 310 million MMBtu and 270 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 96% and 78% 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 71% (in MMbtu) of the positions in the hedging program at September 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.

52

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 September 30, 2013:

	Measure	Balance 2013 (a)	2014	Total
Natural gas hedge volumes (b)	mm MMBtu	~65	~146	~211
Weighted average hedge price (c)	$/MMBtu	~6.89	~7.80	—
Average market price (d)	$/MMBtu	~3.60	~3.86	—
Realization of hedge gains (e)	$ billions	~0.2	~0.6	~0.8

___________

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

(b) Where collars are reflected, the volumes are based on the delta equivalent short 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 September 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 September 30, 2013, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $210 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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Realized net gain	$	276		$	440		$	756		$	1,459
Unrealized net loss including reversals of previously recorded amounts related to positions settled	(258		)	(539		)	(739		)	(1,244		)
Total	$	18		$	(99	)	$	17		$	215

The cumulative unrealized mark-to-market net gain related to positions in the natural gas hedging program totaled $845 million and $1.584 billion at September 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.

53

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 our business. 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
September 30, 2013	$	3.60	$	3.86	$	4.06	$	4.17

___________

(a) Based on NYMEX Henry Hub prices.

(b) For March 31, 2013, June 30, 2013 and September 30, 2013, natural gas prices for 2013 represent the average of forward prices for April through December, July through December and October 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 September 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)	$ ~3		$ ~115	$ ~475
0.1/MMBtu/MWh change in market heat rate (c)	$	—	$ ~20	$ ~30
$1.00/gallon change in diesel fuel price	$ ~1		$ ~15	$ ~45

___________

(a) Balance of 2013 is from November 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 September 30, 2013.

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 September 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%	October 2013 through October 2014		$	18.140	billion (a)
6.8	%	-	9.0%	October 2015 through October 2017		$	12.600	billion (b)

___________

(a) Swaps related to an aggregate $1.6 billion principal amount of debt expired in 2013. Per the terms of the transactions, the notional amount of swaps entered into in 2011 grew by $1.280 billion 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.

54

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 September 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 presented in the table below. See Note 8 to Financial Statements for discussion of nonperformance risk adjustments included in unrealized net gain in 2013.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Realized net loss	$	(160	)	$	(168	)	$	(466	)	$	(505	)
Unrealized net gain (loss) including reversals of previously recorded amounts related to settled positions	413			(20		)	899			(16		)
Total	$	253		$	(188	)	$	433		$	(521	)

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.518 billion (before nonperformance risk adjustment) and $2.065 billion at September 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 September 30, 2013, a one percent change in interest rates would result in an increase or decrease of approximately $525 million in our cumulative unrealized mark-to-market net liability.

First-Lien Security for Natural Gas Hedging Program and Interest Rate Swaps — Approximately 95% 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 September 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 $1.2 billion (before nonperformance risk adjustment). This amount is subject to change based on changes in interest rates and natural gas prices.

Seasonal Suspension of Certain Generation Operations — In October 2013, ERCOT approved our notice of intent (filed in September 2013) to suspend operations at one of the three generation units at our Martin Lake generation facility for approximately six months beginning December 2013 due to low wholesale power prices and other market conditions. The unit is expected to return to service during the peak demand months in the summer of 2014. Our mines that support the Martin Lake facility are expected to continue year-round operations.

In August 2013, ERCOT approved our notice of intent, as previously disclosed, to suspend operations beginning October 1, 2013 at two of the three generation units at our Monticello generation facility due to low wholesale power prices and other market conditions. The two Monticello 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 are expected to 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.

Natural Gas-Fueled Generation Development — In August 2013, the TCEQ granted air permits to Luminant to build two natural gas combustion turbines totaling 420 MW to 460 MW at its existing DeCordova generation facility. 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. 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.

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Liability Management Program — At September 30, 2013, we had $30.4 billion principal amount of long-term debt outstanding, including $30 million pushed down from EFH Corp. We and EFH Corp. have implemented a liability management program designed to reduce debt, capture debt discount and extend debt maturities through debt exchanges, repurchases and extensions.

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 2009 related to TCEH debt include debt exchange, issuance and repurchase activities as follows (all transactions occurred prior to 2012):

Security (except where noted, debt amounts are principal amounts)	Debt Acquired		Debt Issued/Cash Paid
TCEH 10.25% Notes due 2015	$	1,513	$	—
TCEH Toggle Notes due 2016	758		—
TCEH Senior Secured Facilities due 2013 and 2014	1,604		—
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)	—		343
Total	$	3,875	$	3,168

____________

(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 $343 million of the proceeds from the October 2010 issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 that were used to repurchase debt, including $53 million used to repurchase debt held by EFH Corp.

Since inception, TCEH's transactions in the liability management program resulted in the capture of approximately $700 million of debt discount and the extension of approximately $19.6 billion of debt maturities to 2017-2021.

As the result of EFH Corp. and EFIH liability management transactions in December 2012 and the first quarter 2013, substantially all EFH Corp. debt guaranteed by EFCH was cancelled or amended to remove EFCH's guarantee, such that EFCH now guarantees $60 million principal amount of EFH Corp. 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."

EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) continue to consider and evaluate possible transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and have entered 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 exchanges or conversions of debt for preferred or common equity or warrants, including exchanges or conversions of debt of EFH Corp., EFIH, EFCH and TCEH into preferred or common equity or warrants of EFH Corp., EFIH, EFCH, TCEH and/or any of their subsidiaries.

In evaluating whether to undertake any liability management transaction, EFH Corp. 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 its 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.

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Greenhouse Gas Emissions — In September 2013, the EPA issued a proposed rule for greenhouse gas emission standards for new electricity generation units. We are currently reviewing this proposed rule; however, at this time it is uncertain how (if at all) the proposed rule, if finalized, would affect our results of operations, liquidity or financial condition.

President Obama has 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 proposed rule 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 proposed rule, if finalized, would affect our results of operations, liquidity or financial condition.

In addition, the US Supreme Court (Supreme Court) recently granted review in Am. Chemistry Council, et al v. EPA, et al. In that case, the Supreme Court will consider whether EPA's regulation of greenhouse gas emissions from new motor vehicles allow it to require permits under the CAA for stationary sources that emit greenhouse gases. We are not a party to that case. It is uncertain how (if at all) any decision by the Supreme Court 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.

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.

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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 under the Financial Reform Act for entities that are not Swap Dealers or Major Swap Participants became effective in August 2013, and we are in compliance with these rules.

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.

Recent PUCT/ERCOT Actions—In May 2013, ERCOT published an updated Capacity, Demand, and Reserves report. The May 2013 report showed declining reserve margins in the ERCOT market that fall below the current 13.75% target reserve margin to 11.6% in 2015 and 10.4% in 2016. A number of changes to the ERCOT market rules have been implemented for the stated purpose of sending appropriate price signals to encourage development of generation resources in ERCOT. These changes, among others, include an increased system-wide offer cap that applies to wholesale power offers in ERCOT (from its previous level of $3,000 per MWh to $4,500 per MWh effective August 2012, $5,000 per MWh effective June 2013 and $7,000 and $9,000 per MWh in the summers of 2014 and 2015, respectively).

In September 2013, the PUCT directed ERCOT to develop the processes necessary to implement a new price mechanism, "the operating reserve demand curve" (also known as "ORDC" and "Hogan B+"), which would provide for an increasing price adder to real-time wholesale power prices as reserves decline. The market rules implementing the operating reserve demand curve require approval by the ERCOT Board and could be appealed to the PUCT. Although two of the three PUCT commissioners indicated in October 2013 that ERCOT should have a required reserve margin instead of a target reserve margin, discussions are expected to continue among the PUCT, ERCOT, market participants and other stakeholders regarding the level of the reserve margin and additional actions necessary to meet a required reserve margin.

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.

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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.

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. The Texas Legislature is scheduled to convene its next legislative session in January 2015.

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

Sales Volume and Customer Count Data

	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
	2013		2012				2013		2012
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential	7,657		7,891		(3.0	)%	17,737		18,682		(5.1	)%
Small business (a)	1,635		1,757		(6.9	)%	4,156		4,694		(11.5	)%
Large business and other customers	2,679		2,846		(5.9	)%	7,478		7,892		(5.2	)%
Total retail electricity	11,971		12,494		(4.2	)%	29,371		31,268		(6.1	)%
Wholesale electricity sales volumes (b)	11,029		9,337		18.1	%	28,566		24,085		18.6	%
Total sales volumes	23,000		21,831		5.4	%	57,937		55,353		4.7	%
Average volume (kilowatt-hours) per residential customer (c)	5,010		5,019		(0.2	)%	11,500		11,707		(1.8	)%
Weather (North Texas average) – percent of normal (d):
Cooling degree days	106.5	%	105.5	%	0.9	%	103.5	%	113.7	%	(9.0	)%
Heating degree days	—		—		—		104.1	%	74.6	%	39.5	%
Customer counts:
Retail electricity customers (end of period, in thousands) (e):
Residential							1,524		1,566		(2.7	)%
Small business (a)							176		176		—	%
Large business and other customers							17		17		—	%
Total retail electricity customers							1,717		1,759		(2.4	)%

____________

(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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Revenue and Commodity Hedging and Trading Activities

	Three Months Ended September 30,						% Change		Nine Months Ended September 30,						% Change
	2013			2012					2013			2012
Operating revenues:
Retail electricity revenues:
Residential	$	998		$	982		1.6	%	$	2,310		$	2,322		(0.5	)%
Small business (a)	197			214			(7.9	)%	523			583			(10.3	)%
Large business and other customers	181			195			(7.2	)%	517			549			(5.8	)%
Total retail electricity revenues	1,376			1,391			(1.1	)%	3,350			3,454			(3.0	)%
Wholesale electricity revenues (b) (c)	449			291			54.3	%	1,019			715			42.5	%
Amortization of intangibles (d)	4			7			(42.9	)%	15			15			—	%
Other operating revenues	64			63			1.6	%	188			174			8.0	%
Total operating revenues	$	1,893		$	1,752		8.0	%	$	4,572		$	4,358		4.9	%
Net gain (loss) from commodity hedging and trading activities:
Realized net gains on settled positions	$	228		$	538		(57.6	)%	$	739		$	1,553		(52.4	)%
Unrealized net losses	(170		)	(541		)	(68.6	)%	(710		)	(1,324		)	(46.4	)%
Total	$	58		$	(3	)	—	%	$	29		$	229		—	%

____________

(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 September 30,				Nine Months Ended September 30,
	2013		2012		2013			2012
Reported in revenues	$	—	$	4	$	(1	)	$	—
Reported in fuel and purchased power costs	7		11		18			34
Net gain	$	7	$	15	$	17		$	34

(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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Production, Purchased Power and Delivery Cost Data

	Three Months Ended September 30,						% Change		Nine Months Ended September 30,						% Change
	2013			2012					2013			2012
Fuel, purchased power costs and delivery fees ($ millions):
Fuel for nuclear facilities	$	45		$	47		(4.3	)%	$	128		$	139		(7.9	)%
Fuel for lignite/coal facilities	273			251			8.8	%	674			606			11.2	%
Total nuclear and lignite/coal facilities	318			298			6.7	%	802			745			7.7	%
Fuel for natural gas facilities and purchased power costs (a)	94			97			(3.1	)%	219			248			(11.7	)%
Amortization of intangibles (b)	9			14			(35.7	)%	29			39			(25.6	)%
Other costs	48			58			(17.2	)%	146			147			(0.7	)%
Fuel and purchased power costs	469			467			0.4	%	1,196			1,179			1.4	%
Delivery fees	383			383			—	%	979			974			0.5	%
Total	$	852		$	850		0.2	%	$	2,175		$	2,153		1.0	%
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
Nuclear facilities	$	8.50		$	8.85		(4.0	)%	$	8.47		$	8.83		(4.1	)%
Lignite/coal facilities (c)	$	19.25		$	20.21		(4.8	)%	$	19.95		$	21.01		(5.0	)%
Natural gas facilities and purchased power (d)	$	46.61		$	44.98		3.6	%	$	46.74		$	45.26		3.3	%
Delivery fees per MWh	$	31.88		$	30.56		4.3	%	$	33.19		$	31.06		6.9	%
Production and purchased power volumes (GWh):
Nuclear facilities	5,273			5,276			(0.1	)%	15,170			15,772			(3.8	)%
Lignite/coal facilities (e)	16,474			15,179			8.5	%	40,004			35,929			11.3	%
Total nuclear and lignite/coal-facilities	21,747			20,455			6.3	%	55,174			51,701			6.7	%
Natural gas-facilities	525			594			(11.6	)%	767			1,117			(31.3	)%
Purchased power (f)	728			782			(6.9	)%	1,996			2,535			(21.3	)%
Total energy supply volumes	23,000			21,831			5.4	%	57,937			55,353			4.7	%
Capacity factors:
Nuclear facilities	103.8		%	103.9		%	(0.1	)%	100.7		%	104.3		%	(3.5	)%
Lignite/coal facilities (e)	93.1		%	85.7		%	8.6	%	76.2		%	68.2		%	11.7	%
Total	95.5		%	89.8		%	6.3	%	81.6		%	76.2		%	7.1	%

____________

(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 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.

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

(e) Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal-fueled units totaling 860 GWh and 2,510 GWh for the three months ended September 30, 2013 and 2012, respectively, and 7,790 GWh and 7,480 GWh for the nine months ended September 30, 2013 and 2012, respectively.

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

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

Operating revenues increased $141 million, or 8%, to $1.893 billion in 2013.

Retail electricity revenues decreased $15 million, or 1%, to $1.376 billion reflecting a $58 million decline in sales volumes partially offset by $43 million in higher average prices. Sales volumes fell 4% reflecting declines in both the residential and business markets. Residential volumes reflected a 3% decline in customer counts. Business markets volumes declined 6% reflecting competitive intensity and changes in customer mix. Weather did not have a significant effect on volume changes. 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 $158 million, or 54%, to $449 million in 2013 reflecting a $105 million increase driven by higher average prices and a $53 million increase in sales volumes. Higher average prices reflected an increase in natural gas prices. Sales volumes increased 18% reflecting higher available generation due to lower economic backdown and lower volumes sold in our retail operations.

Fuel, purchased power costs and delivery fees increased $2 million to $852 million in 2013. Lignite/coal fuel costs increased $22 million driven by higher generation volumes. Natural gas fuel costs decreased $10 million reflecting lower generation volumes, partially offset by increased fuel prices, and other costs decreased $10 million primarily due to lower net charges from ERCOT.

A 9% increase in lignite/coal-fueled generation volumes was driven by less economic backdown in 2013 reflecting higher wholesale power prices.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $58 million in net gains and $3 million in net losses for the three months ended September 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 September 30, 2013
	Net Realized Gains		Net Unrealized Losses			Total
Hedging positions	$	203	$	(146	)	$	57
Trading positions	25		(24		)	1
Total	$	228	$	(170	)	$	58

	Three Months Ended September 30, 2012
	Net Realized Gains		Net Unrealized Losses			Total
Hedging positions	$	494	$	(475	)	$	19
Trading positions	44		(66		)	(22		)
Total	$	538	$	(541	)	$	(3	)

The decreases in net realized gains and unrealized losses reflected lower volumes and prices of maturing positions in the natural gas hedging program.

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 $7 million in net gains in 2013 and $15 million in net gains in 2012 (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).

Operating costs decreased $12 million, or 6%, to $189 million in 2013. The decrease included $8 million in lower nuclear generation maintenance costs reflecting activities performed for the fall refueling outage completed in the fourth quarter of 2012 (and no refueling outage in the fall of 2013) and $3 million in lower lease expense due to purchase of the interest in a trust holding certain combustion turbines (see Note 5 to Financial Statements).

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SG&A expenses increased $1 million to $175 million in 2013. The increase reflected $14 million in legal and consulting costs in the third quarter associated with our liability management program, compared to $4 million in the third quarter 2012. This increase is partially offset by $11 million in lower employee-related expenses reflecting lower benefit costs and incentive compensation expense.

Other deductions totaled $8 million in 2013 and $30 million in 2012. Other deductions in 2013 included $3 million of asset impairments. Other deductions in 2012 included a $24 million impairment of mineral interests. See Note 12 to Financial Statements.

Interest income decreased $9 million to $1 million in 2013. The decrease was driven by EFH Corp.'s settlement of the TCEH Demand Notes. See Note 12 to Financial Statements.

Interest expense and related charges decreased $432 million to $340 million in 2013. The decrease was driven by $413 million in unrealized mark-to-market net gains on interest rate swaps in 2013 compared to $20 million in net losses in 2012 and $18 million in lower interest expense due to a reduction in debt pushed down (see Note 5 to Financial Statements). See Note 8 to Financial Statements regarding nonperformance risk adjustment related to interest rate swaps. These changes were partially offset by $19 million in higher amortization of debt issuance costs and discounts reflecting the January 2013 amendment and extension of the TCEH Revolving Credit Facility.

Income tax benefit totaled $17 million and $228 million on pretax income in 2013 and pretax losses in 2012, respectively. Excluding the $38 million in total income tax benefit recorded in 2013 related to resolution of IRS audit matters (see Note 12 to Financial Statements regarding uncertain tax positions), the effective rate was 52.5% and 37.2%, respectively. The change in the effective tax rate reflected a decrease in the lignite depletion deduction, partially offset by lower Texas margin tax expense and lower nondeductible interest on debt.

EFCH had after-tax net income of $57 million in 2013 compared to an after-tax net loss of $385 million in 2012. The change was driven by unrealized gains on interest rate swaps compared to unrealized losses in 2012, and lower unrealized losses on commodity hedging activities.

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Financial Results — Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Operating revenues increased $214 million, or 5%, to $4.572 billion in 2013.

Retail electricity revenues decreased $104 million, or 3%, to $3.350 billion reflecting a $210 million decline in sales volumes partially offset by $106 million in higher average prices. Sales volumes fell 6% reflecting declines in both the residential and business markets. Residential volumes declined 5% reflecting a 3% decrease in customer counts and milder weather in the second quarter. Business market volumes declined 8% reflecting competitive intensity and changes in customer mix. 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 $304 million, or 43%, to $1.019 billion in 2013 reflecting a $171 million increase due to higher average prices and a $133 million increase in sales volumes. Higher average prices reflected an increase in natural gas prices. Sales volumes increased 19% reflecting higher generation volumes and lower volumes sold in our retail operations.

Fuel, purchased power costs and delivery fees increased $22 million, or 1%, to $2.175 billion in 2013. Lignite/coal fuel costs increased $68 million driven by higher generation volumes. Natural gas fuel costs decreased $27 million reflecting decreases in generation volumes, partially offset by increased fuel prices. Nuclear fuel costs decreased $11 million reflecting a decrease in generation volumes and lower prices.

An 11% increase in lignite/coal-fueled generation volumes was driven by fewer unplanned and planned outage days, while nuclear-fueled generation volumes decreased 4% reflecting a planned refueling outage in the spring of 2013.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $29 million and $229 million in net gains for the nine months ended September 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."

	Nine Months Ended September 30, 2013
	Net Realized Gains (Losses)			Net Unrealized Losses			Total
Hedging positions	$	751		$	(709	)	$	42
Trading positions	(12		)	(1		)	(13		)
Total	$	739		$	(710	)	$	29

	Nine Months Ended September 30, 2012
	Net Realized Gains		Net Unrealized Losses			Total
Hedging positions	$	1,504	$	(1,310	)	$	194
Trading positions	49		(14		)	35
Total	$	1,553	$	(1,324	)	$	229

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 $17 million in net gains in 2013 and $34 million in net gains in 2012 (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).

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Operating costs increased $49 million, or 8%, to $685 million in 2013. The increase reflected $42 million in higher nuclear generation outage costs driven by the planned refueling outage in the spring of 2013. The balance of the increase was driven by higher maintenance costs associated with lignite/coal-fueled generation unit outages of $18 million, reflecting timing and scope of the activities, partially offset by $6 million in lower lease expense due to purchase of the interest in a trust holding certain combustion turbines and $6 million in lower information technology project costs.

Depreciation and amortization increased $20 million, or 2%, to $1.012 billion in 2013. The increase reflected retirement of coal plant assets and capital investment.

SG&A expenses increased $18 million, or 4%, to $502 million in 2013. The increase reflected $48 million in legal and consulting costs in the nine months ending September 30, 2013 associated with our liability management program, compared to $4 million in 2012. This increase is partially offset by $21 million lower employee-related costs primarily reflecting lower incentive compensation expense.

Other deductions totaled $12 million in 2013 and $37 million in 2012. Other deductions in 2013 included $3 million of asset impairments. Other deductions in 2012 included a $24 million impairment of mineral interests and a $4 million counterparty contract settlement. See Note 12 to Financial Statements.

Interest income decreased $31 million to $5 million in 2013. The decrease was driven by EFH Corp.'s settlement of the TCEH Demand Notes. See Note 12 to Financial Statements.

Interest expense and related charges decreased $930 million, or 41%, to $1.338 billion in 2013. The decrease was driven by $899 million in unrealized mark-to-market net gains on interest rate swaps in 2013 compared to $16 million in net losses in 2012 and $52 million in lower interest expense due to a reduction in debt pushed down (see Note 5 to Financial Statements). See Note 8 to Financial Statements regarding nonperformance risk adjustment related to interest rate swaps. This change was partially offset by $58 million in higher amortization of debt issuance costs and discounts reflecting the January 2013 amendment and extension of the TCEH Revolving Credit Facility.

Income tax benefit totaled $476 million and $692 million on pretax losses in 2013 and 2012, respectively. Excluding the $80 million in total income tax benefit recorded in the nine months ended September 30, 2013 related to resolution of IRS audit matters (see Note 12 to Financial Statements regarding uncertain tax positions), the effective tax rate was 34.1% and 34.8% in 2013 and 2012, respectively. The decrease in the effective tax rate reflected a decrease in the lignite depletion deduction, partially offset by lower Texas margin tax expense and lower nondeductible interest on debt.

After-tax loss decreased $612 million to $686 million in 2013 driven by unrealized mark-to-market net gains on interest rate swaps, compared to net losses in 2012, and the income tax benefit related to audit resolutions, partially offset by lower net gains from commodity hedging activities.

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2013 and 2012. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $695 million and $1.290 billion 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.

	Nine Months Ended September 30,
	2013			2012
Commodity contract net asset at beginning of period	$	1,664		$	3,190
Settlements of positions (a)	(749		)	(1,420		)
Changes in fair value of positions in the portfolio (b)	54			130
Other activity (c)	(47		)	(36		)
Commodity contract net asset at end of period	$	922		$	1,864

____________

(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 September 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 September 30, 2013
Source of fair value	Less than 1 year			1-3 years			Total
Prices actively quoted	$	20		$	(9	)	$	11
Prices provided by other external sources	764			151			915
Prices based on models	(9		)	5			(4		)
Total	$	775		$	147		$	922
Percentage of total fair value	84		%	16		%	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 —Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012 — Cash used in operating activities totaled $121 million in 2013 compared to cash provided by operating activities of $329 million in 2012. The change of $450 million reflected a decrease of $703 million in net realized gains from the natural gas hedging program. Favorable changes in margin deposits totaling $124 million and favorable net changes in various working capital and other asset and liability accounts due in large part to timing of payments were largely offset by higher interest payments.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $130 million and $145 million for the nine months ended September 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 $7 million in 2013 compared to $493 million used in 2012. Activity in 2012 reflected repayments of borrowings under the TCEH Revolving Credit Facility and a $159 million payment to settle transition bond reimbursement agreements with Oncor (see Note 11 to Financial Statements).

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

Cash provided by investing activities totaled $215 million in 2013 compared to $353 million in 2012. Amounts provided in 2013 and 2012 reflect EFH Corp. repayments of TCEH Demand Notes, which totaled $698 million and $950 million, respectively, (see Note 11 to Financial Statements). Capital expenditures (excluding nuclear fuel purchases) decreased $145 million to $353 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 $96 million to $59 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.

Debt Activity— Activities related to short-term borrowings and long-term debt during the nine months ended September 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	$	(90	)
EFCH	—		(4		)
EFH Corp. (pushed down to EFCH) (b)	—		420
Total long-term	385		326
Total short-term – TCEH (c)	90		—
Total	$	475	$	326

____________

(a) Borrowings represent noncash principal increases of TCEH Term Loan Facilities as fees in consideration for the extension of $645 million of commitments under the TCEH Revolving Credit Facility, as well as 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 $82 million of payments of principal at scheduled maturity or mandatory tender dates and $8 million of payments of capital lease liabilities.

(b) Settlements represent the effects of debt cancellations and other transactions discussed in Note 5 to Financial Statements.

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

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

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Available Liquidity — The following table summarizes changes in available liquidity for the nine months ended September 30, 2013.

	Available Liquidity
	September 30, 2013		December 31, 2012		Change
Cash and cash equivalents	$	1,262	$	1,175	$	87
TCEH Letter of Credit Facility	171		183		(12		)
Total liquidity	$	1,433	$	1,358	$	75

The increase in available liquidity of $75 million in the nine months ended September 30, 2013 was driven by EFH Corp.'s settlement of its borrowings from TCEH under the TCEH Demand Notes, which totaled $698 million at December 31, 2012, partially offset by $412 million in cash used for capital expenditures, including nuclear fuel purchases, $128 million in cash used in operating activities and $40 million used to acquire the interest in a combustion turbine lease trust. Based on forward wholesale power prices in ERCOT, which are subject to the effects of changing market conditions, TCEH may not have sufficient liquidity, absent any financing transactions, to meet its obligations within the next twelve months.

Debt Capacity—We believe that TCEH is permitted under its applicable debt agreements to issue additional senior secured debt (in each case, subject to certain exceptions and conditions set forth in its applicable debt documents) as follows:

• 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

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

Investment Capacity — We believe that TCEH is permitted under applicable debt agreements to make "investments" that could result in, among other things, additional liquidity through financings secured by existing assets (subject to certain exceptions and conditions set forth in the applicable debt documents). TCEH is permitted under the TCEH Senior Secured Facilities to make additional investments of approximately $1.4 billion, of which approximately $915 million may include investments in unrestricted subsidiaries and joint ventures (as defined). The balance is a general restricted payment basket that limits the aggregate amount of investments and dividends and redemptions of certain debt.

These debt capacity and investment capacity 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 (i) additional secured or unsecured debt, including, but not limited to, acquisition debt, refinancing debt, capital leases and hedging obligations and (ii) additional investments, including but not limited to, permitted investments. 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 and the investments we are permitted to make under our debt agreements could be materially different than the amounts provided above.

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

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 September 30, 2013, approximately 95% 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.

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Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. At September 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 September 30, 2013, an insignificant amount 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 September 30, 2013, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• For exchange cleared transactions (including initial margin), $4 million in cash has been posted with counterparties, net of $16 million in cash received, as compared to $69 million posted at December 31, 2012;

• For over-the-counter and other non-exchange cleared transactions, $336 million in cash has been received from counterparties, net of $1 million in cash posted, as compared to $598 million received, net of $2 million in cash posted, at December 31, 2012;

• $353 million in letters of credit have been posted with counterparties, as compared to $376 million posted at December 31, 2012, and

• $30 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 and TCEH. EFH Corp. is a corporate member of the EFH Corp. consolidated group, while each of 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. 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 and TCEH) 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.

In April 2013, EFH Corp. 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.

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. 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 EFH Corp. had tax strategies available to it that it believed would avoid triggering income tax payments upon a transaction involving its investment in EFCH, EFH Corp. did not record deferred income tax liabilities with respect to this outside basis difference.

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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, there are expected to be no income tax payments to EFH Corp. under the tax sharing agreement for federal income taxes and payments for the Texas margin tax are expected to total approximately $27 million. Federal income tax payments totaled $84 million and $34 million for the nine months ended September 30, 2013 and 2012, respectively. Texas margin tax payments totaled $49 million and $48 million for the nine months ended September 30, 2013 and 2012, respectively.

See Note 12 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. On October 29, 2013, we terminated the Accounts Receivable Securitization Program and repaid all outstanding obligations under the program.

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 September 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 we 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 resolve our liquidity needs, including refinancing 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 financial statements for the year ended December 31, 2013. See Note 1 to Financial Statements.

Adjusted EBITDA (as used in the maintenance covenant contained in the TCEH Senior Secured Facilities) for the twelve months ended September 30, 2013 totaled $2.871 billion for TCEH. See Exhibits 99(b) and 99(c) for a reconciliation of net loss to Adjusted EBITDA for TCEH and EFH Corp., respectively, for the nine and twelve months ended September 30, 2013 and 2012.

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The table below summarizes TCEH's secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and the TCEH accounts receivable securitization program and other financial ratios of EFH Corp. and TCEH 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 and the EFH Corp. 10.875% Notes and EFH Corp. Toggle 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. 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. 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).

	September 30, 2013	December 31, 2012	Threshold Level at September 30, 2013
Maintenance Covenant:
TCEH Senior Secured Facilities and TCEH's accounts receivable securitization program:
Secured debt to Adjusted EBITDA ratio	7.38 to 1.00	5.88 to 1.00	Must not exceed 8.00 to 1.00 (a)
Debt Incurrence Thresholds:
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	12.3 to 1.0	10.1 to 1.0	Equal to or less than 7.0 to 1.0
TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes:
TCEH fixed charge coverage ratio	1.0 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	10.6 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 September 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.

Material Credit Rating Covenants and Creditworthiness 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 September 30, 2013, counterparties to those contracts could have required TCEH to post up to an aggregate of $12 million in additional collateral. This amount largely represents the unfavorable market terms of these contracts at September 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 are required to assure adequate creditworthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these requirements, 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 September 30, 2013, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $21 million, with $10 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at September 30, 2013, TCEH posted letters of credit in the amount of $65 million, which are subject to adjustments.

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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 12 to Financial Statements, our recorded mining reclamation liability totaled $86 million at September 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 creditworthiness 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 $140 million at September 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 EFCH and its subsidiaries, including 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 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 ($22.635 billion at September 30, 2013), under such facilities.

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

Under the terms of a TCEH rail car lease, which has $39 million in remaining lease payments at September 30, 2013 and terminates in 2017, if TCEH fails 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 $42 million in remaining lease payments at September 30, 2013 and terminates in 2028, if payment obligations of TCEH in excess of $200 million in the aggregate 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.

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.

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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 have 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 September 30, 2013 that are expected to materially impact our financial statements.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Market risk is the risk that 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.

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

Commodity Price Risk

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

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

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.

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.

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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.

	September 30, 2013		December 31, 2012
Month-end average Trading VaR:	$	2	$	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.

	September 30, 2013		December 31, 2012
Month-end average MtM VaR:	$	72	$	132
Month-end high MtM VaR:	$	97	$	206
Month-end low MtM VaR:	$	43	$	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.

	September 30, 2013		December 31, 2012
Month-end average EaR:	$	29	$	109
Month-end high EaR:	$	37	$	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.

Interest Rate Risk

At September 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 $18 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 $1.236 billion at September 30, 2013. The components of this exposure are discussed in more detail below.

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Assets subject to credit risk at September 30, 2013 include $592 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $60 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 September 30, 2013, the exposure to credit risk from these counterparties totaled $644 million taking into account the netting provisions of the master agreements described above but before taking into account $369 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $275 million increased $20 million in the nine months ended September 30, 2013.

Of this $275 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.

The following table presents the distribution of credit exposure at September 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	$	626		$	366	$	260
Noninvestment grade	18			3		15
Totals	$	644		$	369	$	275
Investment grade	97.2		%			94.5		%
Noninvestment grade	2.8		%			5.5		%

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 two counterparties, which represented 18% and 15% of the $275 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 Texas Reliability Entity, Inc., 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;

◦ 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 the Employee Retirement Income Security Act of 1974, as amended;

• 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.

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Item 5. OTHER INFORMATION

Accounts Receivable Securitization Program Termination

On October 29, 2013, EFH Corp. and its subsidiaries, TCEH, TXU Energy and TXU Energy Receivables Company LLC (TXU Energy Receivables Company) terminated the TXU Energy accounts receivable securitization program (the program). For a description of the Accounts Receivable Securitization Program, see Note 7 to the 2012 Form 10-K and Note 4 to Financial Statements.

In connection with the termination of the program, (i) TXU Energy repurchased $491 million in accounts receivable from TXU Energy Receivables Company for an aggregate purchase price of $474 million, which constituted all of the accounts receivable outstanding and previously sold by TXU Energy to TXU Energy Receivables Company under the program pursuant to the Trade Receivables Sale Agreement, dated as of November 30, 2012, among TXU Energy, TXU Energy Receivables Company and EFH Corp. (Trade Receivables Sale Agreement), (ii) TXU Energy Receivables Company paid TXU Energy $11 million, constituting repayment in full of the outstanding obligations under the subordinated note previously issued by TXU Energy Receivables Company to TXU Energy as partial consideration for the accounts receivable sold to TXU Energy Receivables Company pursuant to the Trade Receivables Sale Agreement, and (iii) TXU Energy Receivables Company paid Citibank, N.A. (Citibank), as Group Managing Agent under the First Lien Trade Receivables Financing Agreement, dated as of November 30, 2012, among TXU Energy Receivables Company, TXU Energy, certain Investors party thereto, and Citibank (Trade Receivables Financing Agreement), an amount equal to $126 million, constituting all of TXU Energy Receivables Company 's outstanding obligations under the Trade Receivables Financing Agreement. Upon the payment of such amounts, the Trade Receivables Sale Agreement and the Trade Receivables Financing Agreement were terminated. Citibank also serves as the administrative agent and collateral agent under TCEH's Senior Secured Credit Facilities and collateral agent under the TCEH Senior Secured Notes.

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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
(2)	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2(a)	001-34543 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	2(a)	—	Plan of Conversion of Energy Future Competitive Holdings Company
(3(i))	Articles of Incorporation
3(a)	001-34543 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	3(a)	—	Certificate of Formation of Energy Future Competitive Holdings Company LLC
(3(ii))	By-laws
3(b)	001-34543 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	3(b)	—	Limited Liability Company Agreement Of Energy Future Competitive Holdings Company LLC
(31)	Rule 13a - 14(a)/15d - 14(a) Certifications
31(a)			—	Certification of John F. Young, principal executive officer of Energy Future Competitive Holdings Company LLC, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Company LLC, 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 Competitive Holdings Company LLC, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Company LLC, 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 September 30, 2013.
99(b)			—	Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2013 and 2012.
99(c)			—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2013 and 2012.
	XBRL Data Files
101.INS			—	XBRL Instance Document**
101.SCH			—	XBRL Taxonomy Extension Schema Document**
101.CAL			—	XBRL Taxonomy Extension Calculation Document**

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Exhibits	Previously Filed With File Number*	As Exhibit
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 Competitive Holdings Company LLC
By:	/s/ STAN SZLAUDERBACH
Name:	Stan Szlauderbach
Title:	Senior Vice President and Controller
	(Principal Accounting Officer)

Date: October 31, 2013

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