UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________________________________

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 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 or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1601 Bryan Street, Dallas, TX 75201-3411	(214) 812-4600
(Address of principal executive offices)(Zip Code)	(Registrant's telephone number, including area code)

 ____________________________________________________________

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

________________________________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨     No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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  ¨    No  x

At April 29, 2014, the outstanding membership interest in Energy Future Competitive Holdings Company LLC was directly held by Energy Future Holdings Corp.

________________________________________ 

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

Glossary		ii
PART I
Items 1. and 2.	BUSINESS AND PROPERTIES	1
Item 1A.	RISK FACTORS	19
Item 1B.	UNRESOLVED STAFF COMMENTS	34
Item 3.	LEGAL PROCEEDINGS	35
Item 4.	MINE SAFETY DISCLOSURES	37
PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	38
Item 6.	SELECTED FINANCIAL DATA	39
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	41
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	81
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	89
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	173
Item 9A.	CONTROLS AND PROCEDURES	173
Item 9B.	OTHER INFORMATION	176
PART III
Item 10.	MANAGERS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	177
Item 11.	EXECUTIVE COMPENSATION	181
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	183
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE	184
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	187
PART IV
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	189

Energy Future Competitive Holdings Company LLC's (EFCH) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the Energy Future Holdings Corp. (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 annual report on Form 10-K. The representations and warranties contained in any agreement that EFCH has filed as an exhibit to this annual report on Form 10-K 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 annual report on Form 10-K and other Securities and Exchange Commission filings of EFCH and its subsidiaries occasionally make references to EFCH, TCEH, TXU Energy or Luminant (or "we," "our," "us" or "the company") 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.

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-K (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.
ancillary services	Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system. These services include monitoring and providing for various types of reserve generation to ensure adequate electricity supply and system reliability.
Bankruptcy Filing	Voluntary petitions for relief under Chapter 11 of the US Bankruptcy Code (Bankruptcy Code) in the US Bankruptcy Court for the District of Delaware (Bankruptcy Court) filed on April 29, 2014 by the Debtors.
CAIR	Clean Air Interstate Rule
CFTC	US Commodity Futures Trading Commission
CO2	carbon dioxide
CPNPC	Refers to Comanche Peak Nuclear Power Company LLC, which was formed by subsidiaries of TCEH (holding an 88% equity interest) and Mitsubishi Heavy Industries Ltd. (MHI) (holding a 12% equity interest) for the purpose of developing two new nuclear generation units and obtaining a combined operating license from the NRC for the units.
Consenting Creditors	Means collectively, (i) certain lenders or investment advisors or managers of discretionary accounts (Consenting TCEH First Lien Lenders) that hold claims under the TCEH Senior Secured Facilities; (ii) certain holders (Consenting TCEH First Lien Noteholders and together with the Consenting TCEH First Lien Lenders, the Consenting TCEH First Lien Creditors) of TCEH Senior Secured Notes; (iii) certain holders (Consenting EFIH First Lien Noteholders) of the EFIH 6.875% Notes and the EFIH 10% Notes (EFIH First Lien Notes); (iv) certain holders (Consenting EFIH Second Lien Noteholders) of the EFIH 11% Notes and the EFIH 11.75% Notes (EFIH Second Lien Notes); (v) certain holders (Consenting EFIH Unsecured Noteholders) of the EFIH Toggle Notes; and certain holders (the Consenting EFH Corp. Unsecured Noteholders) of the EFH Corp. 5.55% Series P Senior Notes due 2014, the EFH Corp. 6.50% Series Q Senior Notes due 2024, EFH Corp. 6.55% Series R Senior Notes due 2034, the EFH Corp. 11.250%/12.00% Senior Toggle Notes due 2017, the EFH Corp. 10.875% Senior Notes due 2017, the EFH Corp. 9.75% Fixed Senior Notes due 2019, and the EFH Corp. 10% Fixed Senior Notes due 2020 (EFH Unsecured Notes).
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 remanded by the US Supreme Court to the D.C. Circuit Court for further proceedings consistent with the US Supreme Court's opinion (see Note 11 to Financial Statements)
DIP Facility	Refers to TCEH's proposed debtor-in-possession financing. See Note 10 to Financial Statements.

ii

Debtors	EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities
D.C. Circuit Court	US Court of Appeals for the District of Columbia Circuit
DOE	US Department of Energy
EBITDA	earnings (net income) before interest expense, income taxes, depreciation and amortization
EFCH	Energy Future Competitive Holdings Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context
EFH Corp.	Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context, whose major subsidiaries include TCEH and Oncor
EFIH	Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings
EFIH Finance	EFIH Finance Inc., a direct, wholly owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities
EFIH Second Lien DIP Facility	Refers, collectively, to the facility that includes the EFIH Second Lien DIP Notes.
EPA	US Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
ERISA	Employee Retirement Income Security Act of 1974, as amended
FERC	US Federal Energy Regulatory Commission
Fifth Circuit Court	US Court of Appeals for the Fifth Circuit
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GWh	gigawatt-hours
ICE	the IntercontinentalExchange, a commodity exchange
IRS	US Internal Revenue Service
kWh	kilowatt-hours
LIBOR	London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
Luminant	subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas
market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.
MATS	the Mercury and Air Toxics Standard established by the EPA
Merger	The transaction referred to in the Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which was completed on October 10, 2007.

iii

MMBtu	million British thermal units
Moody's	Moody's Investors Services, Inc.
MW	megawatts
MWh	megawatt-hours
NERC	North American Electric Reliability Corporation
NOX	nitrogen oxides
NRC	US Nuclear Regulatory Commission
NYMEX	the New York Mercantile Exchange, a physical commodity futures exchange
Oncor	Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities
Oncor Holdings	Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context
Oncor Ring-Fenced Entities	Oncor Holdings and its direct and indirect subsidiaries, including Oncor.
Oncor Tax Sharing Agreement	Federal and State Income Tax Allocation Agreement among EFH Corp., Oncor Holdings, Oncor and Texas Transmission
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
purchase accounting	The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or "purchase price" of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
REP	retail electric provider
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
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 Debtors	TCEH and its subsidiaries that are Debtors in the Chapter 11 Cases

iv

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 with a maturity date of November 1, 2015 and 10.25% Senior Notes with a maturity date of November 1, 2015, Series B (collectively, TCEH 10.25% Notes) and TCEH's and TCEH Finance's 10.50%/11.25% Senior Toggle Notes with a maturity date of 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 10 to Financial Statements for details of these facilities.
TCEH Senior Secured Notes	TCEH's and TCEH Finance's 11.5% Senior Secured Notes with a maturity date of October 1, 2020
TCEH Senior Secured Second Lien Notes	Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes with a maturity date of April 1, 2021 and TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes with a maturity date of 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.
TRE	Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols
TXU Energy	TXU Energy Retail Company LLC, a direct, wholly owned subsidiary of TCEH that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
US	United States of America
VIE	variable interest entity

v

PART I.

Items 1. and 2. BUSINESS AND PROPERTIES

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" on page ii for defined terms.

EFCH's Business and Strategy

As described more fully below under "Filing under Chapter 11 of the United States Bankruptcy Code," on April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, (the Debtors) filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). During the pendency of the Bankruptcy Filing (the Chapter 11 Cases), the Debtors will operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. We intend to conduct our business operations in the normal course and maintain our focus on achieving excellence in customer service and meeting the needs of electricity consumers in Texas.

EFCH, a wholly owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. We conduct our operations almost entirely through our wholly owned subsidiary, TCEH. TCEH is a 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. Collectively with its operating subsidiaries, EFCH is the largest generator and retailer of electricity in Texas. 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.

EFCH's principal asset is its investment in TCEH. EFCH is a guarantor of a significant portion of TCEH's debt and $60 million principal amount of EFH Corp.'s debt.

TCEH owns 15,427 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas fueled generation facilities and accounts for approximately 18% of the generation capacity in our market. TCEH is also one of the largest purchasers of wind-generated electricity in Texas and the US. TCEH provides competitive electricity and related services to 1.7 million retail electricity customers in Texas.

At December 31, 2013, we had approximately 5,230 full-time employees, including approximately 2,020 employees under collective bargaining agreements.

Filing under Chapter 11 of the United States Bankruptcy Code

On April 29, 2014, EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. During the pendency of the Bankruptcy Filing, the Debtors will operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

The Bankruptcy Filing resulted primarily from the adverse effects on EFCH of lower wholesale electricity prices in ERCOT driven by the sustained decline in natural gas prices since mid-2008. Further, the remaining natural gas hedges that TCEH entered into when forward market prices of natural gas were significantly higher than current prices mature in 2014. These market conditions challenged EFCH's profitability and operating cash flows and resulted in the inability to support its significant interest payments and debt maturities, including the remaining debt obligations due in 2014, and to refinance and/or extend the maturities of its outstanding debt. These liquidity matters raised substantial doubt about EFCH's ability to continue as a going concern without a restructuring of the debt.

In consideration of the liquidity matters discussed above, the report of EFCH's independent registered public accounting firm that accompanies its audited consolidated financial statements for the year ended December 31, 2013 included in this annual report contains an explanatory paragraph regarding the substantial doubt about EFCH's ability to continue as a going concern.

1

In 2013, EFH Corp. began to engage in discussions with certain creditors, including TCEH creditors, with respect to proposed changes to its capital structure, including the possibility of a consensual, prepackaged restructuring transaction. Because of the more recent constructive nature of these discussions, TCEH elected not to make interest payments due in April 2014 totaling $123 million on certain debt obligations. Under the terms of the debt obligations that apply to the substantial majority of the missed interest payments, the lenders had the right to accelerate the payment of the debt if TCEH had not cured the default after an applicable grace period. In consideration of the additional time required to evaluate the effects of events related to the creditor discussions, including potential changes to EFH Corp.'s capital structure on the financial statements and disclosures included in EFH Corp.’s, EFCH’s and EFIH’s Annual Reports on Form 10-K for the year ended December 31, 2013, the companies did not file their Annual Reports on Form 10-K for the year ended December 31, 2013 with the SEC by April 15, 2014, the date when the reports were required to be filed (including an allowed extension), and instead filed those Annual Reports on April 30, 2014. In anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors entered into a Restructuring Support and Lock-Up Agreement (the Restructuring Support and Lock-Up Agreement) with various stakeholders in order to effect an agreed upon restructuring of the Debtors through a pre-arranged Chapter 11 plan of reorganization (the Restructuring Plan).

Restructuring Support and Lock-Up Agreement

General

In anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors, Texas Holdings and its general partner Texas Energy Future Capital Holdings LLC (TEF and, together with Texas Holdings, the Consenting Interest Holders) and the Consenting Creditors entered into the Restructuring Support and Lock-Up Agreement in order to effect an agreed upon restructuring of the Debtors through the Restructuring Plan.

Pursuant to the Restructuring Support and Lock-Up Agreement, the Consenting Interest Holders and Consenting Creditors agreed, subject to the terms and conditions contained in the Restructuring Support and Lock-Up Agreement, to support the Debtors’ proposed financial restructuring (the Restructuring Transactions), and further agreed to limit certain transfers of any ownership (including any beneficial ownership) in the equity interests of or claims held against the Debtors, including any such interests or claims acquired after executing the Restructuring Support and Lock-Up Agreement.

Material Restructuring Terms

The Restructuring Support and Lock-Up Agreement along with the accompanying term sheet sets forth the material terms of the Restructuring Transactions pursuant to which, in general:

TCEH First Lien Secured Claims

As a result of the Restructuring Transactions, holders of TCEH first lien secured claims will receive, among other things, their pro rata share of (i)100% of the equity of TCEH consummated through a tax-free spin (in accordance with the Private Letter Ruling described below) in connection with TCEH's emergence from bankruptcy (Reorganized TCEH) and (ii) all of the net cash from the proceeds of the issuance of new long-term secured debt of Reorganized TCEH.

TCEH Unsecured Claims

As a result of the Restructuring Transactions, holders of general unsecured claims against EFCH, TCEH and its subsidiaries (including TCEH first lien deficiency claims, TCEH second lien claims and TCEH unsecured note claims) will receive their pro rata share of the unencumbered assets of TCEH.

2

EFIH First Lien Settlement

Certain holders of EFIH 6.875% Notes and EFIH 10% Notes (such holders, the EFIH First Lien Note Parties) have agreed to voluntary settlements with respect to EFIH’s and EFIH Finance’s obligations under the EFIH First Lien Notes held by the EFIH First Lien Note Parties. Under the terms of the settlement, each EFIH First Lien Note Party has agreed to accept as payment in full of any claims arising out of its EFIH First Lien Notes an amount of loans under the EFIH First Lien DIP Facility equal to the greater of (a) 105% of the principal amount on the EFIH First Lien Notes plus 101% of the accrued and unpaid interest at the non-default rate on such principal (which amount will be deemed to include the original issue discount) and (b) 104% of the principal amount of, plus accrued and unpaid interest at the non-default rate on, the EFIH First Lien Notes, in each case held by such EFIH First Lien Note Party. In addition, in the case of (b) above, each EFIH First Lien Note Party will be entitled to original issue discount paid in accordance with the EFIH First Lien Facility. No EFIH First Lien Note Party will receive any other fees, including commitment fees paid in respect of the EFIH First Lien DIP Facility (such settlement, the EFIH First Lien Settlement).

During the early portion of the Chapter 11 Cases, EFIH expects to:

• solicit agreement to, and participation in, the EFIH First Lien Settlement from holders of the remaining outstanding EFIH First Lien Notes, other than the EFIH First Lien Note Parties (the EFIH First Lien Settlement Solicitation), and

• initiate litigation to obtain entry of an order from the Bankruptcy Court disallowing the claims of holders of EFIH First Lien Notes not a party to the EFIH First Lien Settlement (Non-Settling EFIH First Lien Note Holders) derived from or based upon make-whole or other similar payment provisions under the EFIH First Lien Notes.

Following the completion of the EFIH First Lien Settlement Solicitation, Non-Settling EFIH First Lien Note Holders will receive their pro rata share of cash from the proceeds of the EFIH First Lien DIP Facility in an amount equal to the principal plus accrued and unpaid interest through the closing of the EFIH First Lien DIP Facility, at the non-default rate of such holder's claim (not including any premiums, fees, or claims relating to the repayment of the EFIH First Lien Notes)

EFIH Second Lien Settlement

Certain holders of EFIH 11% Notes and EFIH 11.75% Notes (such holders, the EFIH Second Lien Note Parties) have agreed to voluntary settlements with respect to EFIH's and EFIH Finance's obligations under the EFIH Second Lien Notes held by the EFIH Second Lien Note Parties. Under the terms of the settlement, each EFIH Second Lien Note Party has agreed to accept as payment in full of any claims arising out of its EFIH Second Lien Notes, its pro rata share of an amount in cash equal to (i) 100% of the principal of, plus accrued but unpaid interest at the non-default rate on, EFIH Second Lien Notes held by such EFIH Second Lien Party plus (ii) 50% of the aggregate amount of any claim derived from or based upon make-whole or other similar provisions under the EFIH 11% Notes or EFIH 11.75% Notes (such settlement, the EFIH Second Lien Settlement).

As part of the EFIH Second Lien Settlement, a significant EFIH Second Lien Note Party, but not other EFIH Second Lien Note Parties, will have the right to receive up to $500 million of its payment under the EFIH Second Lien Settlement in the form of loans under the EFIH First Lien DIP Facility. In addition, such EFIH Second Lien Note Party will be entitled to its pro rata share of interest and original issue discount paid in respect of the EFIH First Lien DIP Facility and a 1.75% commitment fee.

During the early portion of the Chapter 11 Cases, EFIH expects to:

• solicit agreement to, and participation in, the EFIH Second Lien Settlement from holders of the remaining outstanding EFIH Second Lien Notes, other than the EFIH Second Lien Note Parties (the EFIH Second Lien Settlement Solicitation), and

• initiate litigation to obtain entry of an order from the Bankruptcy Court disallowing the claims of holders of EFIH Second Lien Notes not a party to the EFIH Second Lien Settlement (Non-Settling EFIH Second Lien Note Holders) derived from or based upon make-whole or other similar payment provisions under the EFIH Second Lien Notes.

Following the completion of the EFIH Second Lien Settlement Solicitation, Non-Settling EFIH Second Lien Note Holders will receive their pro rata share of cash from the proceeds of the EFIH Second Lien DIP Facility (as described below) in an amount equal to the principal plus accrued and unpaid interest through the closing of the EFIH Second Lien DIP Facility, at the non-default rate of such holder’s claim (not including any premiums, fees, or claims relating to the repayment of the EFIH Second Lien Notes).

3

EFIH Second Lien DIP Notes Offering

During the early portion of the Chapter 11 Cases, EFIH and EFIH Finance expect to offer (the EFIH Second Lien DIP Notes Offering) to all holders as of a specified record date of EFIH Unsecured Notes the right to purchase up to its pro rata percentage of $1.73 billion aggregate principal amount of 8% Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche A-1 Notes due 2016 (EFIH Second Lien DIP Tranche A-1 Notes). Concurrently with the EFIH Second Lien DIP Notes Offering, EFIH and EFIH Finance will also offer (the concurrent offering) to a significant EFIH Second Lien Note Party the right to purchase up to $170 million aggregate principal amount of 8% Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche A-3 Notes due 2016 (EFIH Second Lien DIP Tranche A-3 Notes). If such significant EFIH Second Lien Note Party elects to participate in the offering, EFIH will pay such party $11.3 million. To the extent the Backstop Parties are required to purchase any notes in the offering pursuant to the terms of the Commitment Letter (as described below), such notes will be 8% Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche A-2 Notes due 2016 (EFIH Second Lien DIP Tranche A-2 Notes). The EFIH Second Lien DIP Tranche A-1 Notes, the EFIH Second Lien DIP Tranche A-2 Notes and the EFIH Second Lien DIP Tranche A-3 Notes are expected to have the same terms and conditions (other than (i) the ability to trade as a single tranche, (ii) the EFIH Second Lien Tranche A-1 Notes will trade together with the corresponding EFIH Unsecured Notes and (iii) the EFIH Second Lien Tranche A-2 Notes and EFIH Second Lien Tranche A-3 Notes will not trade together with any other notes).

Backstop Commitment

In connection with the execution of the Restructuring Support and Lock-Up Agreement, certain holders of the EFIH Unsecured Notes (the Backstop Parties) have entered into a commitment letter with EFH Corp. and EFIH, dated April 29, 2014 (the Commitment Letter), pursuant to which such holders have committed, severally and not jointly, up to $2.0 billion in available funds (the Backstop Commitment) to purchase EFIH Second Lien DIP Notes. Any EFIH Second Lien DIP Notes not sold in the EFIH Second Lien DIP Notes Offering and the concurrent offering (unpurchased notes) will be purchased by the Backstop Parties, pro rata in proportion to their respective share of the Backstop Commitment. If any Backstop Party fails to satisfy its obligation to purchase its pro rata share of the unpurchased notes, the other Backstop Parties would have the right, but not the obligation, to purchase such unpurchased notes. The obligations under the Commitment Letter are not subject to the approval of the Oncor TSA Amendment (as described below) by the Bankruptcy Court.

Under the Commitment Letter and in consideration of the Backstop Commitment, EFIH agreed to pay the Backstop Parties a commitment fee consisting of (i) a $10 million execution fee that was paid to the Backstop Parties concurrently with the execution of the Commitment Letter, (ii) a $10 million approval fee to be paid within five days of the issuance of an order by the Bankruptcy Court authorizing the EFIH First Lien Settlement, the EFIH Second Lien Settlement, and the performance by EFH Corp. and EFIH under the Commitment Letter, (iii) a $20 million funding fee to be paid concurrently with the consummation of the EFIH Second Lien DIP Notes Offering to holders of EFIH Unsecured Notes and the concurrent offering and (iv) a fee equal to $100 million payable in the form of Non-Interest Bearing Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche B Notes due 2016 (EFIH Second Lien DIP Tranche B Notes and, together with the EFIH Second Lien DIP Tranche A-1 Notes, the EFIH Second Lien DIP Tranche A-2 Notes and the EFIH Second Lien DIP Tranche A-3 Notes, the EFIH Second Lien DIP Notes) to be paid concurrently with the consummation of the EFIH Second Lien DIP Notes Offering to holders of EFIH Unsecured Notes and the concurrent offering. Other than with respect to the requirement not to pay interest and related mechanics and not trading together with any other debt, the EFIH Second Lien DIP Tranche B Notes are expected to have the same terms and conditions as the EFIH Second Lien DIP Tranche A-1 Notes, the EFIH Second Lien DIP Tranche A-2 Notes and the EFIH Second Lien DIP Tranche A-3 Notes.

In the event the EFIH Second Lien DIP Notes are repaid in cash prior to the effective date of the plan of reorganization (Effective Date), EFIH agreed to pay the Backstop Parties a termination fee of $380 million. In addition, if the EFIH Second Lien DIP Notes Offering is not consummated at the option of EFIH, EFIH agreed to pay the Backstop Parties a break-up fee of $60 million.

EFIH Unsecured Claims and EFH Corp. Unsecured Claims

On the Effective Date, all of the EFIH Unsecured Notes and EFH Corp. Unsecured Notes will be canceled. In full satisfaction of the claims under the EFIH Unsecured Notes and the EFH Corp. Unsecured Notes, (i) each holder of EFIH Unsecured Notes will receive its pro rata share of 98.0% of the equity interests of newly reorganized EFH Corp. (Reorganized EFH Corp.) (subject to dilution by the Equity Conversion as described below) and (ii) each holder of EFH Corp. Unsecured Notes will receive its pro rata share of 1.0% of the equity interests of Reorganized EFH Corp. (subject to dilution by the Equity Conversion).

4

Holders of the EFH Corp. Unsecured Notes will also receive on the Effective Date their pro rata share of either (A) if the Oncor TSA Amendment (described below) has then been approved, (1) $55 million in cash from EFIH, provided, however, that if the Oncor tax payments received by EFIH under the Oncor TSA Amendment through the Effective Date are less than 80% of projected amounts, the $55 million payment will be reduced on a dollar for dollar basis by the amount of such shortfall, and (2) cash on hand at EFH Corp. (not including the settlement payment in clause (1) hereof); or (B) if the Oncor TSA Amendment has not then been approved, all assets of EFH Corp., including cash on hand but excluding the equity interests in EFIH.

EFH Corp. Equity Interests

On the Effective Date, all of the equity interests in EFH Corp. (EFH Corp. Interests) will be canceled. In full satisfaction of the claims under the EFH Corp. Interests, each holder of EFH Corp. Interests will receive its pro rata share of 1.0% of the equity interests of Reorganized EFH Corp. (subject to dilution by the Equity Conversion).

Equity Conversion

On the Effective Date, the EFIH Second Lien DIP Notes will automatically convert (Equity Conversion) on a pro rata basis into approximately 64% of the equity interests of Reorganized EFH Corp.

Oncor TSA Amendment

The Restructuring Support and Lock-Up Agreement provides that the Debtors will request authority from the Bankruptcy Court to amend, or otherwise assign the right to payments under, the Oncor Tax Sharing Agreement (the Oncor TSA Amendment) to provide that any payment required to be made to EFH Corp. under the Oncor Tax Sharing Agreement after March 31, 2014, will instead be made to EFIH. Any tax payments received by EFH Corp. before the Bankruptcy Court enters or denies an order authorizing the Oncor TSA Amendment will be deposited by EFH Corp. into a segregated account until the earlier of (i) the date the Bankruptcy Court enters the order authorizing the Oncor TSA Amendment, in which case such amounts will be remitted to EFIH, or (ii) the date the Bankruptcy Court denies authorization of the Oncor TSA Amendment, in which case such amounts will be remitted to EFH Corp.

The Oncor TSA Amendment will automatically terminate and be of no further force and effect in the event that the Commitment Letter is terminated by the Backstop Parties; provided, however, that any amounts that were paid to EFIH in accordance with the Oncor TSA Amendment before its termination will be retained by EFIH if the Commitment Letter terminates or the EFIH Second Lien DIP Facility is not fully funded in accordance with its terms (i.e., except as a result of a breach by the Backstop Parties). Neither EFH Corp. nor EFIH will have the right to terminate or modify the Oncor TSA Amendment during the Chapter 11 Cases if the EFIH Second Lien DIP Facility is consummated.

If the Bankruptcy Court has not approved the Oncor TSA Amendment within 90 days after the Petition Date, the interest rate on the EFIH Second Lien DIP Tranche A-1 Notes, EFIH Second Lien DIP Tranche A-2 Notes and EFIH Second Lien DIP Tranche A-3 Notes will increase by 4.0% with such additional interest to be paid-in-kind (compounded quarterly) until such approval is received from the Bankruptcy Court. If the Bankruptcy Court has not approved the Oncor TSA Amendment by May 1, 2015, each holder of EFIH Second Lien DIP Notes will receive additional EFIH Second Lien DIP Notes equal to 10.0% of the amount of EFIH Second Lien DIP Notes held by such holder.

Private Letter Ruling

The Restructuring Support and Lock-Up Agreement provides that EFH Corp. will file a request with the IRS for a private letter ruling (Private Letter Ruling) that, among other things, will provide (a) that (i) the transfer by TCEH of all of its assets and its ordinary course operating liabilities to Reorganized TCEH, (ii) the transfer by the Debtors to Reorganized TCEH of certain operating assets and liabilities that are reasonably necessary to the operation of Reorganized TCEH and (iii) the distribution by TCEH of (A) the equity it holds in Reorganized TCEH and (B) the cash proceeds TCEH receives from Reorganized TCEH to the holders of TCEH First Lien Claims will qualify as a "reorganization" within the meaning of Sections 368(a)(1)(G) , 355 and 356 of the Code and (b) for certain other rulings under Sections 368(a)(1)(G) and 355 of the Code.

5

Conditions Precedent to Restructuring Transactions

The Restructuring Support and Lock-Up Agreement provides that the consummation of the Restructuring Transactions is subject to the satisfaction or waiver (if applicable) of various conditions, including, among other things:

• the consummation of the debtor-in-possession financing transactions and settlements described above;

• holders of certain EFH Unsecured Notes shall have received not less than 37.15% in value for their respective claims under the plan of reorganization;

• immediately following the distribution by TCEH described above under the heading "Private Letter Ruling", the aggregate tax basis, for federal income tax purposes, of the assets held by Reorganized TCEH will be equal to a specified minimum amount of aggregate tax basis, and the step-up in aggregate tax basis will be no less than $2.1 billion;

• the receipt of requisite regulatory approvals;

• the receipt of the Private Letter Ruling, and

• the receipt of requisite orders from the Bankruptcy Court.

Termination

The Restructuring Support and Lock-Up Agreement may be terminated upon the occurrence and continuation of certain events described in the Restructuring Support and Lock-Up Agreement.

For additional discussion of the Bankruptcy Filing and its effects, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance – Filing under Chapter 11 of the United States Bankruptcy Code" and Item 1A, "Risk Factors – Risks Related to Filing under Chapter 11 of the United States Bankruptcy Code." See Note 10 to Financial Statements for discussion of the DIP Facilities.

EFCH's Market

We operate primarily within the ERCOT market. This market represents approximately 85% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the Independent System Operator of the interconnected transmission grid for those systems. ERCOT's membership consists of more than 300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, investor-owned utilities, REPs and consumers.

The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure adequacy and reliability of power supply across Texas' main interconnected transmission grid. ERCOT is responsible for scheduling power on the grid and maintaining reliable operations of the electricity supply system in the market. Its responsibilities include centralized dispatch of the power pool and ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. ERCOT also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

Installed generation capacity in the ERCOT market for the year 2013 totaled approximately 84,500 MW, including approximately 2,000 MW mothballed (idled) capacity and more than 11,500 MW of wind and other resources that may not be available coincident with system need. Texas has more installed wind generation capacity than any other state in the US. In 2013, ERCOT's hourly demand peaked at 67,245 MW as compared to peak demand of 66,548 MW in 2012. Of ERCOT's total installed capacity, approximately 59% is natural gas fueled generation, approximately 28% is lignite/coal and nuclear fueled generation and approximately 13% is wind and other renewable resources.

The ERCOT market has limited interconnections to other markets in the US and Mexico, which currently limits potential imports into and exports out of the ERCOT market to 1,106 MW of generation capacity (or approximately 2% of peak demand). In addition, wholesale transactions within the ERCOT market are generally not subject to regulation by the FERC.

6

Natural gas fueled generation is the predominant electricity capacity resource (approximately 59%) in the ERCOT market and accounted for approximately 41% of the electricity produced in the ERCOT market in 2013. Because of the significant amount of natural gas fueled capacity and the ability of such facilities to more readily increase or decrease production when compared to nuclear and lignite/coal fueled generation, marginal demand for electricity in ERCOT is usually met by natural gas fueled facilities. As a result, wholesale electricity prices in ERCOT have generally moved with natural gas prices.

EFCH's Strategies

Our business focuses operations on key safety, reliability, economic and environmental drivers such as optimizing and developing our generation fleet to safely provide reliable electricity supply in a cost-effective manner and in consideration of environmental impacts, hedging our commodity price and volume exposure and providing high quality service and innovative energy products to retail and wholesale customers.

Other elements of our strategies include:

• Increase value from existing business lines. We strive for top-tier performance across our operations in terms of safety, reliability, cost and customer service. In establishing strategic objectives, we incorporate the following core operating principles:

• Safety: Placing the safety of communities, customers and employees first;

• Environmental Stewardship: Continuing to make strategic and operational improvements that lead to cleaner air, land and water;

• Customer Focus: Delivering products and superior service to help customers more effectively manage their use of electricity;

• Community Focus: Being an integral part of the communities in which we live, work and serve;

• Operational Excellence: Incorporating continuous improvement and financial discipline in all aspects of the business to achieve top-tier results that maximize the value of the company for stakeholders, including operating world-class facilities that produce and deliver safe and dependable electricity at affordable prices, and

• Performance-Driven Culture: Fostering a strong values- and performance-based culture designed to attract, develop and retain best-in-class talent.

• Drive and support growth of the ERCOT market. We expect to pursue growth opportunities across our existing business lines, including:

• Pursuing generation development opportunities to help meet ERCOT's growing electricity needs over the longer term from a diverse range of energy sources such as natural gas, nuclear and renewable energy.

• Working with ERCOT and other market participants to develop policies and protocols that provide appropriate pricing signals that incent the development of new generation to meet growing electricity demand in the ERCOT market.

• Profitably increasing the number of retail customers served throughout the competitive ERCOT market areas by delivering superior value through high quality customer service and innovative energy products, including leading energy efficiency initiatives and service offerings.

• Manage exposure to wholesale electricity price volatility. We actively manage our exposure to wholesale electricity prices in ERCOT through contracts for physical delivery of electricity, exchange traded and over-the-counter financial contracts, ERCOT day-ahead market transactions and bilateral contracts with other wholesale market participants, including other generators and end-use customers. These hedging activities include shorter-term agreements, longer-term electricity sales contracts and forward sales of natural gas. The historical relationship between natural gas prices and wholesale electricity prices in the ERCOT market has provided us an opportunity to manage our exposure to variability of wholesale electricity prices through natural gas hedging activities. For discussion of natural gas hedging activities, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program."

7

• Pursue new environmental initiatives. We are committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce our impact on the environment. EFH Corp.'s Sustainable Energy Advisory Board advises us in our pursuit of technology development opportunities that reduce our impact on the environment while balancing the need to help address the energy requirements of Texas. The Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: environmental conservation, labor unions, customers, economic development in Texas and technology/reliability standards. See "Environmental Regulations and Related Considerations" below for discussion of actions we are taking to reduce emissions from our generation facilities and our investments in energy efficiency and related initiatives.

Seasonality

Our revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.

Business Organization

Key TCEH activities, including management of risks related to commodity price and availability, as well as electricity sourcing for our retail and wholesale customers, are performed on an integrated basis. This integration strategy, the execution of which is discussed below in describing the activities of our wholesale operations, is a key consideration in our operating segment determination. For purposes of market identity and operational accountability, our operations are grouped and identified as Luminant, which is engaged in electricity generation and wholesale markets activities, and TXU Energy, which is engaged in retail electricity sales activities. These activities are conducted through separate legal entities.

Luminant — Luminant's existing electricity production fleet consists of 40 generation units in Texas, all of which are owned, with total installed nameplate generating capacity as shown in the table below:

Fuel Type	Installed Nameplate Capacity (MW)	Number of Plant Sites	Number of Units
Nuclear	2,300	1	2
Lignite/coal	8,017	5	12
Natural gas (a)	5,110	8	26
Total	15,427	14	40

___________

(a) Includes 1,655 MW representing four units mothballed and not currently available for dispatch. See "Natural Gas Fueled Generation Operations" below.

The generation units are located primarily on owned land. Nuclear and lignite/coal fueled units are generally scheduled to run at capacity except for periods of scheduled maintenance activities; however, we reduce production from certain lignite/coal fueled generation units, referred to as economic backdown, during periods when wholesale electricity market prices are less than the unit's variable production costs. In addition, we have implemented seasonal suspensions of operations of certain lignite/coal fueled generation units because of the low wholesale electricity price environment. The natural gas fueled generation units supplement the nuclear and lignite/coal fueled generation capacity in meeting consumption in peak demand periods as production from certain of these units, particularly combustion-turbine units, can be more readily ramped up or down as demand warrants.

Nuclear Generation Operations — Luminant operates two nuclear generation units at the Comanche Peak plant site, each of which is designed for a capacity of 1,150 MW. Comanche Peak's Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, which will occur in 2014 and last occurred in 2011. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last three years the refueling outage period per unit has ranged from 22 to 29 days. The Comanche Peak facility operated at a capacity factor of 101.7%, 98.5% and 95.7% in 2013, 2012 and 2011, respectively.

8

Luminant has contracts in place for all of its uranium and nuclear fuel conversion, enrichment and fabrication services for 2014. For the period of 2015 through 2019, Luminant has contracts in place for the acquisition of approximately 66% of its uranium requirements and 81% of its nuclear fuel conversion services requirements. In addition, Luminant has contracts in place for all of its nuclear fuel enrichment services through 2019, as well as all of its nuclear fuel fabrication services through 2018. Luminant does not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion and enrichment services in the foreseeable future.

The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily through the use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear fuel storage capability is sufficient for the foreseeable future.

The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date of commercial operation. Therefore, assuming that Luminant receives 20-year license extensions, similar to what has been granted by the NRC to several other commercial generation reactors over the past several years, decommissioning activities would be scheduled to begin in 2050 for Comanche Peak Unit 1 and 2053 for Unit 2 and common facilities. Decommissioning costs will be paid from a decommissioning trust that, pursuant to Texas law, is intended to be fully funded from Oncor's customers through an ongoing delivery surcharge. (See Note 18 to Financial Statements for discussion of the decommissioning trust fund.) Under applicable law, the Bankruptcy Filing is not expected to have any effect on the collection of such surcharge or the ongoing viability of the decommissioning trust.

Nuclear insurance provisions are discussed in Note 11 to Financial Statements.

Nuclear Generation Development — In 2008, we filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at our existing Comanche Peak nuclear plant site. In connection with the filing of the application, in 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company LLC (CPNPC), to further the development of the two new nuclear generation units using MHI's US-Advanced Pressurized Water Reactor (US-APWR) technology. The TCEH subsidiary owns an 88% interest in CPNPC, and an MHI subsidiary owns a 12% interest.

In the fourth quarter 2013, MHI notified us and the NRC of its plans to refocus MHI's US resources on the restart of 24 nuclear reactors in Japan and thus reduce its support of review activities related to the NRC's Design Certification of MHI's US-APWR technology. As a result, Luminant has notified the NRC of its intent to suspend all reviews associated with the combined operating license application by March 31, 2014. Luminant does not intend to withdraw the license application at this time. MHI expressed to the NRC its continuing commitment to obtaining an NRC design certification for its technology. Luminant has filed a loan guarantee application with the DOE for financing the proposed units prior to commencement of construction and expects to continue to update the application in accordance with the loan solicitation guidelines. See Note 8 to Financial Statements for discussion of impairment of the joint venture's assets.

Lignite/Coal Fueled Generation Operations — Luminant's lignite/coal fueled generation fleet capacity totals 8,017 MW and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (2 units) and Sandow (2 units) plant sites. Maintenance outages at these units are scheduled during seasonal off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit averaged 40 days in duration. Luminant's lignite/coal fueled generation fleet operated at a capacity factor of 74.1% in 2013, 70.0% in 2012 and 83.5% in 2011. This performance reflects increased economic backdown of the units and the seasonal suspension of operations of certain units as discussed above.

Luminant is the seventh-largest coal miner in the US and the largest lignite coal miner in Texas. Luminant's mining activity supports generation at its lignite/coal fueled units. Approximately 68% of the fuel used at Luminant's lignite/coal fueled generation units in 2013 was supplied from surface-minable lignite reserves dedicated to our generation plants, which are located adjacent to the reserves. Luminant owns or has under lease an estimated 715 million tons of lignite reserves dedicated to our generation plants, including an undivided interest in approximately 175 million tons of lignite reserves that provide fuel for the Sandow facility. Luminant also owns or has under lease approximately 85 million tons of reserves not currently dedicated to specific generation plants. In 2013, Luminant recovered approximately 29 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipment to remove the overburden and recover the lignite.

Luminant's lignite mining operations include extensive reclamation activities that return the land to productive uses such as wildlife habitats, commercial timberland and pasture land. In 2013, Luminant reclaimed more than 2,300 acres of land. In addition, Luminant planted 1.5 million trees in 2013, the majority of which were part of the reclamation effort.

9

Luminant meets its fuel requirements for its Big Brown, Monticello and Martin Lake generation units by blending lignite with western coal from the Powder River Basin in Wyoming. The coal is purchased from multiple suppliers under contracts of various lengths and is transported from the Powder River Basin to Luminant's generation plants by railcar. Based on its current planned usage, Luminant believes that it has sufficient lignite reserves for the foreseeable future and has contracted the majority of its anticipated western coal requirements and all of the related transportation through 2014.

See "Environmental Regulations and Related Considerations – Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions" for discussion of potential effects of recent EPA rules on future operations of our generation units.

Natural Gas Fueled Generation Operations — Luminant owns a fleet of 26 natural gas fueled generation units, of which 11 are steam generation units totaling 4,135 MW of capacity and 15 are combustion turbine generation units totaling 975 MW of capacity. Of the steam generation units, four units representing 1,655 MW of capacity are currently mothballed (idled). The natural gas fueled units predominantly serve as peaking units that can be ramped up or down to balance electricity supply and demand.

Natural Gas Fueled Generation Development — In August 2013, the TCEQ granted air permits to Luminant to build two natural gas combustion turbine generation units totaling 420 MW to 460 MW at its existing DeCordova generation facility. In February 2014, the TCEQ granted air permits to Luminant to build two natural gas combustion turbine generation units totaling 420 MW to 460 MW at its existing Tradinghouse generation facility. In January 2014, Luminant filed an air permit application with the TCEQ to build a combined cycle natural gas turbine generation unit totaling 730 MW to 810 MW at its existing Eagle Mountain generation facility. In February 2014, Luminant filed an air permit application with the TCEQ to build two natural gas combustion turbine generation units totaling 420 MW to 460 MW at its existing Lake Creek 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. See "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance – Recent PUCT/ERCOT Actions" for discussion of recent actions by the PUCT and ERCOT related to generation resource adequacy.

Wholesale Operations — Luminant's wholesale operations play a pivotal role in our business by optimally dispatching the generation fleet, procuring fuels for the generation fleet, sourcing all of TXU Energy's electricity requirements and managing commodity risk for the retail and wholesale electricity sales operations.

Our electricity price exposure is managed across the complementary generation, wholesale and retail operations on an integrated portfolio basis. Under this approach, Luminant's wholesale operations manage the risks of imbalances between generation supply and sales load, as well as exposures to natural gas price movements and market heat rate changes (variations in the relationships between natural gas prices and wholesale electricity prices), through wholesale market activities that include physical purchases and sales and transacting in financial instruments.

Luminant's wholesale operations provide TXU Energy and other retail and wholesale customers with electricity-related services to meet their demands and the operating requirements of ERCOT. In consideration of electricity generation resource availability and consumer demand levels that can be highly variable, as well as opportunities to meet longer-term objectives of larger wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-term forward electricity purchase and sales agreements. Luminant is also one of the largest purchasers of wind-generated electricity in Texas and the US with approximately 700 MW of existing wind power under contract.

Fuel price exposure, primarily relating to Powder River Basin coal, natural gas, uranium and fuel oil, as well as fuel transportation costs, is managed primarily through short- and long-term contracts for physical delivery of fuel as well as financial contracts.

In its hedging activities, Luminant enters into contracts for the physical delivery of electricity and fuel commodities, exchange traded and over-the-counter financial contracts and bilateral contracts with other wholesale market participants, including generators and end-use customers. A significant element of these activities involves natural gas hedging, described above under "EFCH's Strategies," designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, principally utilizing natural gas-related financial instruments.

10

The wholesale operations also dispatch Luminant's available generation capacity. These dispatching activities include economic backdown of lignite/coal fueled units and ramping up and down of natural gas fueled units as market conditions warrant. Luminant's dispatching activities are performed on a centrally managed real-time basis optimizing operational activities across the fleet and interfacing with various wholesale market channels. In addition, the wholesale operations manage the fuel procurement requirements for Luminant's fossil fuel and nuclear generation facilities.

Luminant's wholesale operations include electricity and natural gas trading and third-party energy management activities. Natural gas transactions include direct purchases from natural gas producers, transportation agreements, storage leases and commercial retail sales. Luminant currently manages approximately 10.5 billion cubic feet of natural gas storage capacity.

Luminant's wholesale operations manage exposure to wholesale commodity and credit-related risk within established transactional risk management policies, limits and controls. These policies, limits and controls have been structured so that they are practical in application and consistent with stated business objectives. Risk management processes include capturing transaction data, monitoring transaction types and notional limits, reviewing and managing credit risk, performing and validating valuations and reporting exposures on a daily basis using risk management information systems designed to support a large transactional portfolio. A risk management forum meets regularly to ensure that business practices comply with approved transactional limits, commodities, instruments, exchanges and markets. Transactional risks are monitored to ensure limits comply with the established risk policy. Risk management also includes a disciplinary program to address any violations of the risk management policies and periodic reviews of these policies to ensure they are responsive to changing market and business conditions.

TXU Energy — TXU Energy serves 1.7 million residential and commercial retail electricity customers in Texas. Approximately 69% of our reported retail revenues in 2013 represented sales to residential customers. Texas is one of the fastest growing states in the nation with a diverse economy and, as a result, has attracted a number of competitors into the retail electricity market; consequently, competition is robust. TXU Energy, as an active participant in this competitive market, provides retail electric service to all areas of the ERCOT market now open to competition, including the Dallas/Fort Worth, Houston, Corpus Christi, and lower Rio Grande Valley areas of Texas and holds an approximately 26% and 19% share of the residential and business customers in ERCOT, respectively. TXU Energy competitively markets its services to add new customers and retain its existing customer base, as well as opportunistically acquire customers from other REPs. There are more than 100 REPs certified to compete within the ERCOT region. Based upon data published by the PUCT, at September 30, 2013, approximately 62% of residential customers and 69% of small commercial customers in competitive areas of ERCOT are served by REPs not affiliated with the pre-competition utility. TXU Energy is a REP affiliated with a pre-competition utility, considering EFH Corp.'s history prior to the deregulation of the Texas market.

TXU Energy's strategy focuses on providing its customers with high quality customer service and creating new products and services to meet customer needs; accordingly, customer care enhancements are implemented on an ongoing basis to continually improve customer satisfaction. TXU Energy offers a wide range of residential products to meet varying customer needs and has invested more than $100 million in energy efficiency initiatives since the Merger as part of a program to offer customers a broad set of innovative energy products and services.

Regulation — Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation units. NRC regulations govern the granting of licenses for the construction and operation of nuclear fueled generation facilities and subject such facilities to continuing review and regulation. In addition, Luminant is subject to the jurisdiction of the RCT's oversight of its lignite mining and reclamation operations.

Luminant is also subject to the jurisdiction of the PUCT's oversight of the competitive ERCOT wholesale electricity market. PUCT rules establish a framework for and robust oversight of wholesale power pricing and market behavior. Luminant is also subject to the requirements of the ERCOT Nodal Protocols as well as reliability standards adopted and enforced by the TRE and the NERC, including NERC critical infrastructure protection (CIP) standards. Luminant is also subject to the authority of the CFTC as it continues to implement rules and provide oversight vested in the agency by the Wall Street Reform and Consumer Protection Act of 2010, particularly Title VII, which deals with over-the-counter derivative markets.

TXU Energy is a licensed REP under the Texas Electric Choice Act and is subject to the jurisdiction of the PUCT with respect to provision of electricity service in ERCOT. PUCT rules govern the granting of licenses for REPs, including oversight but not setting of retail prices. TXU Energy is also subject to the requirements of the ERCOT Nodal Protocols as well as reliability standards adopted and enforced by the TRE and the NERC, including NERC CIP standards.

11

Environmental Regulations and Related Considerations

Global Climate Change

Background — There is a debate nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as CO₂, might contribute to global climate change. GHG emissions from the combustion of fossil fuels, primarily by our lignite/coal fueled generation units, represent the substantial majority of our total GHG emissions. CO₂, methane and nitrous oxide are emitted in this combustion process, with CO₂ representing the largest portion of these GHG emissions. We estimate that our generation facilities produced 59.5 million short tons of CO₂in 2013. Other aspects of our operations result in emissions of GHGs including, among other things, coal piles at our generation plants, refrigerant from our chilling and cooling equipment, fossil fuel combustion in our motor vehicles and electricity usage at our facilities and headquarters. Our financial condition, liquidity or results of operations could be materially affected by the enactment of statutes or regulations that mandate a reduction in GHG emissions or that impose financial penalties, costs or taxes on those that produce GHG emissions. See Item 1A, "Risk Factors" for additional discussion of risks posed to us regarding global climate change regulation.

Global Climate Change Legislation — Over the past few years, proposals have been debated in the US Congress or advocated by the Obama Administration that were intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade). In addition to potential federal legislation to regulate GHG emissions, the US Congress has also considered, and may in the future consider, other legislation that could result in the reduction of GHG emissions, such as the establishment of renewable or clean energy portfolio standards.

Through our own evaluation and working in tandem with other companies and industry trade associations, we have in the past engaged in the development of an integrated package of recommendations for the federal government to address the global climate change issue through federal legislation. We have also created a Sustainable Energy Advisory Board that advises us on technology development opportunities that reduce the effects of our operations on the environment while balancing the need to address the energy requirements of Texas. EFH Corp.'s Sustainable Energy Advisory Board is comprised of individuals representing various interests, including the environment, customers, economic development in Texas and technology/reliability standards. If, despite these efforts, a substantial number of our customers or others refuse to do business with us because of our GHG emissions, it could have a material effect on our results of operations, liquidity and financial condition.

Federal Level — The EPA has taken a number of actions regarding GHG emissions. In September 2009, the EPA issued a final rule requiring the reporting of calendar year GHG emissions from specified large GHG emissions sources in the US. This reporting rule applies to our lignite/coal fueled generation facilities, and we have complied with the requirement since its effective date in 2011. In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment and that emissions from motor vehicles contribute to that endangerment. The EPA's finding required it to begin regulating GHG emissions from motor vehicles, and the EPA ultimately extended regulation of GHG emissions to stationary sources under existing provisions of the federal Clean Air Act. In March 2010, the EPA determined that the Clean Air Act's Prevention of Significant Deterioration (PSD) program permit requirements would apply to newly identified pollutants such as GHGs when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, PSD permitting requirements became applicable to GHG emissions from planned stationary sources or planned modifications to stationary sources that had not been issued a PSD permit by January 2, 2011 - the first date that new motor vehicles were required to meet the new GHG standards. In June 2010, the EPA finalized its so-called "tailoring rule" that established new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources, including our electricity generation facilities. The EPA's tailoring rule defines the threshold of GHG emissions for determining applicability of the Clean Air Act's PSD and Title V permitting programs at levels greater than the emission thresholds contained in the Clean Air Act. In December 2010, in response to the State of Texas's indication that it would not take regulatory action to implement the EPA's tailoring rule, the EPA adopted a rule to take over the issuance of permits for GHG emissions from the TCEQ. The State of Texas challenged that rule and the GHG permitting rules through litigation and has refused to implement the GHG permitting rules issued by the EPA. In June 2012, the D.C. Circuit Court upheld all of the EPA's GHG rules and regulations. The State of Texas has since completed a rulemaking to implement the EPA's GHG permitting rules and will assume responsibility for issuing permits for GHG emissions upon the EPA's approval. A number of members of the US Congress from both parties have introduced legislation to either block or delay EPA regulation of GHGs under the Clean Air Act, and legislative activity in this area in the future is possible. In August 2012, various industry groups and states that challenged the rule filed petitions with the D.C. Circuit Court asking for review by the full D.C. Circuit Court of the panel's decision. In December 2012, the D.C. Circuit Court denied these requests and these parties then petitioned the US Supreme Court to review the D.C. Circuit Court's decision. In October 2013, the US Supreme Court agreed to review the permissibility of EPA's determination that its regulation of GHG emissions from motor vehicles triggered greenhouse gas permitting requirements for stationary sources under the Clean Air Act. We are not a party to that case. Oral arguments in the case were held before the US Supreme Court in February 2014. It is uncertain how (if at all) any decision by the Supreme Court would affect our results of operations, liquidity or financial condition.

12

In September 2013, the EPA released a draft proposed rule for greenhouse gas emission standards from new electricity generation units (EGUs). In January 2014, the EPA withdrew the 2012 proposed rule and issued a revised proposed rule. We are currently reviewing this draft proposed rule; however, at this time it is uncertain how (if at all) the draft 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 generation plants by June 2014 and finalize them by June 2015. We expect the proposed rule to include guidelines that require states to submit to the EPA their compliance implementation 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.

State and Regional Level — There are currently no Texas state regulations in effect concerning GHGs, and there are no regional initiatives concerning GHGs in which the State of Texas is a participant. We oppose state-by-state regulation of GHGs. In October 2009, Public Citizen Inc. filed a lawsuit against the TCEQ and its commissioners seeking to compel the TCEQ to regulate GHG emissions under the Texas Clean Air Act. The Attorney General of Texas filed special exceptions to the Public Citizen pleading, which were granted by the court in May 2010. Public Citizen appealed the court's ruling and the appeal has been fully briefed and submitted to the appellate court for decision on the briefs. In July 2013, Public Citizen withdrew its lawsuit and its appeal was dismissed as moot.

International Level — In December 2009, leaders of developed and developing countries met in Copenhagen under the United Nations Framework Convention on Climate Change (UNFCCC) and issued the Copenhagen Accord. The Copenhagen Accord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissions of GHGs by 2020 and provides for developed countries to fund GHG emission mitigation projects in developing countries. President Obama participated in the development of, and endorsed, the Copenhagen Accord. In January 2010, the US informed the United Nations that it would reduce GHG emissions by 17% from 2005 levels by 2020, contingent on Congress passing climate change legislation. In December 2011, the UNFCCC met in Durban, South Africa and agreed to develop a document with "legal force" to address climate change by 2015, with reductions effective starting in 2020. In December 2012, the UNFCCC met in Doha, Qatar and 194 countries agreed to an extension of the Kyoto Protocol through 2020. The US and China are not participants in the Kyoto Protocol extension. In 2013, the UNFCCC met in Warsaw, Poland and agreed to establish an international mechanism to provide most vulnerable populations better protection against loss and damage, particularly those in less developed countries that have low-lying areas near oceans or on islands that are susceptible to flooding from rising sea levels and/or damage from extreme weather events. The impact, if any, of the Durban agreement or the Kyoto Protocol extension on near-term regulatory or legislative policy cannot yet be determined.

We continue to assess the risks posed by possible future legislative or regulatory changes pertaining to GHG emissions. Because some of the proposals described above are in their formative stages, we are unable to predict the potential effects on our business, results of operations, liquidity or financial condition; however, any such effects could be material. The effect will depend, in large part, on the specific requirements of the legislation or regulation and how much, if any, of the costs are reflected in wholesale electricity prices.

13

EFCH's Voluntary Energy Efficiency, Renewable Energy, and Global Climate Change Efforts — We are actively engaged in, considering, or expect to be actively engaged in, business activities that could result in reduced GHG emissions including:

• Investing in Energy Efficiency and Related Initiatives — Since the Merger, we have invested more than $100 million in energy efficiency and related initiatives, including software- and hardware-based services deployed behind the meter. These programs leverage advanced meter interval data and in-home devices to provide usage and other information and insights to customers, as well as to control energy-consuming equipment. Examples of these initiatives include: the TXU Energy MyEnergy Dashboard^SM, a set of online tools that show residential customers how and when they use electricity, how their electricity use compares to others and their forecast monthly bill; the Brighten^SM Personal Energy Advisor, an online energy audit tool with personalized tips and projects for saving electricity; the Brighten^SM Online Energy Store that provides customers the opportunity to purchase hard-to-find, cost-effective energy-saving products; the Brighten^SM iThermostat, a web-enabled programmable thermostat with a load control feature for cycling air conditioners during times of peak energy demand; TXU Energy Right Time Pricing Products^SM, including TXU Energy Power Hours^SM, TXU Energy Free Nights^SM and TXU Energy Free Weekends^SM time-based electricity rates, and TXU Energy FlexPower^SM prepaid electricity plans, that work in conjunction with advanced metering infrastructure; in-home display devices that enable residential customers to monitor whole-house energy usage and cost in real-time and project month-end bill amounts; rate plans that include electricity from renewable resources; the Brighten^SM Energy Efficiency Assistance Program that delivered products and services, as well as grants through social service agencies, to save energy at participating low income customer homes and apartment complexes; a program to refer customers to energy efficiency contractors, and the provision of rebates to business customers for purchasing new energy efficient equipment for their facilities through the Brighten^SM Greenback Energy Efficiency Rebate Program; the TXU Energy Electricity Usage Report, a weekly email that contains charts and graphs that give customers insight to better control their electricity usage and bills; programs promoting distributed renewable generation to reduce peak summer demand on the grid; and mobile access through smart phones, tablets and other mobile devices with "alert" features that help inform residential customers about recent electricity consumption thresholds.

• Purchasing Electricity from Renewable Sources — We expect to remain a leader in the ERCOT market in providing electricity from renewable sources by purchasing wind power. Our total wind power portfolio is currently approximately 700 MW. We also purchase additional renewable energy credits (RECs) to support discretionary sales of renewable power to our customers;

• Promoting the Use of Solar Power — TXU Energy provides qualified customers, through its TXU Energy SolarLease^SM program, the ability to finance the addition of solar panels to their homes. TXU Energy also purchases surplus renewable distributed generation from qualified customers. In addition, TXU Energy's Solar Academy works with Texas school districts to teach and demonstrate the benefits of solar power;

• Investing in Technology — We continue to evaluate the development and commercialization of cleaner power facility technologies, including technologies that support sequestration and/or reduction of CO₂; incremental renewable sources of electricity, including wind and solar power; energy storage, including advanced battery and compressed air storage, as well as related technologies that seek to lower emissions intensity. Additionally, we continue to explore and participate in opportunities to accelerate the adoption of electric cars and plug-in hybrid electric vehicles that have the potential to reduce overall GHG emissions and are furthering the advance of such vehicles by supporting, and helping develop infrastructure for, networks of charging stations for electric vehicles, and

• Offsetting GHG Emissions by Planting Trees — We are engaged in a number of tree planting programs that offset GHG emissions, resulting in the planting of over 1.5 million trees in 2013. The majority of these trees were planted as part of our mining reclamation efforts but also include TXU Energy's Urban Tree Farm program, which has planted more than 190,000 trees since its inception in 2002.

Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions

Air Transport Regulations: Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule(CSAPR)— In 2005, the EPA issued CAIR, which was intended to implement the provisions of the Clean Air Act Section 110(a)(2)(D)(i)(I) (CAA Section 110) requiring states to reduce emissions of sulfur dioxide (SO₂) and nitrogen oxides (NO_X) that significantly contribute to other states failing to attain or maintain compliance with the EPA's National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone. In 2008, the D.C. Circuit Court invalidated CAIR, but allowed the rule to continue until the EPA issued a final replacement rule.

14

In July 2011, the EPA finalized CSAPR, which was intended to replace CAIR. In September 2011, we filed a petition for review in the 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 December 2011, the D.C. Circuit Court stayed the CSAPR and stated its expectation that the EPA would continue administering CAIR.

During 2012, the EPA made various revisions to CSAPR, including changes to the emissions budgets for our generation assets. Certain of these revisions are the subject of pending litigation that is being held in abeyance pending the US Supreme Court's CSAPR decision.

In August 2012, the D.C. Circuit Court vacated the CSAPR, remanding it to the EPA for further proceedings. As a result, the CSAPR (as revised by the revisions rules) does 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 pending the EPA's further consideration of the rule.

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's decision. The US Supreme Court granted review of the decision and heard oral arguments in December 2013. In April 2014, the US Supreme Court issued its opinion in the CSAPR litigation, reversing the D.C. Circuit Court's decision in which that court vacated CSAPR. The US Supreme Court has remanded the case to the D.C. Circuit Court for further proceedings consistent with its opinion. We are evaluating the decision and cannot predict the timing or outcome of future proceedings related to CSAPR, including any compliance timeframe or the financial effects, if any.

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 and the D.C. Circuit Court heard oral arguments in December 2013. In April 2014, the D.C. Circuit Court issued its ruling upholding the MATS rule and dismissing all challenges. We cannot predict whether the challengers will seek either panel or full court rehearing in the D.C. Circuit, or whether they will seek review by the US Supreme Court. 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. In 2013, the TCEQ approved one-year MATS compliance extensions for our Big Brown and Sandow 4 generation plants.

Regional Haze — SO₂ and NO_X reductions required under the regional haze/visibility rule (or so-called BART rule) apply to electricity generation 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 (Regional Haze SIP) 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 Regional Haze 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 response to a lawsuit by environmental groups, the D.C. Circuit Court issued a consent decree in March 2012 that required the EPA to propose a decision on the Regional Haze SIP by May 2012 and finalize that decision by November 2012. The consent decree requires a Federal Implementation Plan (FIP) for any provisions that EPA disapproves. In June 2012, the EPA finalized the limited disapproval of the Regional Haze SIP, but did not finalize a FIP for Texas, stating that it needed more time to review the Regional Haze SIP. In August 2012, we filed a petition for review in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the EPA's limited disapproval of the 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 above. We cannot predict when or how the D.C. Circuit Court will rule on these petitions. In May 2013, the D.C. Circuit amended the consent decree and extended the dates for the EPA to propose and finalize a decision on the Regional Haze SIP to May and December 2014, respectively. We cannot predict whether or when the EPA will fully approve the Regional Haze SIP or finalize a FIP for Texas regarding regional haze, or a FIP’s impact on our results of operations, liquidity or financial condition. The TCEQ submitted a required five-year status report regarding its Regional Haze SIP to the EPA in March 2014.

15

State Implementation Plan (SIP) Emissions Rules — The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient air quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted SIP rules in May 2007 to deal with eight-hour ozone standards, which required NO_X emission reductions from certain of our peaking natural gas fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposed to further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage; however, in September 2011, the White House directed the EPA to withdraw this reconsideration. In May 2012, the EPA designated nonattainment areas; however, because SIP rules to address attainment of the 2008 standards will not be required until June 2015, we cannot yet predict the impact of this action on our generation facilities. In January 2010, the EPA added a new one-hour nitrogen dioxide (NO₂) National Ambient Air Quality Standard (NAAQS) that may require actions within Texas to reduce emissions. The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required no earlier than January 2021. In June 2010, the EPA adopted a new one-hour SO₂ national ambient air quality standard that may require action within Texas to reduce SO₂ emissions. Based on current monitoring, Texas has recommended to the EPA that no area in Texas is in nonattainment with this one-hour SO₂ standard. The EPA designated 29 areas in 16 states as nonattainment but did not finalize designations for other areas of the country, including Texas. In April 2014, the EPA issued a proposed rule establishing data requirements and deadlines associated with a timeline to expand existing monitoring networks and require modeling to determine attainment status for the other areas. Areas where modeling will be used will be designated in 2017 with attainment demonstrations due in 2019, while areas with expanded or new monitors will be designated in 2020 with SIP revisions due in 2022. In September 2013, four states, including Texas, filed suit to compel the EPA to make SO₂ designations. The Sierra Club and the Natural Resources Defense Council also recently filed a lawsuit seeking to force the EPA to issue designations using air modeling. The Sierra Club has provided modeling that implicates Luminant's coal plants in NAAQS exceedances. We are not a party to this litigation, but we are continuing to monitor the case. The EPA has also initiated efforts to expand near-road monitoring for fine particulates and NO_X, which will increase the risk that an area could be labeled as "nonattainment" as a result of the proximity of the monitors to mobile sources. We cannot predict the impact of the new standards on our business, results of operations or financial condition until the TCEQ adopts (if required) an implementation plan with respect to the standards.

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 Clean Air Act. 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 PCP. 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 Clean Air Act. In March 2012, the Fifth Circuit Court vacated the EPA's disapproval of the Texas standard permit for PCP 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. In February 2014, the Fifth Circuit Court ordered the EPA to issue a final rule on the standard permit for pollution control projects by May 19, 2014. We cannot predict the 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 Clean Air Act. In July 2012, the Fifth Circuit Court denied our challenge and ruled that the EPA's actions were in accordance with the Clean Air Act. 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.

16

Acid Rain Program— The EPA has promulgated Acid Rain Program rules that require fossil fueled plants to have sufficient SO₂ emission allowances and meet certain NO_X emission standards. We believe our generation plants meet these SO₂ allowance requirements and NO_X emission rates.

Installation of Substantial Emissions Control Equipment — Each of our lignite/coal fueled generation facilities is currently equipped with substantial emissions control equipment. All of our lignite/coal fueled generation facilities are equipped with activated carbon injection systems to reduce mercury emissions. Flue gas desulfurization systems designed primarily to reduce SO₂ emissions are installed at Oak Grove Units 1 and 2, Sandow Units 4 and 5, Martin Lake Units 1, 2, and 3, and Monticello Unit 3. Selective catalytic reduction systems designed to reduce NO_X emissions are installed at Oak Grove Units 1 and 2 and Sandow Unit 4. Selective non-catalytic reduction systems designed to reduce NO_X emissions are installed at Sandow Unit 5, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Fabric filter systems designed primarily to reduce particulate matter emissions are installed at Oak Grove Units 1 and 2, Sandow Unit 5, Monticello Units 1 and 2, and Big Brown Units 1 and 2. Electrostatic precipitator systems designed primarily to reduce particulate matter emissions are installed at Sandow Unit 4, Martin Lake Units 1, 2, and 3, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Sandow Unit 5 uses a fluidized bed combustion process that facilitates control of NO_X and SO₂. Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitator systems also assist in reducing mercury and other emissions.

We believe that we hold all required emissions permits for facilities in operation. If the TCEQ adopts implementation plans that require us to install additional emissions controls, or if the EPA adopts more stringent requirements through any of the number of potential rulemaking activities in which it is or may be engaged, we could incur material capital expenditures, higher operating costs and potential production curtailments, resulting in material effects on our results of operations, liquidity and financial condition.

Water

The TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. We believe our facilities are presently in material compliance with applicable state and federal requirements relating to discharge of pollutants into water. We believe we hold all required waste water discharge permits from the TCEQ for facilities in operation and have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals.

Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits from the TCEQ for these activities at our current facilities. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were published by the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuit brought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it was suspending the regulations pending further rulemaking. The US Supreme Court issued a decision in April 2009 reversing the federal court's decision, in part, and finding that the EPA permissibly used cost-benefit analysis in the Section 316(b) regulations. Pursuant to a settlement agreement, the EPA issued for comment proposed new Section 316(b) regulations in March 2011 and was required to adopt the final regulations by April 2014. The EPA informed the federal court in April 2014 that they would not complete the rulemaking by the deadline and expect to issue the final rule in May 2014. In the absence of regulations, the EPA has instructed the states implementing the Section 316(b) program, including Texas, to use their best professional judgment in reviewing applications and issuing permits under Section 316(b). Although the proposed rule does not mandate a certain control technology, it does require site-specific assessments of technology feasibility on a case-by-case basis at the state level. As proposed, compliance with this rule requires assessments and reports six months following implementation of the rule, but allows up to eight full years following promulgation for full compliance. We cannot predict the substance of the final regulations or the impact they may have on our results of operations, liquidity or financial condition.

Radioactive Waste

We currently, and expect to continue to, ship low-level waste material to a disposal facility outside of Texas. Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The State of Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by the President in 1998, and the State of Texas has enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal. The first disposal facility in Texas for such purposes began operations in 2012, and we began shipping some forms of waste material to the facility in 2013. Should existing off-site disposal become unavailable, the low-level waste material can be stored on-site. (See discussion under "Luminant – Nuclear Generation Operations" above.)

17

The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily through the use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear fuel storage capability is sufficient for the foreseeable future.

Solid Waste, Including Fly Ash Associated with Lignite/Coal Fueled Generation

Treatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas Solid Waste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 and the Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable to our facilities. We believe we are in material compliance with all applicable solid waste rules and regulations. In addition, we have registered solid waste disposal sites and have obtained or applied for permits required by such regulations.

In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured, releasing a significant quantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of our impoundments, which are significantly smaller than the TVA's and are inspected on a regular basis. We routinely sample groundwater monitoring wells to ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, in May 2010, the EPA released a proposed rule that considers regulating coal combustion residuals as either a hazardous waste or a non-hazardous waste. In February 2014, a break in a stormwater pipe beneath a coal ash basin at Duke Energy Carolinas' retired Dan River generation plant caused a release of ash basin water and ash into the Dan River in North Carolina. The EPA is under a court-ordered deadline to finalize this rule by December 2014. We are unable to predict the requirements of a final rule; however, the potential cost of compliance could be material.

The EPA issued a notice in December 2009 that it had identified several industries, including the electric power industry, which should be subject to financial responsibility requirements under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) consistent with the risk associated with their production, transportation, treatment, storage or disposal of hazardous substances. The EPA indicated in its notice that it would develop regulations that define the scope of those financial responsibility requirements. We do not know the scope of these requirements, nor are we able to estimate the potential cost, which could be material, of complying with any such new requirements.

Environmental Capital Expenditures

Capital expenditures for our environmental projects totaled $93 million in 2013 and are expected to total approximately $75 million in 2014 for environmental control equipment to comply with regulatory requirements. From 2010 through 2013, our environmental capital expenditures totaled more than $600 million, and additional such expenditures are expected to total nearly $450 million from 2014 through 2020 to comply with the MATS rule as well as other EPA regulations, including maintenance of existing equipment.The total expenditure for environmental capital will ultimately depend on the evolution of pending or future regulatory requirements. Our current plan includes the ongoing use of lignite coal as part of the fuel mix at all of our coal facilities, in varying proportions that reflect the economically available fuel supply as well as the configuration of environmental control equipment for each unit.

18

Item 1A.    RISK FACTORS

Important factors, in addition to others specifically addressed in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," that could have a material impact on our operations, liquidity, financial results and financial condition, or could cause our actual results or outcomes to differ materially from any projected outcome contained in any forward-looking statement in this report, are described below. There may be further risks and uncertainties that are not currently known or that are not currently believed to be material that may adversely affect our performance or financial condition in the future.

Our major risks fall primarily into the following categories:

• Risks Related to Filing under Chapter 11 of the United States Bankruptcy Code. Our capital structure will likely be significantly altered under any Chapter 11 plan confirmed by the Bankruptcy Court, and there can be no assurances regarding the amount of any distribution holders of claims against, or equity interests in, the Debtors ultimately will receive with respect to their claims or equity interests. In addition to material and significant expense, the Chapter 11 Cases subject us to a variety of material risks, including: a material decrease in the number of counterparties that are willing to engage in commodity related hedging transactions with us and a significant increase in the amount of collateral required to engage in any such transactions; a loss of, or a disruption in, the materials or services received from, suppliers, contractors or service providers; a loss of wholesale and retail electric customers and a tarnishing of the TXU Energy brand; retention of employees; management distraction; limitations on our ability to operate our business and to adjust to changing market and industry conditions during the pendency of the Chapter 11 Cases; litigation and/or claims asserted by creditors or other stakeholders in the Chapter 11 Cases and the regulatory approval process necessary to consummate the Restructuring Plan.

In addition, the Chapter 11 Cases could have a material impact on our corporate or capital structure. For example, in connection with the Chapter 11 Cases, certain of our creditors may seek, and receive, Bankruptcy Court approval to sell or otherwise transfer certain of our subsidiaries (or their assets) in order to satisfy liabilities owed to such creditors. Any such transfer could result in significant tax liabilities for EFH Corp. and its subsidiaries (excluding the Oncor Ring-Fenced Entities), which could reduce the recovery of creditors. Additionally, TCEH has received a commitment from certain institutions for a DIP Facility to provide liquidity and fund operational and restructuring-related expenses during the Chapter 11 Cases. We cannot be certain that the Bankruptcy Court will authorize entry into this DIP Facility, and, if authorized, the consummation of such facility will be subject to customary closing conditions. In addition, if the consummation of such facility occurs, the TCEH Debtors will be subject to various covenants and events of default under the DIP Facility. If the TCEH Debtors fail to comply with these covenants or an event of default occurs under the DIP Facility, our liquidity, financial condition or operations may be materially impacted.

• Risks Related to Our Structure. EFCH's and TCEH's cash flows and ability to meet their obligations are largely dependent upon the earnings of their subsidiaries and the payment of such earnings to EFCH and TCEH in the form of dividends, distributions, loans or otherwise, and repayment of loans or advances from EFCH or TCEH to their subsidiaries. These subsidiaries are separate and distinct legal entities and have no obligation (other than any existing contractual obligations, which could be suspended or altered in the Chapter 11 Cases) to provide EFCH or TCEH with funds for its payment obligations. A subsidiary's ability and willingness to pay dividends or make loans will likely be limited by the Chapter 11 Cases, covenants in its existing and future debt agreements and/or applicable law.

• Market, Financial and Economic Risks. Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas. Accordingly, our earnings, cash flows and the value of our lignite/coal and nuclear fueled generation assets are dependent in significant part upon the price of natural gas. In recent years natural gas supply has outpaced demand, thereby depressing natural gas prices. In addition, wholesale electricity prices have generally moved with ERCOT market heat rates, which could fall if demand for electricity were to decrease or if more efficient generation facilities are built in ERCOT. Accordingly, our earnings, cash flows and the value of our lignite/coal and nuclear fueled generation assets are also dependent in significant part upon market heat rates. Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.

• Regulatory and Legislative Risks. Our regulatory and legislative risks include changes in laws and regulations that govern our operations. In particular, new requirements for control of certain emissions from sources including electricity generation facilities may result in our incurrence of significant additional costs.

19

• Operational Risks. Our operational risks include the risks inherent in running electricity generation facilities. Failure of our equipment and facilities, information technology failure, fuel or water supply interruptions and adverse weather conditions, among other things, can adversely affect our business. In addition, our retail business is subject to intense competition.

Risks Related to Filing under Chapter 11 of the United States Bankruptcy Code

We have filed voluntary petitions for relief under the Bankruptcy Code and are subject to the risks and uncertainties associated with bankruptcy cases.

We have filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. For the duration of the Chapter 11 Cases, our business and operations will be subject to various risks, including but not limited to the following:

• Our ability to develop, consummate, and implement the Restructuring Plan or one or more other plans of reorganization with respect to the Chapter 11 Cases;

• Our ability to obtain Bankruptcy Court, creditor and regulatory approval of the Restructuring Plan or another plan of reorganization and the effect of alternative proposals, views, and objections of creditor committees, creditors, or other stakeholders, which may make it difficult to develop and consummate the Restructuring Plan or another plan of reorganization in a timely manner;

• Our ability to obtain Bankruptcy Court approval with respect to motions in the Chapter 11 Cases and the outcomes of Bankruptcy Court rulings and of the Chapter 11 Cases in general;

• Risks associated with third party motions in the Chapter 11 Cases, which may interfere with our business operations, including additional collateral requirements, or ability to formulate and implement the Restructuring Plan or another plan of reorganization;

• Increased costs related to the Chapter 11 Cases and related litigation;

• Our ability to maintain or obtain sufficient financing sources for operations or to fund the Restructuring Plan or any other reorganization plan and meet future obligations;

• Potential termination of our hedging arrangements under the “safe harbor” provisions of the Bankruptcy Code;

• A material decrease in the number of counterparties that are willing to engage in commodity related hedging transactions with us and a significant increase in the amount of collateral required to engage in any such transactions;

• A loss of, or a disruption in the materials or services received from, suppliers, contractors or service providers with whom we have commercial relationships;

• A material decrease in the number of TXU Energy's electric customers and a material tarnishing of its brand;

• Risk that parties in interest in the Chapter 11 Cases may seek to cause the PUCT to review our REP certifications;

• Risks related to our mining reclamation bonding obligations;

• Potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increased difficulty in attracting new employees;

• Significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations; and

• The outcome of potential litigation regarding whether note holders are entitled to make-whole premiums in connection with the treatment of their claims in bankruptcy.

We will also be subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may significantly increase the time we have to operate under Chapter 11 bankruptcy protection. Because of the risks and uncertainties associated with Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure. For example, in connection with the Chapter 11 Cases, certain of our creditors may seek, and receive, Bankruptcy Court approval to sell or otherwise transfer certain of our subsidiaries (or their assets) in order to satisfy liabilities owed to such creditors. Any such transfer could result in significant tax liabilities for EFH Corp. and its subsidiaries (excluding the Oncor Ring-Fenced Entities), which could reduce the recovery of creditors.

The duration of the Chapter 11 Cases is difficult to estimate and could be lengthy. We will be required to seek approvals of the Bankruptcy Court and certain federal and state regulators in connection with the Chapter 11 Cases, and certain parties may intervene and protest approval, absent the imposition of conditions to resolve their concerns. The approvals by governmental entities may be denied, conditioned or delayed.

20

We intend to file various "first day" motions wherein we seek the authority to pay certain prepetition claims in the ordinary course of business. We cannot be sure that the Bankruptcy Court will grant these motions on an interim or final basis, as applicable. The Bankruptcy Court’s failure to grant these motions could have a negative impact on our business, liquidity, financial condition and results of operations. Additionally, TCEH has received a commitment from certain institutions for a DIP Facility to, among other things, provide liquidity and fund operational and restructuring-related expenses during the Chapter 11 Cases. We cannot be certain that the Bankruptcy Court will authorize entry into this DIP Facility, and, if authorized, the consummation of such facility will be subject to customary closing conditions. In addition, if the consummation of such facility occurs, the TCEH Debtors will be subject to various covenants and events of default under the DIP Facility. If we fail to comply with these covenants or an event of default occurs under the DIP Facility, our liquidity, financial condition or operations may be materially impacted.

Operating under Chapter 11 may restrict our ability to pursue our strategic and operational initiatives.

Under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities or to adapt to changing market or industry conditions. Additionally, the terms of the proposed DIP Facility and the Restructuring Support and Lock-Up Agreement (including related agreements) will limit our ability to undertake certain business initiatives. These limitations include, among other things, our ability to:

• sell assets outside the normal course of business;

• consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

• grant liens; and

• finance our operations, investments or other capital needs or to engage in other business activities that may be in our interest.

We may experience increased levels of employee attrition as a result of the Bankruptcy Filing.

As a result of the Bankruptcy Filing, we may experience increased levels of employee attrition, and our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incent key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of retention programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, liquidity and results of operations.

As a result of the Chapter 11 Cases, our historical financial information may not be indicative of our future financial performance.

Our capital structure will likely be significantly altered under any Chapter 11 plan confirmed by the Bankruptcy Court. Under fresh-start accounting rules that may apply to us upon the effective date of a Chapter 11 plan, our assets and liabilities would be adjusted to fair value. Accordingly, if fresh-start accounting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection with the Chapter 11 Cases and the development of a Chapter 11 plan, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to our consolidated financial position, liquidity and results of operations.

In particular, EFH Corp.’s capital structure will be significantly altered if the Restructuring Plan is consummated. On the Effective Date, pursuant to the Restructuring Support and Lock-Up Agreement and in connection with the confirmation of the Restructuring Plan, the outstanding equity of TCEH will be cancelled, the equity of Reorganized TCEH will be distributed to certain holders of TCEH’s outstanding senior first lien secured indebtedness, and EFH Corp. will cease to hold a direct or indirect equity interest in EFCH, TCEH, or any of TCEH’s direct or indirect subsidiaries.

21

If we fail to consummate the Restructuring Plan, a non-prearranged proceeding could delay our emergence from bankruptcy.

If we are not able to consummate the Restructuring Plan, we would likely become subject to a “traditional” bankruptcy proceeding, which would be lengthy, costly and highly disruptive, and have a more pronounced adverse effect on our business than the pre-arranged plan contemplated by the Restructuring Plan. A “traditional” bankruptcy proceeding would likely involve contested issues with multiple creditors. A non-prearranged proceeding could also cause critical members of our senior management team to pursue other opportunities.

The uncertainty surrounding a prolonged restructuring would also have other adverse effects on us. For example, it would also adversely affect:

• our ability to raise additional capital;

• our liquidity;

• how our business is viewed by regulators, investors, lenders and credit ratings agencies; and

• our enterprise value.

Even if the Restructuring Plan is successful, we will continue to face risks.

The Restructuring Plan is generally designed to reduce the amount of the Debtors' indebtedness and cash interest expense and improve each of their liquidity and financial and operational flexibility in order to generate long-term growth. Even if the Restructuring Plan is approved under the Bankruptcy Code and consummated, we will continue to face a number of risks upon emergence from the bankruptcy proceedings, including certain risks that are beyond our control, such as changes in economic conditions, changes in our industry and changes in commodity prices. As a result of these risks and others, there is no guarantee that the Restructuring Plan will achieve our stated goals.

The DIP Facilities may be insufficient to fund our cash requirements through our emergence from bankruptcy.

For the duration of the Chapter 11 Cases, we will be subject to various risks, including but not limited to (i) the inability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations, and (ii) increased legal and other professional costs associated with the Chapter 11 Cases and our reorganization.

We believe that the DIP Facilities, plus cash from operations (in the case of TCEH), will be sufficient to fund the Debtors' anticipated cash requirements through the pendency of the Chapter 11 Cases. However, if the Effective Date does not occur during the term of the DIP Facilities, we may not be able to obtain sufficient additional financing on acceptable terms or at all.

As a result of the Chapter 11 Cases, net operating losses and other tax attributes are not expected to be available upon emergence from the Chapter 11 Cases.

Certain tax attributes, such as net operating loss carry-forwards and certain tax credits, are expected to be utilized in connection with the Chapter 11 Cases. Under Section 108 of the Internal Revenue Code, tax attributes are reduced to the extent discharge of indebtedness income is excluded from gross income arising from a Chapter 11 case. If any attributes are still available after the application of Section 108, such attributes may be limited or lost in the event EFH Corp. or any of its subsidiaries experience an ownership change as defined under Section 382 of the Internal Revenue Code. In addition, tax attributes may be utilized in a transaction such as a sale or transfer of assets that could result in a significant tax liability for EFH Corp. and its subsidiaries. As a result of the foregoing rules, any pre-emergence net operating losses and certain tax credits are not expected to be available to EFH Corp. and its subsidiaries to reduce taxable income for tax periods beginning after emergence from Chapter 11.

22

Risks Related to Our Structure

EFCH and TCEH are holding companies and their obligations are structurally subordinated to existing and future liabilities and preferred stock of their subsidiaries.

EFCH's and TCEH's cash flows and ability to meet their obligations are largely dependent upon the earnings of their subsidiaries and the payment of such earnings to EFCH and TCEH in the form of dividends, distributions, loans or otherwise, and repayment of loans or advances from EFCH or TCEH. These subsidiaries are separate and distinct legal entities and have no obligation (other than any existing contractual obligations, which may be suspended or altered in the Chapter 11 Cases) to provide EFCH or TCEH with funds for their payment obligations. Any decision by a subsidiary to provide EFCH or TCEH with funds for their payment obligations, whether by dividends, distributions, loans or otherwise, will depend on, among other things, the subsidiary's results of operations, financial condition, cash requirements, contractual restrictions and other factors. In addition, a subsidiary's ability to pay dividends may be limited by covenants in its existing and future debt agreements, applicable law and the Chapter 11 Cases.

Because EFCH and TCEH are holding companies, their obligations to their creditors are structurally subordinated to all existing and future liabilities and existing and future preferred stock of their subsidiaries that do not guarantee such obligations. Therefore, with respect to subsidiaries that do not guarantee EFCH's or TCEH's obligations, EFCH's and TCEH's rights and the rights of their creditors to participate in the assets of any subsidiary in the event that such a subsidiary is liquidated or reorganized are subject to the prior claims of such subsidiary's creditors and holders of such subsidiary's preferred stock. To the extent that EFCH or TCEH may be a creditor with recognized claims against any such subsidiary, EFCH's or TCEH's claims would still be subject to the prior claims of such subsidiary's creditors to the extent that they are secured or senior to those held by EFCH or TCEH. Subject to restrictions contained in financing arrangements, EFCH's and TCEH's subsidiaries may incur additional debt and other liabilities.

EFH Corp. and Oncor, which is a subsidiary of EFH Corp. but not a subsidiary of EFCH, have implemented certain structural and operational ring-fencing measures that were based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor's credit quality. These measures were put in place to mitigate Oncor's credit exposure to Texas Holdings and its subsidiaries other than Oncor Holdings and its subsidiaries (Texas Holdings Group) and to reduce the risk that the assets and liabilities of Oncor would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities.

As part of the ring-fencing measures, a majority of the members of the board of directors of Oncor are required to be, and are, independent from EFH Corp. Any new independent directors of Oncor are required to be appointed by the nominating committee of Oncor Holdings, which is required to be, and is, comprised of a majority of directors that are independent from EFH Corp. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certain periods, any director designated by Texas Transmission Investment LLC (which owns approximately 19.75% of Oncor), the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp., which may result in EFH Corp. relying on loans from TCEH to meet its obligations.

In addition, Oncor's organizational documents prohibit Oncor from making any distribution to EFH Corp. so long as and to the extent that such distribution would cause Oncor's regulatory capital structure to exceed the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

Market, Financial and Economic Risks

Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and may otherwise significantly impact our businesses.

Technological advances have improved, and are likely to continue to improve, existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. Such technological advances have reduced, and are expected to continue to reduce, the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with traditional generation facilities. Consequently, the profitability and market value of our generation assets could be significantly reduced as a result of these advances. In addition, changes in technology have altered, and are expected to continue to alter, the channels through which retail customers buy electricity (i.e., self-generation facilities). To the extent self-generation facilities become a more cost-effective option for ERCOT customers, our revenues, liquidity and results of operations could be materially reduced.

23

Technological advances in demand-side management and increased conservation efforts have resulted, and are expected to continue to result, in a decrease in electricity demand. A significant decrease in electricity demand in ERCOT as a result of such efforts would significantly reduce the value of our generation assets. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption. Effective energy conservation by our customers could result in reduced energy demand or significantly slow the growth in demand. Such reduction in demand could materially reduce our revenues, liquidity and results of operations. Furthermore, we may incur increased capital expenditures if we are required to increase investment in conservation measures.

TCEH's revenues and results of operations generally are negatively impacted by decreases in market prices for electricity, natural gas prices and/or market heat rates.

TCEH is not guaranteed any rate of return on capital investments in its businesses. We market and trade electricity, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale operations. TCEH's results of operations depend in large part upon wholesale market prices for electricity, natural gas, uranium, coal, fuel oil and transportation in its regional market and other competitive markets and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of regulatory authorities. Market prices may fluctuate substantially over relatively short periods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, at times, there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.

Some of the fuel for our generation facilities is purchased under short-term contracts. Prices of fuel (including diesel, natural gas, coal and nuclear fuel) may also be volatile, and the price we can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.

Volatility in market prices for fuel and electricity may result from the following:

• volatility in natural gas prices;

• volatility in ERCOT market heat rates;

• volatility in coal and rail transportation prices;

• severe or unexpected weather conditions, including drought and limitations on access to water;

• seasonality;

• changes in electricity and fuel usage;

• illiquidity in the wholesale power or other commodity markets;

• transmission or transportation constraints, inoperability or inefficiencies;

• availability of competitively-priced alternative energy sources;

• changes in market structure;

• changes in supply and demand for energy commodities, including nuclear fuel and related enrichment and conversion services;

• changes in the manner in which we operate our facilities, including curtailed operation due to market pricing, environmental, safety or other factors;

• changes in generation efficiency;

• outages or otherwise reduced output from our generation facilities or those of our competitors;

• changes in the credit risk or payment practices of market participants;

• changes in production and storage levels of natural gas, lignite, coal, crude oil, diesel and other refined products;

• natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and

• federal, state and local energy, environmental and other regulation and legislation.

All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas because marginal electricity demand is generally supplied by natural gas fueled generation facilities. Accordingly, our earnings, cash flows and the value of our nuclear and lignite/coal fueled generation assets, which provided a substantial portion of our supply volumes in 2013, are dependent in significant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008 (from $11.12 per MMBtu in mid-2008 to $4.14 per MMBtu at December 31, 2013 for calendar year 2015). In recent years natural gas supply has outpaced demand as a result of development and expansion of hydraulic fracturing in natural gas extraction. Many industry experts expect this supply/demand imbalance to continue for a number of years, thereby depressing natural gas prices for a long-term period.

24

Wholesale electricity prices also have generally moved with ERCOT market heat rates, which could fall if demand for electricity were to decrease or if more efficient generation facilities are built in ERCOT. Accordingly, our earnings, cash flows and the value of our nuclear and lignite/coal fueled generation assets are also dependent in significant part upon market heat rates. As a result, our nuclear and lignite/coal fueled generation assets could significantly decrease in profitability and value if ERCOT market heat rates decline.

Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.

We cannot fully hedge the risk associated with changes in commodity prices, most notably electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative to market liquidity. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations, liquidity and financial position, either favorably or unfavorably.

To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, crude oil, diesel fuel, uranium and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, consumer behavior, market constraints or other factors could cause us to purchase power to meet unexpected demand in periods of high wholesale market prices or resell excess power into the wholesale market in periods of low prices. As a result of these and other factors, we cannot precisely predict the impact that risk management decisions may have on our businesses, results of operations, liquidity or financial position.

With the tightening of credit markets that began in 2008 and the expansion of regulatory oversight through various financial reforms, there has been some decline in the number of market participants in the wholesale energy commodities markets, resulting in less liquidity, particularly in the ERCOT electricity market. Participation by financial institutions and other intermediaries (including investment banks) has particularly declined. Extended declines in market liquidity could materially affect our ability to hedge our financial exposure to desired levels. In addition, our highly leveraged balance sheet has significantly limited the number of counterparties that will enter into commodity hedging transactions with us on attractive terms, which may become even more limited as a result of the Bankruptcy Filing.

To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that owe us money, energy or other commodities as a result of these activities will not perform their obligations. Should the counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, we could incur losses in addition to amounts, if any, already paid to the counterparties. In addition, because certain of these instruments are deemed to be "forward contracts" under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements. ERCOT market participants are also exposed to risks that another ERCOT market participant may default on its obligations to pay ERCOT for power taken, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.

As discussed in Note 4 to Financial Statements, goodwill and/or other intangible assets not subject to amortization that we have recorded in connection with the Merger are subject to at least annual impairment evaluations. As a result of the Bankruptcy Filing, we may be required to write off some or all of this goodwill and other intangible assets, which may cause adverse impacts on our results of operations and financial condition.

In accordance with accounting standards, goodwill and certain other indefinite-lived intangible assets that are not subject to amortization are reviewed annually or, if certain conditions exist, more frequently, for impairment. Factors such as the economic climate, market conditions, including the market prices for wholesale electricity and natural gas and market heat rates, environmental regulation, and the condition of assets are considered when evaluating these assets for impairment. The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could cause a material impact on our reported results of operations and financial condition.

25

Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets and/or during times when there are significant changes in commodity prices. The inability to access liquidity, particularly on favorable terms, could materially affect our results of operations, liquidity and financial condition.

Our businesses are capital intensive. We rely on access to financial markets and credit facilities as a significant source of liquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The inability to raise capital or access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our ability to meet our obligations or sustain and grow our businesses and could increase capital costs. Our access to the financial markets and credit facilities could be adversely impacted by various factors, such as:

• changes in financial markets that reduce available liquidity or the ability to obtain or renew credit facilities on acceptable terms;

• economic weakness in the ERCOT or general US market;

• changes in interest rates;

• a deterioration, or perceived deterioration, of EFCH's (and/or its subsidiaries') creditworthiness or enterprise value;

• a reduction in EFCH's or its applicable subsidiaries' credit ratings;

• a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilities that affects the ability of such lender(s) to make loans to us;

• volatility in commodity prices that increases margin or credit requirements;

• a material breakdown in our risk management procedures, and

• the occurrence of changes in our businesses that restrict our ability to access credit facilities.

In the event that the governmental agencies that regulate the activities of our businesses determine that the creditworthiness of any such business is inadequate to support our activities, such agencies could require us to provide additional cash or letter of credit collateral in substantial amounts to qualify to do business.

Further, a lack of available liquidity could adversely impact the evaluation of our creditworthiness by counterparties and rating agencies. In particular, such concerns by existing and potential counterparties could significantly limit TCEH's wholesale markets activities, including any future hedging activities.

While TCEH has received a commitment from certain financial institutions for a DIP Facility to, among other things, provide liquidity and fund operational and restructuring-related expenses during the Chapter 11 Cases, we cannot be certain that the Bankruptcy Court will authorize entry into the DIP Facility, and, if authorized, the consummation of such facility will be subject to customary closing conditions. Moreover, we cannot be sure that the DIP Facility will ultimately be adequate to cover all of our liquidity needs for the entirety of the Chapter 11 Cases. In addition, if the consummation of such facility occurs, the TCEH Debtors will be subject to various covenants and events of default under the DIP Facility. If we fail to comply with these covenants or an event of default occurs under the DIP Facilities, our liquidity, financial condition or operations may be materially impacted.

The costs of providing postretirement benefits and related funding requirements are subject to changes in value of fund assets, benefit costs, demographics and actuarial assumptions and may have a material effect on our results of operations, liquidity and financial condition.

To a limited extent, EFH Corp. provides pension benefits based on either a traditional defined benefit formula or a cash balance formula, and EFH Corp. also provides certain health care and life insurance benefits to our eligible employees and their eligible dependents upon the retirement of such employees. Our costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates, including the market value of the assets funding the pension and OPEB plans. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

The values of the investments that fund the pension and OPEB plans are subject to changes in financial market conditions. Significant decreases in the values of these investments could increase the expenses of the pension plans and the costs of the OPEB plans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods. See Note 15 to Financial Statements for further discussion of EFH Corp.'s pension and OPEB plans, including certain pension plan amendments approved by EFH Corp. in August 2012.

26

Regulatory and Legislative Risks

Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses and/or results of operations.

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. We will need to continually adapt to these changes.

Our businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act, the Energy Policy Act of 2005 and the Dodd-Frank Wall Street Reform and Consumer Protection Act), changing governmental policy and regulatory actions (including those of the PUCT, the NERC, the TRE, the RCT, the TCEQ, the FERC, the EPA, the NRC and the CFTC) and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT. Changes in, revisions to, or reinterpretations of existing laws and regulations may have a material effect on our businesses.

The Texas Legislature meets every two years. The next regular legislative session is scheduled to begin in January 2015; however, at any time the governor of Texas may convene a special session of the Legislature. During any regular or special session bills may be introduced that, if adopted, could materially affect our businesses, including our results of operations, liquidity or financial condition.

Our cost of compliance with existing and new environmental laws could materially affect our results of operations, liquidity and financial condition.

We are subject to extensive environmental regulation by governmental authorities, including the EPA and the TCEQ. In operating our facilities, we are required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits. We may incur significant additional costs beyond those currently contemplated to comply with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements (see Note 11 to Financial Statements).

The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources including electricity generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, in each case that may affect our generation facilities or our ability to cost-effectively develop new generation facilities. There is no assurance that the currently-installed emissions control equipment at our coal fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Some of the recent regulatory actions, such as the EPA's CSAPR and MATS, could require us to install significant additional control equipment, resulting in material costs of compliance for our generation units, including capital expenditures, higher operating and fuel costs and potential production curtailments if the rules take effect. These costs could result in material effects on our results of operations, liquidity and financial condition.

We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approval is retroactively disallowed, the operation of our facilities could be stopped, curtailed or modified or become subject to additional costs.

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

27

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

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

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

In September 2013, the EPA released a draft proposed rule for greenhouse gas emission standards from new electricity generation units (EGUs). In January 2014, the EPA withdrew the 2012 proposed rule and issued a revised proposed rule. We are currently reviewing this draft proposed rule; however, at this time it is uncertain how (if at all) the draft 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. We expect the proposed rule to include guidelines that require states to submit to the EPA their compliance implementation 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.

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

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

28

If we are required to comply with the EPA's revised Cross-State Air Pollution Rule (CSAPR), or a similar replacement, and in order to comply with the Mercury and Air Toxics Standard (MATS), we will likely incur material capital expenditures and operating costs and experience material revenue decreases due to reduced generation and wholesale electricity sales volumes.

In July 2011, the EPA issued the CSAPR, a replacement for the Clean Air Interstate Rule (CAIR). 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 discussed in Items 1 and 2, "Business and Properties – Environmental Regulations and Related Considerations – Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions." In June 2012, the EPA finalized the proposed rule (Second Revised Rule). 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 pending the EPA's further consideration of the rule. 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's decision. The US Supreme Court granted review of the D.C. Circuit Court's decision in June 2013 and heard oral arguments in December 2013. In April 2014, the US Supreme Court issued its opinion in the CSAPR litigation, reversing the D.C. Circuit Court's decision in which that court vacated CSAPR. The US Supreme Court has remanded the case to the D.C. Circuit Court for further proceedings consistent with its opinion. We are evaluating the decision and cannot predict the timing or outcome of future proceedings related to CSAPR, including any compliance timeframe or the financial effects, if any. As a result, there can be no assurance that we will not be required to implement a compliance plan for the CSAPR, the Final Revisions, the Second Revised Rule or any replacement rules in a short time frame or that such plan will not materially affect our results of operations, liquidity or financial condition.

Material capital expenditures would be required to comply with the CSAPR as well as with other pending and expected environmental regulations, including MATS.

Environmental capital expenditures are expected to total nearly $450 million from 2014 through 2020 to comply with the MATS rule as well as other EPA regulations, including maintenance of existing equipment.The total expenditure for environmental capital will ultimately depend on the evolution of pending or future regulatory requirements. Our current plan includes the ongoing use of lignite coal as part of the fuel mix at all of our coal facilities, in varying proportions that reflect the economically available fuel supply as well as the configuration of environmental control equipment for each unit.

Luminant's mining permits are subject to RCT review.

The RCT reviews on an ongoing basis whether Luminant is compliant with RCT rules and regulations and whether it has met all of the requirements of its mining permits. In addition, because of the Bankruptcy Filing, the RCT may initiate additional reviews of Luminant's creditworthiness. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities. Such event would have a material effect on our results of operations, liquidity and financial condition.

Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputation damage, and have a material effect on our results of operations, and the litigation environment in which we operate poses a significant risk to our businesses.

We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, and environmental issues, and other claims for injuries and damages, among other matters. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material effect on our results of operations. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significant business risk.

We are involved in the ordinary course of business in permit applications and renewals, and we are exposed to the risk that certain of our operating permit applications may not be granted or that certain of our operating permits may not be renewed on satisfactory terms. Failure to obtain and maintain the necessary permits to conduct our businesses could have a material effect on our results of operations, liquidity and financial condition.

29

We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. See Item 3, "Legal Proceedings – Litigation Related to EPA Reviews." While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have a material effect on our results of operations, liquidity and financial condition.

Our collateral requirements for hedging arrangements could be materially impacted if the remaining rules implementing the Financial Reform Act broaden the scope of the Act's provisions regarding the regulation of over-the-counter financial derivatives, making certain provisions applicable to end-users like us.

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). While the legislation is broad and detailed, a few key rulemaking decisions remain to be made by federal governmental agencies to fully implement the Financial Reform Act.

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

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. Based on our assessments, we are not a Swap Dealer or Major Swap Participant. However, 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. 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.

Certain issues remain uncertain; for example, the Financial Reform Act requires the posting of collateral for uncleared swaps, but the final rule for margin requirements for Swap Dealers and Major Swap Participants has not been issued. 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. Also, in November 2013 the CFTC proposed certain changes to its Position Limit Rule (PLR), which was vacated and remanded to the CFTC by the District Court for the District of Columbia. The PLR provides for specific position limits related to futures and Swap contracts that we utilize in our hedging activities. The proposed PLR will require that we comply with the portion of the PLR applicable to these contracts, which will result in increased monitoring and reporting requirements and can also impact the types of contracts that we utilize as hedging instruments in our operations.

The REP certification of our retail operation is subject to PUCT review.

The PUCT may at any time initiate an investigation into whether our retail operation complies with PUCT Substantive Rules and whether we have met all of the requirements for REP certification, including financial requirements. In addition, as a result of the Bankruptcy Filing, the PUCT may initiate additional reviews of our retail operation, including with respect to its creditworthiness. Any removal or revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers. Such decertification could have a material effect on our results of operations, liquidity and financial condition.

30

Operational Risks

We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generation facility.

The ownership and operation of a nuclear generation facility involves certain risks. These risks include:

• unscheduled outages or unexpected costs due to equipment, mechanical, structural, cyber security or other problems;

• inadequacy or lapses in maintenance protocols;

• the impairment of reactor operation and safety systems due to human error or force majeure;

• the costs of storage, handling and disposal of nuclear materials, including availability of storage space;

• the costs of procuring nuclear fuel;

• the costs of securing the plant against possible terrorist or cyber security attacks;

• limitations on the amounts and types of insurance coverage commercially available, and

• uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives.

The prolonged unavailability of Comanche Peak could materially affect our financial condition and results of operations. The following are among the more significant of these risks:

• Operational Risk — Operations at any nuclear generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at Comanche Peak.

• Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, the NRC operating licenses for Comanche Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively. In addition, as a result of the Bankruptcy Filing, the NRC may initiate additional reviews of our operations at Comanche Peak, including with respect to its ability to fund its operations in compliance with its operating license. Changes in regulations by the NRC, including potential regulation as a result of the NRC's ongoing analysis and response to the effects of the natural disaster on nuclear generation facilities in Japan in 2010, could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

• Nuclear Accident Risk — Although the safety record of Comanche Peak and other nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred both in the US and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impact and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage.

The operation and maintenance of electricity generation facilities involves significant risks that could adversely affect our results of operations, liquidity and financial condition.

The operation and maintenance of electricity generation facilities involves many risks, including, as applicable, start-up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. In particular, older generating equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (i) increased starting and stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all our generating facilities, (ii) any unexpected failure to generate electricity, including failure caused by equipment breakdown or forced outage, (iii) damage to facilities due to storms, natural disasters, wars, terrorist or cyber security acts and other catastrophic events and (iv) the passage of time and normal wear and tear. Further, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs and/or losses and write downs of our investment in the project or improvement.

31

We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist or cyber security attacks). The unexpected requirement of large capital expenditures could materially affect our results of operations, liquidity and financial condition.

If we make any major modifications to our power generation facilities, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the Clean Air Act. Any such modifications would likely result in us incurring substantial additional capital expenditures.

Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses that could result from the risks discussed above, including the cost of replacement power. Likewise, the ability to obtain insurance, and the cost of and coverage provided by such insurance, could be affected by events outside our control.

Our employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of our operations.

Employees and contractors throughout our organization work in, and customers and the general public may be exposed to, potentially dangerous environments near our operations. As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life. Significant risks include nuclear accidents, dam failure, gas explosions and electric contact cases.

Our results of operations, liquidity and financial condition may be materially affected by the effects of extreme weather conditions.

Our results of operations, liquidity and financial condition may be materially affected by weather conditions and may fluctuate substantially on a seasonal basis as the weather changes. In addition, we could be subject to the effects of extreme weather. Extreme weather conditions could stress our generation facilities resulting in outages, increased maintenance and capital expenditures. Extreme weather events, including sustained cold temperatures, hurricanes, storms or other natural disasters, could be destructive and result in casualty losses that are not ultimately offset by insurance proceeds or in increased capital expenditures or costs, including supply chain costs.

Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weather event might affect the availability of generation and transmission capacity, limiting our ability to source or deliver electricity where it is needed or limit our ability to source fuel for our plants (including due to damage to rail infrastructure). These conditions, which cannot be reliably predicted, could have an adverse consequence by requiring us to seek additional sources of electricity when wholesale market prices are high or to sell excess electricity when market prices are low.

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

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

Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significant additional costs if unsuccessful.

As we seek to improve our financial condition, we have taken, and intend to take steps to reduce our costs. While we have completed and have underway a number of initiatives to reduce costs, it will likely become increasingly difficult to identify and implement significant new cost savings initiatives. The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and if unsuccessful, may instead result in significant additional costs as well as significant disruptions in our operations due to employee displacement and the rapid pace of changes to organizational structure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect on our results of operations, liquidity and financial condition.

32

Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities and reputation damage and disrupt business operations, which could have a material effect on our results of operations, liquidity and financial condition.

Much of our information technology infrastructure is connected (directly or indirectly) to the Internet. There have been numerous attacks on government and industry information technology systems through the Internet that have resulted in material operational, reputation and/or financial costs. While we have controls in place designed to protect our infrastructure and have not had any significant breaches, a breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could adversely affect our reputation, expose the company to material legal/regulatory claims, impair our ability to execute on business strategies and/or materially affect our results of operations, liquidity and financial condition.

As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day, per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber and physical security breaches.

Our retail operation (TXU Energy) may lose a significant number of customers due to competitive marketing activity by other retail electric providers.

Our retail operation faces competition for customers. Competitors may offer lower prices and other incentives, or attempt to use the Bankruptcy Filing against us, which, despite the business' long-standing relationship with customers, may attract customers away from us. We operate in a very competitive retail market, as is reflected in a 23% decline in customers (based on meters) served over the last five years.

In some retail electricity markets, our principal competitor may be the incumbent REP. The incumbent REP has the advantage of long-standing relationships with its customers, including well-known brand recognition.

In addition to competition from the incumbent REP, we may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with us. Some of these competitors or potential competitors may be larger or better capitalized than we are. If there is inadequate potential margin in these retail electricity markets, it may not be profitable for us to compete in these markets.

Our retail operations are subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to our reputation and/or the results of the retail operations.

Our retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. Our retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. If a significant breach occurred, the reputation of our retail business may be adversely affected, customer confidence may be diminished, or our retail business may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and its results of operations, liquidity and financial condition.

Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, its customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material negative impact on the business and results of operations.

Our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities, as well as Oncor's facilities, to deliver the electricity it sells to its customers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered, and we may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service.

33

Our retail operations offer bundled services to customers, with some bundled services offered at fixed prices and for fixed terms. If our costs for these bundled services exceed the prices paid by our customers, our results of operations could be materially affected.

Our retail operations offer customers a bundle of services that include, at a minimum, electricity plus transmission, distribution and related services. The prices we charge for the bundle of services or for the various components of the bundle, any of which may be fixed by contract with the customer for a period of time, could fall below our underlying cost to provide the components of such services.

Our revenues and results of operations may be adversely impacted by decreases in wholesale market prices of electricity due to the development of wind generation sources.

A significant amount of investment in wind generation in the ERCOT market over the past few years has increased overall wind power generation capacity. Generally, the increased capacity has led to lower wholesale electricity prices (driven by lower market heat rates) in the regions at or near wind power development. As a result, the profitability of our generation facilities and power purchase contracts, including certain wind generation power purchase contracts, has been impacted and could be further impacted by the effects of the wind power development, and the value could significantly decrease if wind power generation has a material sustained effect on market heat rates. Additionally, as further development of long haul transmission lines under the Competitive Renewable Energy Zone program are completed, the increased capacity from wind power development will impact wholesale electricity prices outside of the regions at or near that development.

Our results of operations and financial condition could be negatively impacted by any development or event beyond our control that causes economic weakness in the ERCOT market.

We derive substantially all of our revenues from operations in the ERCOT market, which covers approximately 75% of the geographical area in the State of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market, economic weakness in the ERCOT market could lead to reduced demand for electricity in the ERCOT market. Such a reduction could have a material negative impact on our results of operations, liquidity and financial condition.

The loss of the services of our key management and personnel could adversely affect our ability to operate our businesses.

Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside our industry, government entities and other organizations. We may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attract new personnel or retain existing personnel could have a material effect on our businesses.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

34

Item 3. LEGAL PROCEEDINGS

See Items 1 and 2, "Business and Properties – Environmental Regulations and Related Considerations – Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions" for discussion of litigation regarding the CSAPR and the Texas State Implementation Plan as well as certain other environmental regulations.

Litigation

Aurelius Capital Master, Ltd. and ACP Master, Ltd. (Aurelius) filed a lawsuit in March 2013, amended in May 2013, in the US 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 alleged 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 sought recovery for the benefit of EFCH. EFCH and the directors filed a motion to dismiss this lawsuit in June 2013. In January 2014, the district court granted the motion to dismiss and in February 2014 entered final judgment dismissing the lawsuit. Aurelius has appealed the district court's judgment to the US Court of Appeals for the Fifth Circuit (Fifth Circuit 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. Oral argument was held in April 2014. 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 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 (a wholly owned subsidiary of TCEH) for alleged violations of the Clean Air Act (CAA) at Luminant's Big Brown generation facility. The Big Brown trial was held in February 2014. In pre-trial filings submitted in January 2014, the Sierra Club stated it was seeking over $337 million in civil penalties for the alleged violations and injunctive relief. In March 2014, the district court entered final judgment denying all of the Sierra Club's claims and all relief requested by the Sierra Club. The Sierra Club has appealed the district court's decision to the Fifth Circuit Court.

In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC for alleged violations of the CAA at Luminant's Martin Lake generation facility. In April 2014, the Martin Lake trial setting of May 2014 was vacated by the district court so that the district court could consider the effects of the decision in the Big Brown case. The Sierra Club has stated that it intends to ask the district court in this case to impose civil penalties of approximately $147 million. The Sierra Club has also stated that the district court can impose the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation depending on the date of the alleged violation. In addition, the Sierra Club has requested injunctive relief, including the installation of new emissions control equipment at the plant. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. While we are unable to estimate any possible loss or predict the outcome of the Martin Lake case, we believe that, as the judge ruled in the Big Brown case, the Sierra Club's claims are without merit, and we intend to vigorously defend the lawsuit.

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.

Notwithstanding the foregoing, the affirmative claims asserted against EFH Corp. and Luminant Generation Company LLC described above were automatically stayed as a result of the Bankruptcy Filing. The matters will be subject to resolution in accordance with the Bankruptcy Code and the orders of the Bankruptcy Court.

35

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 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 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. The consolidated cases are now fully briefed and before the Fifth Circuit Court. Oral argument has been scheduled for June 2014.

In August 2013, the US 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. In January 2014, the district court granted our motion to stay the lawsuit until the Fifth Circuit Court resolves our petitions for 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 against these allegations. The lawsuit requests civil penalties of up to $32,500 to $37,500 per day for each alleged violation (the maximum penalties available under the CAA), depending on the date of the alleged violation, and injunctive relief, including an order requiring the installation of best available control technology at the affected units. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. We cannot predict the outcome of these proceedings, including the financial effects, if any.

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.

36

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 annual report on Form 10-K.

37

PART II.

Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not applicable. All of EFCH's membership interests are owned by EFH Corp.

See Note 12 to Financial Statements for discussion of the restrictions on EFCH's ability to pay dividends.

38

Item 6. SELECTED FINANCIAL DATA

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

SELECTED CONSOLIDATED FINANCIAL DATA

(millions of dollars, except ratios)

	Year Ended December 31,
	2013			2012			2011			2010			2009
Operating revenues	$	5,899		$	5,636		$	7,040		$	8,235		$	7,911
Impairment of goodwill	$	(1,000	)	$	(1,200	)	$	—		$	(4,100	)	$	(70	)
Net income (loss)	$	(2,317	)	$	(3,008	)	$	(1,802	)	$	(3,530	)	$	515
Net loss attributable to noncontrolling interests	$	107		$	—		$	—		$	—		$	—
Net income (loss) attributable to EFCH	$	(2,210	)	$	(3,008	)	$	(1,802	)	$	(3,530	)	$	515
Ratio of earnings to fixed charges (a)	—			—			—			—			1.36
Cash provided by (used in) operating activities	$	(271	)	$	(240	)	$	1,236		$	1,257		$	1,384
Cash provided by (used in) financing activities	$	(174	)	$	1,161		$	(973	)	$	27		$	279
Cash provided by (used in) investing activities	$	16		$	134		$	(190	)	$	(1,338	)	$	(2,048	)
Capital expenditures, including nuclear fuel	$	(588	)	$	(844	)	$	(662	)	$	(902	)	$	(1,521	)
	At December 31,
	2013			2012			2011			2010			2009
Total assets	$	28,798		$	32,973		$	37,340		$	39,144		$	43,245
Property, plant & equipment — net	$	17,649		$	18,556		$	19,218		$	20,155		$	20,980
Goodwill and intangible assets	$	5,669		$	6,733		$	7,978		$	8,523		$	12,845
Capitalization
Debt (b)	$	26,230		$	30,310		$	30,458		$	29,474		$	32,121
EFCH membership interests/shareholder's equity	(12,269		)	(10,506		)	(7,819		)	(6,236		)	(4,266		)
Noncontrolling interests in subsidiaries	1			112			103			87			48
Total	$	13,962		$	19,916		$	22,742		$	23,325		$	27,903
Capitalization ratios
Debt (b)	187.9		%	152.2		%	133.9		%	126.4		%	115.1		%
EFCH membership interests/shareholder's equity	(87.9		)%	(52.8		)%	(34.4		)%	(26.7		)%	(15.3		)%
Noncontrolling interests in subsidiaries	—		%	0.6		%	0.5		%	0.3		%	0.2		%
Total	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%
Borrowings under credit and other facilities	$	2,054		$	2,136		$	774		$	1,221		$	953

___________

(a) Fixed charges exceeded earnings (see Exhibit 12(a)) by $3.054 billion, $3.932 billion, $2.745 billion and $3.212 billion for the years ended December 31, 2013, 2012, 2011 and 2010, respectively.

(b) For all periods presented, excludes amounts with contractual maturity dates in the following twelve months.

39

Note: See Note 1 to Financial Statements "Basis of Presentation." Financial Statements for 2010 reflect the prospective adoption of amended guidance regarding consolidation accounting standards related to variable interest entities and amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program being reported as borrowings under credit and other facilities as discussed in Note 9 to Financial Statements. Results for 2013 and 2012 were significantly impacted by goodwill impairment charges as discussed in Note 4 to Financial Statements. Results for 2011 were significantly impacted by an impairment charge related to emissions allowance intangible assets as discussed in Note 4 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 4 to Financial Statements.

See Notes to Financial Statements.

Quarterly Information (Unaudited)

Results of operations by quarter are summarized below. In our opinion, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a full year's operations because of seasonal and other factors. All amounts are in millions of dollars and may not add to full year amounts due to rounding.

	First Quarter			Second Quarter			Third Quarter		Fourth Quarter (a) (b)
2013:
Operating revenues	$	1,260		$	1,419		$	1,893	$	1,327
Net income (loss)	(526		)	(217		)	57		(1,631		)
Net loss attributable to noncontrolling interests	—			—			—		107
Net income (loss) attributable to EFCH	$	(526	)	$	(217	)	$	57	$	(1,524	)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter (a)
2012:
Operating revenues	$	1,222		$	1,385		$	1,752		$	1,278
Net loss	$	(253	)	$	(661	)	$	(385	)	$	(1,710	)

___________

(a) Net loss reflects goodwill impairment charges of $1.0 billion and $1.2 billion in 2013 and 2012, respectively (see Note 4 to Financial Statements).

(b) Net loss reflects a $140 million impairment charge related to assets of the nuclear generation development joint venture (see Note 8 to Financial Statements).

40

Item 7. 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 years ended December 31, 2013, 2012 and 2011 should be read in conjunction with Selected Consolidated Financial Data and our audited 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

Filing under Chapter 11 of the United States Bankruptcy Code — On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, (the Debtors) filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). During the pendency of the Bankruptcy Filing (the Chapter 11 Cases), the Debtors will operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. We intend to conduct our business operations in the normal course and maintain our focus on achieving excellence in customer service and meeting the needs of electricity consumers in Texas.

The Bankruptcy Filing resulted primarily from the adverse effects on EFCH of lower wholesale electricity prices in ERCOT driven by the sustained decline in natural gas prices since mid-2008. Further, the remaining natural gas hedges that TCEH entered into when forward market prices of natural gas were significantly higher than current prices mature in 2014. These market conditions challenged EFCH's profitability and operating cash flows and resulted in the inability to support its significant interest payments and debt maturities, including the remaining debt obligations due in 2014, and to refinance and/or extend the maturities of its outstanding debt. These liquidity matters raised substantial doubt about EFCH's ability to continue as a going concern without a restructuring of the debt.

In consideration of the liquidity matters discussed above, the report of EFCH's independent registered public accounting firm that accompanies its audited consolidated financial statements for the year ended December 31, 2013 included in this annual report contains an explanatory paragraph regarding the substantial doubt about EFCH's ability to continue as a going concern.

In 2013, EFH Corp. began to engage in discussions with certain creditors, including TCEH creditors, with respect to proposed changes to its capital structure, including the possibility of a consensual, prepackaged restructuring transaction. Because of the recent constructive nature of these discussions, TCEH elected not to make interest payments due in April 2014 totaling $123 million on certain debt obligations. Under the terms of the debt obligations that apply to the substantial majority of the missed interest payments, the lenders had the right to accelerate the payment of the debt if TCEH had not cured the default after an applicable grace period. In consideration of the additional time required to evaluate the effects of events related to the creditor discussions, including potential changes to our capital structure, on the financial statements and disclosures included in EFH Corp.'s, EFCH's and EFIH's Annual Reports on Form 10-K for the year ended December 31, 2013, the companies did not file their Annual Reports on Form 10-K for the year ended December 31, 2013 with the SEC by April 15, 2014, the date when the reports were required to be filed (including an allowed extension), and instead filed those Annual Reports on April 30, 2014. In anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors entered into a Restructuring Support and Lock-Up Agreement (the Restructuring Support and Lock-Up Agreement) with various stakeholders in order to effect an agreed upon restructuring of the Debtors through a pre-arranged Chapter 11 plan of reorganization (the Restructuring Plan).

41

Restructuring Support and Lock-Up Agreement

General

In anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors, Texas Holdings and its general partner Texas Energy Future Capital Holdings LLC (TEF and, together with Texas Holdings, the Consenting Interest Holders) and the Consenting Creditors entered into the Restructuring Support and Lock-Up Agreement in order to effect an agreed upon restructuring of the Debtors through the Restructuring Plan.

Pursuant to the Restructuring Support and Lock-Up Agreement, the Consenting Interest Holders and Consenting Creditors agreed, subject to the terms and conditions contained in the Restructuring Support and Lock-Up Agreement, to support the Debtors’ proposed financial restructuring (the Restructuring Transactions), and further agreed to limit certain transfers of any ownership (including any beneficial ownership) in the equity interests of or claims held against the Debtors, including any such interests or claims acquired after executing the Restructuring Support and Lock-Up Agreement.

Material Restructuring Terms

The Restructuring Support and Lock-Up Agreement along with the accompanying term sheet sets forth the material terms of the Restructuring Transactions pursuant to which, in general:

TCEH First Lien Secured Claims

As a result of the Restructuring Transactions, holders of TCEH first lien secured claims will receive, among other things, their pro rata share of (i)100% of the equity of TCEH consummated through a tax-free spin (in accordance with the Private Letter Ruling described below) in connection with TCEH's emergence from bankruptcy (Reorganized TCEH) and (ii) all of the net cash from the proceeds of the issuance of new long-term secured debt of Reorganized TCEH.

TCEH Unsecured Claims

As a result of the Restructuring Transactions, holders of general unsecured claims against EFCH, TCEH and its subsidiaries (including TCEH first lien deficiency claims, TCEH second lien claims and TCEH unsecured note claims) will receive their pro rata share of the unencumbered assets of TCEH.

EFIH First Lien Settlement

Certain holders of EFIH 6.875% Notes and EFIH 10% Notes (such holders, the EFIH First Lien Note Parties) have agreed to voluntary settlements with respect to EFIH’s and EFIH Finance’s obligations under the EFIH First Lien Notes held by the EFIH First Lien Note Parties. Under the terms of the settlement, each EFIH First Lien Note Party has agreed to accept as payment in full of any claims arising out of its EFIH First Lien Notes an amount of loans under the EFIH First Lien DIP Facility equal to the greater of (a) 105% of the principal amount on the EFIH First Lien Notes plus 101% of the accrued and unpaid interest at the non-default rate on such principal (which amount will be deemed to include the original issue discount) and (b) 104% of the principal amount of, plus accrued and unpaid interest at the non-default rate on, the EFIH First Lien Notes, in each case held by such EFIH First Lien Note Party. In addition, in the case of (b) above, each EFIH First Lien Note Party will be entitled to original issue discount paid in accordance with the EFIH First Lien Facility. No EFIH First Lien Note Party will receive any other fees, including commitment fees, paid in respect of the EFIH First Lien DIP Facility (such settlement, the EFIH First Lien Settlement).

During the early portion of the Chapter 11 Cases, EFIH expects to:

• solicit agreement to, and participation in, the EFIH First Lien Settlement from holders of the remaining outstanding EFIH First Lien Notes, other than the EFIH First Lien Note Parties (the EFIH First Lien Settlement Solicitation), and

• initiate litigation to obtain entry of an order from the Bankruptcy Court disallowing the claims of holders of EFIH First Lien Notes not a party to the EFIH First Lien Settlement (Non-Settling EFIH First Lien Note Holders) derived from or based upon make-whole or other similar payment provisions under the EFIH First Lien Notes.

42

Following the completion of the EFIH First Lien Settlement Solicitation, Non-Settling EFIH First Lien Note Holders will receive their pro rata share of cash from the proceeds of the EFIH First Lien DIP Facility in an amount equal to the principal plus accrued and unpaid interest through the closing of the EFIH First Lien DIP Facility, at the non-default rate of such holder's claim (not including any premiums, fees, or claims relating to the repayment of the EFIH First Lien Notes).

EFIH Second Lien Settlement

Certain holders of EFIH 11% Notes and EFIH 11.75% Notes (such holders, the EFIH Second Lien Note Parties) have agreed to voluntary settlements with respect to EFIH's and EFIH Finance's obligations under the EFIH Second Lien Notes held by the EFIH Second Lien Note Parties. Under the terms of the settlement, each EFIH Second Lien Note Party has agreed to accept as payment in full of any claims arising out of its EFIH Second Lien Notes, its pro rata share of an amount in cash equal to (i) 100% of the principal of, plus accrued but unpaid interest at the non-default rate on, EFIH Second Lien Notes held by such EFIH Second Lien Party plus (ii) 50% of the aggregate amount of any claim derived from or based upon make-whole or other similar provisions under the EFIH 11% Notes or EFIH 11.75% Notes (such settlement, the EFIH Second Lien Settlement).

As part of the EFIH Second Lien Settlement, a significant EFIH Second Lien Note Party, but not other EFIH Second Lien Note Parties, will have the right to receive up to $500 million of its payment under the EFIH Second Lien Settlement in the form of loans under the EFIH First Lien DIP Facility. In addition, such EFIH Second Lien Note Party will be entitled to its pro rata share of interest and original issue discount paid in respect of the EFIH First Lien DIP Facility and a 1.75% commitment fee.

During the early portion of the Chapter 11 Cases, EFIH expects to:

• solicit agreement to, and participation in, the EFIH Second Lien Settlement from holders of the remaining outstanding EFIH Second Lien Notes, other than the EFIH Second Lien Note Parties (the EFIH Second Lien Settlement Solicitation), and

• initiate litigation to obtain entry of an order from the Bankruptcy Court disallowing the claims of holders of EFIH Second Lien Notes not a party to the EFIH Second Lien Settlement (Non-Settling EFIH Second Lien Note Holders) derived from or based upon make-whole or other similar payment provisions under the EFIH Second Lien Notes.

Following the completion of the EFIH Second Lien Settlement Solicitation, Non-Settling EFIH Second Lien Note Holders will receive their pro rata share of cash from the proceeds of the EFIH Second Lien DIP Facility (as described below) in an amount equal to the principal plus accrued and unpaid interest through the closing of the EFIH Second Lien DIP Facility, at the non-default rate of such holder’s claim (not including any premiums, fees, or claims relating to the repayment of the EFIH Second Lien Notes).

EFIH Second Lien DIP Notes Offering

During the early portion of the Chapter 11 Cases, EFIH and EFIH Finance expect to offer (the EFIH Second Lien DIP Notes Offering) to all holders as of a specified record date of EFIH Unsecured Notes the right to purchase up to its pro rata percentage of $1.73 billion aggregate principal amount of 8% Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche A-1 Notes due 2016 (EFIH Second Lien DIP Tranche A-1 Notes). Concurrently with the EFIH Second Lien DIP Notes Offering, EFIH and EFIH Finance will also offer (the concurrent offering) to a significant EFIH Second Lien Note Party the right to purchase up to $170 million aggregate principal amount of 8% Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche A-3 Notes due 2016 (EFIH Second Lien DIP Tranche A-3 Notes). If such significant EFIH Second Lien Note Party elects to participate in the offering, EFIH will pay such party $11.3 million. To the extent the Backstop Parties are required to purchase any notes in the offering pursuant to the terms of the Commitment Letter (as described below), such notes will be 8% Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche A-2 Notes due 2016 (EFIH Second Lien DIP Tranche A-2 Notes). The EFIH Second Lien DIP Tranche A-1 Notes, the EFIH Second Lien DIP Tranche A-2 Notes and the EFIH Second Lien DIP Tranche A-3 Notes are expected to have the same terms and conditions (other than (i) the ability to trade as a single tranche, (ii) the EFIH Second Lien Tranche A-1 Notes will trade together with the corresponding EFIH Unsecured Notes and (iii) the EFIH Second Lien Tranche A-2 Notes and EFIH Second Lien Tranche A-3 Notes will not trade together with any other notes).

43

Backstop Commitment

In connection with the execution of the Restructuring Support and Lock-Up Agreement, certain holders of the EFIH Unsecured Notes (the Backstop Parties) have entered into a commitment letter with EFH Corp. and EFIH, dated April 29, 2014 (the Commitment Letter), pursuant to which such holders have committed, severally and not jointly, up to $2.0 billion in available funds (the Backstop Commitment) to purchase EFIH Second Lien DIP Notes. Any EFIH Second Lien DIP Notes not sold in the EFIH Second Lien DIP Notes Offering and the concurrent offering (unpurchased notes) will be purchased by the Backstop Parties, pro rata in proportion to their respective share of the Backstop Commitment. If any Backstop Party fails to satisfy its obligation to purchase its pro rata share of the unpurchased notes, the other Backstop Parties would have the right, but not the obligation, to purchase such unpurchased notes. The obligations under the Commitment Letter are not subject to the approval of the Oncor TSA Amendment (as described below) by the Bankruptcy Court.

Under the Commitment Letter and in consideration of the Backstop Commitment, EFIH agreed to pay the Backstop Parties a commitment fee consisting of (i) a $10 million execution fee that was paid to the Backstop Parties concurrently with the execution of the Commitment Letter, (ii) a $10 million approval fee to be paid within five days of the issuance of an order by the Bankruptcy Court authorizing the EFIH First Lien Settlement, the EFIH Second Lien Settlement, and the performance by EFH Corp. and EFIH under the Commitment Letter, (iii) a $20 million funding fee to be paid concurrently with the consummation of the EFIH Second Lien DIP Notes Offering to holders of EFIH Unsecured Notes and the concurrent offering and (iv) a fee equal to $100 million payable in the form of Non-Interest Bearing Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche B Notes due 2016 (EFIH Second Lien DIP Tranche B Notes and, together with the EFIH Second Lien DIP Tranche A-1 Notes, the EFIH Second Lien DIP Tranche A-2 Notes and the EFIH Second Lien DIP Tranche A-3 Notes, the EFIH Second Lien DIP Notes) to be paid concurrently with the consummation of the EFIH Second Lien DIP Notes Offering to holders of EFIH Unsecured Notes and the concurrent offering. Other than with respect to the requirement not to pay interest and related mechanics and not trading together with any other debt, the EFIH Second Lien DIP Tranche B Notes are expected to have the same terms and conditions as the EFIH Second Lien DIP Tranche A-1 Notes, the EFIH Second Lien DIP Tranche A-2 Notes and the EFIH Second Lien DIP Tranche A-3 Notes.

In the event the EFIH Second Lien DIP Notes are repaid in cash prior to the effective date of the plan of reorganization (Effective Date), EFIH agreed to pay the Backstop Parties a termination fee of $380 million. In addition, if the EFIH Second Lien DIP Notes Offering is not consummated at the option of EFIH, EFIH agreed to pay the Backstop Parties a break-up fee of $60 million.

EFIH Unsecured Claims and EFH Corp. Unsecured Claims

On the Effective Date, all of the EFIH Unsecured Notes and EFH Corp. Unsecured Notes will be canceled. In full satisfaction of the claims under the EFIH Unsecured Notes and the EFH Corp. Unsecured Notes, (i) each holder of EFIH Unsecured Notes will receive its pro rata share of 98.0% of the equity interests of newly reorganized EFH Corp. (Reorganized EFH Corp.) (subject to dilution by the Equity Conversion as described below) and (ii) each holder of EFH Corp. Unsecured Notes will receive its pro rata share of 1.0% of the equity interests of Reorganized EFH Corp. (subject to dilution by the Equity Conversion).

Holders of the EFH Corp. Unsecured Notes will also receive on the Effective Date their pro rata share of either (A) if the Oncor TSA Amendment (described below) has then been approved, (1) $55 million in cash from EFIH, provided, however, that if the Oncor tax payments received by EFIH under the Oncor TSA Amendment through the Effective Date are less than 80% of projected amounts the $55 million payment will be reduced on a dollar for dollar basis by the amount of such shortfall, and (2) cash on hand at EFH Corp. (not including the settlement payment in clause (1) hereof); or (B) if the Oncor TSA Amendment has not then been approved, all assets of EFH Corp., including cash on hand but excluding the equity interests in EFIH.

EFH Corp. Equity Interests

On the Effective Date, all of the equity interests in EFH Corp. (EFH Corp. Interests) will be canceled. In full satisfaction of the claims under the EFH Corp. Interests, each holder of EFH Corp. Interests will receive its pro rata share of 1.0% of the equity interests of Reorganized EFH Corp. (subject to dilution by the Equity Conversion).

Equity Conversion

On the Effective Date, the EFIH Second Lien DIP Notes will automatically convert (Equity Conversion) on a pro rata basis into approximately 64% of the equity interests of Reorganized EFH Corp.

44

Oncor TSA Amendment

The Restructuring Support and Lock-Up Agreement provides that the Debtors will request authority from the Bankruptcy Court to amend, or otherwise assign the right to payments under, the Oncor Tax Sharing Agreement (the Oncor TSA Amendment) to provide that any payment required to be made to EFH Corp. under the Oncor Tax Sharing Agreement after March 31, 2014, will instead be made to EFIH. Any tax payments received by EFH Corp. before the Bankruptcy Court enters or denies an order authorizing the Oncor TSA Amendment will be deposited by EFH Corp. into a segregated account until the earlier of (i) the date the Bankruptcy Court enters the order authorizing the Oncor TSA Amendment, in which case such amounts will be remitted to EFIH, or (ii) the date the Bankruptcy Court denies authorization of the Oncor TSA Amendment, in which case such amounts will be remitted to EFH Corp.

The Oncor TSA Amendment will automatically terminate and be of no further force and effect in the event that the Commitment Letter is terminated by the Backstop Parties; provided, however, that any amounts that were paid to EFIH in accordance with the Oncor TSA Amendment before its termination will be retained by EFIH if the Commitment Letter terminates or the EFIH Second Lien DIP Facility is not fully funded in accordance with its terms (i.e., except as a result of a breach by the Backstop Parties). Neither EFH Corp. nor EFIH will have the right to terminate or modify the Oncor TSA Amendment during the Chapter 11 Cases if the EFIH Second Lien DIP Facility is consummated.

If the Bankruptcy Court has not approved the Oncor TSA Amendment within 90 days after the Petition Date, the interest rate on the EFIH Second Lien DIP Tranche A-1 Notes, EFIH Second Lien DIP Tranche A-2 Notes and EFIH Second Lien DIP Tranche A-3 Notes will increase by 4.0% with such additional interest to be paid-in-kind (compounded quarterly) until such approval is received from the Bankruptcy Court. If the Bankruptcy Court has not approved the Oncor TSA Amendment by May 1, 2015, each holder of EFIH Second Lien DIP Notes will receive additional EFIH Second Lien DIP Notes equal to 10.0% of the amount of EFIH Second Lien DIP Notes held by such holder.

Private Letter Ruling

The Restructuring Support and Lock-Up Agreement provides that EFH Corp. will file a request with the IRS for a private letter ruling (Private Letter Ruling) that, among other things, will provide (a) that (i) the transfer by TCEH of all of its assets and its ordinary course operating liabilities to Reorganized TCEH, (ii) the transfer by the Debtors to Reorganized TCEH of certain operating assets and liabilities that are reasonably necessary to the operation of Reorganized TCEH and (iii) the distribution by TCEH of (A) the equity it holds in Reorganized TCEH and (B) the cash proceeds TCEH receives from Reorganized TCEH to the holders of TCEH First Lien Claims will qualify as a "reorganization" within the meaning of Sections 368(a)(1)(G) , 355 and 356 of the Code and (b) for certain other rulings under Sections 368(a)(1)(G) and 355 of the Code.

Conditions Precedent to Restructuring Transactions

The Restructuring Support and Lock-Up Agreement provides that the consummation of the Restructuring Transactions is subject to the satisfaction or waiver (if applicable) of various conditions, including, among other things:

• the consummation of the debtor-in-possession financing transactions and settlements described above;

• holders of certain EFH Unsecured Notes shall have received not less than 37.15% in value for their respective claims under the plan of reorganization;

• immediately following the distribution by TCEH described above under the heading "Private Letter Ruling", the aggregate tax basis, for federal income tax purposes, of the assets held by Reorganized TCEH will be equal to a specified minimum amount of aggregate tax basis, and the step-up in aggregate tax basis will be no less than $2.1 billion;

• the receipt of requisite regulatory approvals;

• the receipt of the Private Letter Ruling, and

• the receipt of requisite orders from the Bankruptcy Court.

Termination

The Restructuring Support and Lock-Up Agreement may be terminated upon the occurrence and continuation of certain events described in the Restructuring Support and Lock-Up Agreement.

45

Operation and Implications of the Chapter 11 Cases— Subject to certain exceptions, under the Bankruptcy Code, the Bankruptcy Filing automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Accordingly, although the Bankruptcy Filing triggered defaults on the Debtors' debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the Debtors' prepetition liabilities are subject to settlement under the Bankruptcy Code.

Following the Petition Date, the Debtors intend to seek approval from the Bankruptcy Court to pay or otherwise honor certain prepetition obligations generally designed to stabilize their operations. These obligations relate to certain employee wages and benefits, taxes, certain customer programs and certain obligations to vendors and hedging and trading counterparties. The Debtors intend to continue paying claims arising after the Petition Date in the ordinary course of business.

The Debtors have retained, pursuant to Bankruptcy Court approval, legal and financial professionals to advise them in connection with the Chapter 11 Cases and certain other professionals to provide services and advice in the ordinary course of business. From time to time, the Debtors may seek Bankruptcy Court approval to retain additional professionals. We have incurred and expect to continue to incur significant costs associated with the Chapter 11 Cases and our reorganization, but we cannot accurately predict the effect the Chapter 11 Cases will have on our liquidity, operations, financial position and results of operations.

The accompanying consolidated financial statements contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Our ability to continue as a going concern is contingent upon our ability to comply with the financial and other covenants contained in the debtor-in-possession financing (DIP Facility, described below), the Bankruptcy Court's approval of the Restructuring Plan or another Chapter 11 plan and our ability to successfully implement the Restructuring Plan or another Chapter 11 plan and obtain new financing, among other factors. As a result of the Chapter 11 Cases, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession under Chapter 11, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Facility), for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Restructuring Plan or another Chapter 11 plan could materially change the amounts and classifications of assets and liabilities reported in our consolidated financial statements.

Financing During the Chapter 11 Cases—As discussed in Note 10 to Financial Statements, we intend to file motions with the Bankruptcy Court for approval of the TCEH DIP Facility. The TCEH DIP Facility provides for $4.5 billion in senior secured, super-priority financing.

Chapter 11 Plan— A Chapter 11 plan (including the Restructuring Plan) determines the rights and satisfaction of claims of various creditors and security holders and is subject to the ultimate outcome of negotiations and Bankruptcy Court decisions ongoing through the date on which the Chapter 11 plan is confirmed. The Debtors currently expect that any proposed Chapter 11 plan (including the Restructuring Plan) will provide, among other things, mechanisms for settlement of claims against the Debtors' estates, treatment of EFH Corp.'s existing equity holders and the Debtors' respective existing debt holders, potential income tax liabilities and certain corporate governance and administrative matters pertaining to a reorganized EFH Corp. and EFCH. Any proposed Chapter 11 plan will (and the Restructuring Plan may) be subject to revision prior to submission to the Bankruptcy Court based upon discussions with the Debtors' creditors and other interested parties, and thereafter in response to creditor claims and objections and the requirements of the Bankruptcy Code or the Bankruptcy Court. There can be no assurance that the Debtors will be able to secure approval for the Restructuring Plan or any other Chapter 11 plan from the Bankruptcy Court or that any Chapter 11 plan will be accepted by the Debtors' creditors.

In order for the Debtors to emerge successfully from the Chapter 11 Cases as reorganized companies, they must obtain approval from the Bankruptcy Court and certain of their respective creditors for a Chapter 11 plan, which will enable each of the Debtors to transition from the Chapter 11 Cases into reorganized companies conducting ordinary course operations outside of bankruptcy. In connection with an exit from bankruptcy, TCEH will require a new credit facility, or "exit financing." TCEH's ability to obtain such approval, and TCEH's ability to obtain such financing will depend on, among other things, the timing and outcome of various ongoing matters in the Chapter 11 Cases.

46

Regulatory Requirements Related to the Bankruptcy Filing — Pursuant to the Bankruptcy Code, the Debtors intend to comply with all applicable regulatory requirements, including all requirements related to environmental and safety law compliance, during the pendency of the Chapter 11 Cases. In addition, the Debtors will seek all necessary and appropriate regulatory approvals necessary to consummate any transactions proposed in the Chapter 11 plan. Moreover, to the extent the Debtors either maintain insurance policies or self-insure their regulatory compliance obligations, the Debtors intend to continue such insurance policies or self-insurance in the ordinary course of business.

Income Tax Matters — See Note 5 to Financial Statements for discussion of the agreement EFH Corp. reached with the IRS 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. The resolution of audits for these periods resulted in an income tax benefit of $80 million recorded in the year ended December 31, 2013.

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 — Because wholesale electricity prices in ERCOT have generally moved with natural gas prices, in previous years TCEH had entered into long-term market transactions involving natural gas-related financial instruments designed to mitigate the effect of natural gas price changes on future electricity revenues. With the remaining natural gas hedging positions in this portfolio at December 31, 2013, TCEH has effectively sold forward approximately 146 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 17,000 GWh at an assumed 8.5 market heat rate) for the period January 1, 2014 through December 31, 2014 at a weighted average annual hedge price of $7.80 per MMBtu; at December 31, 2012, the comparable hedge volumes totaled approximately 360 million MMBtu. The decline in hedge volumes reflects maturities of positions in the hedge portfolio.

Volumes and hedge values associated with the natural gas hedging positions 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.

The Bankruptcy Filing constituted an event of default under the natural gas hedging agreements. Because certain of these instruments are deemed to be "forward contracts" under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements.

As part of these natural gas hedging activities, TCEH had entered into related put and call transactions (referred to as collars) that mature in 2014 and represent substantially all of the natural gas hedging positions at December 31, 2013. The hedge prices fall within a range, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu.

The 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 with the natural gas hedging positions may not be achieved.

47

Because of the low natural gas price environment, we currently have no natural gas hedging positions that mature after 2014. The following table summarizes the positions at December 31, 2013:

	Measure	2014
Natural gas hedge volumes (a)	mm MMBtu	~146
Weighted average hedge price (b)	$/MMBtu	~7.80
Average market price (c)	$/MMBtu	~4.19
Forecasted realization of hedge gains (d)	$ millions	~$550

___________

(a) For collars, the volumes are based on the delta equivalent short position of approximately 150 million MMBtu for the period January 1, 2014 through December 31, 2014.

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

(c) Based on NYMEX Henry Hub prices at December 31, 2013.

(d) Based on cumulative unrealized mark-to-market gain at December 31, 2013.

Changes in the fair value of the natural gas hedging instruments 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 natural gas hedging position at December 31, 2013, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $146 million in pretax unrealized mark-to-market gains or losses.

The natural gas positions have resulted in reported net gains (losses) as follows:

	Year Ended December 31,
	2013			2012			2011
Realized net gains	$	998		$	1,833		$	1,265
Unrealized net losses including reversals of previously recorded amounts related to positions settled	(1,033		)	(1,540		)	(19		)
Total	$	(35	)	$	293		$	1,246

The cumulative unrealized mark-to-market net gain related to the natural gas hedging positions totaled $551 million and $1.584 billion at December 31, 2013 and 2012, respectively. The decline was driven by settlements of maturing positions.

Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in the future. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost.

The significant realized net gains related to natural gas hedging positions reflects the sustained decline in forward market natural gas prices as presented in "Key Risks and Challenges" below. Forward natural gas prices have generally trended downward over the past several years. While the natural gas hedging positions have mitigated the effect on earnings of low wholesale electricity prices, depressed natural gas and wholesale electricity prices have been challenging to our liquidity and the long-term profitability of our business particularly in consideration of our substantial debt obligations. See Note 2 to Financial Statements.

Also see Note 4 to Financial Statements for discussion regarding goodwill impairment charges recorded in 2013 and 2012.

Overall Hedged Position — Taking together forward wholesale and retail electricity sales with all hedging positions, at December 31, 2013 and March 31, 2014, we had effectively hedged an estimated 95% and 78%, respectively, of the price exposure, on a natural gas equivalent basis, related to our expected generation output for 2014 (assuming an 8.5 market heat rate). The majority of our hedges are financial natural gas positions and include those positions entered into in previous years as discussed above as well more recent short-term hedges. The decline in the overall hedged position is primarily due to a reduction in the short-term hedge portfolio.

48

TCEHInterest Rate Swap Transactions — TCEH has employed interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at December 31, 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%	January 2014 through October 2014		$	18.19	billion (a)
6.8	%	-	9.0%	October 2015 through October 2017		$	12.60	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 $1.330 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 December 31, 2013 totaled $1.050 billion notional amount, a decrease of $10.917 billion from December 31, 2012 reflecting expired swaps. The remaining basis swaps expire in August 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 13 to Financial Statements for discussion of nonperformance risk adjustments included in unrealized net gain in 2013.

	Year Ended December 31,
	2013			2012			2011
Realized net loss	$	(620	)	$	(670	)	$	(684	)
Unrealized net gain (loss) including reversals of previously recorded amounts related to settled positions	1,053			166			(812		)
Total	$	433		$	(504	)	$	(1,496	)

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.363 billion (before nonperformance risk adjustment) and $2.065 billion at December 31, 2013 and 2012, respectively. The decline in the net liability reflected unrealized gains due to higher interest rates and settlements of maturing swaps. 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 December 31, 2013, a one percent change in interest rates would result in an increase or decrease of approximately $500 million in our cumulative unrealized mark-to-market net liability. The Bankruptcy Filing constituted an event of default under the interest rate swap agreements, and because the agreements are deemed to be "forward contracts" under the Bankruptcy Code, the counterparties may elect to terminate the agreements.

First-Lien Security for Natural Gas Hedging Positions and Interest Rate Swaps — Substantially all of the natural gas hedging positions discussed above and all of the TCEH interest rate swaps 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. Certain entities are counterparties to both our natural gas hedging positions and our interest rate swaps and have entered into master agreements that provide for netting and setoff of amounts related to these positions. As reflected in our balance sheet at December 31, 2013, our net mark-to-market liability positions related to these counterparties together with mark-to-market liability positions related to entities that are counterparties to only our interest rate swaps totaled approximately $1.1 billion (before nonperformance risk adjustment). This amount is based on our determinations of fair value of the positions at that time and is subject to change based on changes in interest rates and natural gas prices. Because these instruments are deemed to be "forward contracts" under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements. In addition, net accounts payable amounts related to settled positions, which totaled $89 million at December 31, 2013, are secured by the first-lien interest.

Debt Restructuring/Liability Management Activities — In October 2009, we and EFH Corp. implemented a program designed to reduce debt, capture debt discount and extend debt maturities through debt exchanges, repurchases and extensions. Activities under this program did not include debt issued by Oncor or its subsidiaries.

49

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, as well as the extension of $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016. Consent and extension cash payments to loan holders related to the April 2011 facilities extensions totaled $699 million, and extension fees related to the January 2013 Revolving Credit Facility extension were settled through the issuance of $340 million principal amount of incremental TCEH Term Loan Facilities maturing in 2017.

Other activities under this program since October 2009 related to TCEH debt included 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) Of the $1.623 billion of TCEH Senior Secured Facilities repaid, $1.604 billion was funded with net proceeds from the issuance of $1.750 billion principal amount of the TCEH 11.5% Notes due 2020 and the remainder of the cash was sourced from 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.

See Note 10 to Financial Statements for discussion of these and other debt-related transactions and Note 2 regarding the Bankruptcy Filing. The transactions noted in the table immediately above 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.

Seasonal Suspension of Certain Generation Operations — In October 2013, ERCOT approved our notice of intent 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. In August 2013, ERCOT approved our notice of intent to suspend operations beginning October 2013 at two of the three generation units at our Monticello generation facility due to low wholesale power prices and other market conditions. While the units were expected to return to service during the peak demand months in the summer of 2014, the units were returned to service in February and March 2014 in response to higher than anticipated wholesale electricity prices driven by increased demand for natural gas and electricity in Texas and nationally. The previously disclosed seasonal suspension of two generation units at Monticello that began December 2012 ended June 2013 as planned. The suspension of operations did not significantly impact our results of operations, liquidity or financial condition.

Natural Gas Fueled Generation Development — In August 2013, the TCEQ granted air permits to Luminant to build two natural gas combustion turbine generation units totaling 420 MW to 460 MW at its existing DeCordova generation facility. In February 2014, the TCEQ granted air permits to Luminant to build two natural gas combustion turbine generation units totaling 420 MW to 460 MW at its existing Tradinghouse generation facility. In January 2014, Luminant filed an air permit application with the TCEQ to build a combined cycle natural gas turbine generation unit totaling 730 MW to 810 MW at its existing Eagle Mountain generation facility. In February 2014, Luminant filed an air permit application with the TCEQ to build two natural gas combustion turbine generation units totaling 420 MW to 460 MW at its existing Lake Creek 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.

50

Nuclear Generation Development — In 2008, we filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at our existing Comanche Peak nuclear plant site. In connection with the filing of the application, in 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company LLC (CPNPC), to further the development of the two new nuclear generation units using MHI's US-Advanced Pressurized Water Reactor (US-APWR) technology. The TCEH subsidiary owns an 88% interest in CPNPC, and an MHI subsidiary owns a 12% interest.

In the fourth quarter 2013, MHI notified us and the NRC of its plans to refocus MHI's US resources on the restart of 24 nuclear reactors in Japan and thus reduce its support of review activities related to the NRC's Design Certification of MHI's US-APWR technology. As a result, Luminant has notified the NRC of its intent to suspend all reviews associated with the combined operating license application by March 31, 2014. Luminant does not intend to withdraw the license application at this time. MHI expressed to the NRC its continuing commitment to obtaining an NRC design certification for its technology. Luminant has filed a loan guarantee application with the DOE for financing the proposed units prior to commencement of construction and expects to continue to update the application in accordance with the loan solicitation guidelines. See Note 8 to Financial Statements for discussion of impairment of the joint venture's assets.

Pension Plan Actions — In August 2012, EFH Corp. approved certain amendments to its pension plan (see Note 15 to Financial Statements). These actions were completed in the fourth quarter 2012, and the amendments 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, including TCEH, other than collective bargaining unit employees.

EFH Corp.'s competitive operations recorded charges totaling $285 million in the fourth quarter 2012, including $193 million related to the competitive business obligations (including discontinued businesses) that were assumed under the Oncor Plan and $92 million related to the settlement of the terminated liabilities. These amounts represent the previously unrecognized actuarial losses reported in EFH Corp.'s accumulated other comprehensive income (loss). TCEH's allocated share of these charges totaled $141 million. TCEH settled $91 million of this allocation with EFH Corp. in 2012 and settled the remaining $50 million with EFH Corp. in the first quarter 2013.

Settlement of the liabilities and the full funding of the EFH Corp. competitive operations portion of liabilities (including discontinued businesses) under the Oncor Plan resulted in an aggregate pension plan cash contribution by EFH Corp.'s competitive operations of $259 million in the fourth quarter 2012.

Impairment of Goodwill— In 2013 and 2012, we recorded $1.0 billion and $1.2 billion, respectively, in noncash goodwill impairment charges (which were not deductible for income tax purposes). The write-offs reflected the effect of lower wholesale power prices in ERCOT, driven by the sustained decline in natural gas prices as discussed in "Key Risks and Challenges - Natural Gas Price and Market Heat Rate Exposure" below. Recorded goodwill totaled $3.95 billion at December 31, 2013. See Note 4 to Financial Statements.

The noncash impairment charges did not cause EFCH or its subsidiaries to be in default under any of their respective debt covenants or impact counterparty trading agreements or have a material impact on liquidity.

See Note 4 to Financial Statements and "Application of Critical Accounting Policies" below for more information on goodwill impairment testing and charges.

Global Climate Change and Other Environmental Matters — See Items 1 and 2, "Business and Properties – Environmental Regulations and Related Considerations" for discussion of global climate change, recent and anticipated EPA actions and various other environmental matters and their effects on the company.

Recent PUCT/ERCOT Actions — ERCOT publishes a Capacity, Demand and Reserves report (CDR Report) twice each year that projects the reserve margin in ERCOT over a ten year horizon. In its February 2014 CDR Report, ERCOT projected that reserve margins in the ERCOT market would not fall below the current target reserve margin of 13.75% until 2017. The CDR Report projects reserve margins of 12.8% in 2017, 13.4% in 2018 and 10.9% in 2019. The February 2014 CDR Report employed revised forecast methodologies that indicated a slower pace of peak demand growth as compared to the May 2013 CDR Report, which projected that reserve margins would fall below the target reserve margin beginning in 2015.

51

In August 2013, the PUCT directed ERCOT to work with the Brattle Group, an independent consulting firm, to conduct a study of the ERCOT wholesale electricity market and estimate an economically optimal planning reserve margin. In January 2014, the Brattle Group released its study and concluded that the economically optimal reserve margin, which balances the marginal costs of additional reserves against the marginal costs of unserved load, is approximately 10%, while the current ERCOT market design, including the effects of the ORDC discussed below, would generally result in a reserve margin of 11.5% over the long-term. The report further concluded that mandating a planning reserve margin in the 13% to 15% range would result in modest cost increases to electricity consumers while offering meaningful risk mitigation benefits for both policymakers and market participants.

Discussions are expected to continue among the PUCT, ERCOT, state lawmakers, market participants and other stakeholders regarding generation resource adequacy, including the appropriate level of planning reserve margin, and additional actions, if any, necessary to achieve such margin.

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 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 beginning in the summers of 2014 and 2015, respectively). In September 2013, the PUCT directed ERCOT to develop the processes necessary to implement a new pricing mechanism, "the operating reserve demand curve" (also known as "ORDC" and "Hogan Solution B+"), which would provide for a price adder to real-time wholesale power prices as reserves decline. The market rules implementing the operating reserve demand curve were approved by the ERCOT Board in November 2013 and are targeted to be implemented in June 2014.

Settlement of Make-Whole Agreements with Oncor—See Note 17 to Financial Statements for discussion of the settlement in 2012 of our interest and tax-related reimbursement agreements with Oncor associated with Oncor's bankruptcy-remote financing subsidiary's securitization bonds.

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

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

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 regular 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.

52

KEY RISKS AND CHALLENGES

Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges. These matters involve risks that could have a material effect on our results of operations, liquidity or financial condition. Also see Item 1A, "Risk Factors."

Bankruptcy Filing

As discussed above, we filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. For the duration of the Chapter 11 Cases, our business and operations will be subject to various risks, including but not limited to the following:

• a loss of, or a disruption in receipts of, materials or services provided by vendors with whom we have commercial relationships;

• a decrease in the number of counterparties that are willing to engage in commodity related hedging transactions with us and an increase in the amount of collateral required to engage in any such transactions;

• increased levels of employee distraction and uncertainty and potential attrition;

• the inability to maintain or obtain sufficient debtor-in-possession financing sources for operations or to fund any reorganization plan and meet future obligations;

• a decrease in the number of our retail electricity customers and potential tarnishing of the TXU Energy brand, and

• increased legal and other professional costs associated with the Chapter 11 Cases and our reorganization.

The duration of the Chapter 11 Cases is difficult to estimate and ultimately could be lengthy. We will also be required to seek approvals of certain federal and state regulators in connection with the Chapter 11 Cases, which approvals may be denied, conditioned or delayed, and certain parties may intervene and protest approval. An extended duration of the Chapter 11 Cases due to these factors could exacerbate the risks identified above.

While we are operating under Chapter 11, transactions outside of the ordinary course of business will be subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities. Additionally, the terms of the DIP Facility and the Restructuring Support and Lock-Up Agreement (and related agreements) will limit our ability to undertake certain business initiatives.

To mitigate the risks discussed above, communications with our customers, suppliers and employees will emphasize that the Bankruptcy Filing is the result of an overleveraged balance sheet given the changed wholesale electricity price environment driven by lower natural gas prices and is not the result of a failure of our business model or issues with the performance of our generation assets or other operations. We intend to conduct our business operations in the normal course and maintain our focus on achieving excellence in customer service and meeting the needs of electricity consumers in Texas.

We have also engaged outside counsel and other advisors who are experts in bankruptcy matters to assist our management and other employees with legal and administrative matters related to the Bankruptcy Filing to minimize disruption to and distraction from our business operations and to help ensure that we have sufficient liquidity through the duration of the Chapter 11 Cases.

53

Natural Gas Price and Market Heat Rate Exposure

Wholesale electricity prices in the ERCOT market have historically moved with the price of natural gas because marginal demand for electricity supply is generally met with natural gas fueled generation facilities. The price of natural gas has fluctuated due to changes in industrial demand, supply availability and other economic and market factors, and such prices have historically been volatile. As shown in the table below, forward natural gas prices have generally declined over the last several years driven by development and expansion of hydraulic fracturing in natural gas extraction. (Amounts are prices per MMBtu.)

	Settled Prices (b)		Forward Market Prices (a)
Date			2009		2010		2011		2012		2013		2014		2015		2016
December 31, 2008	$	9.03	$	6.11	$	7.13	$	7.31
December 31, 2009	$	3.99			$	5.79	$	6.34	$	6.53
December 31, 2010	$	4.39					$	4.55	$	5.08	$	5.33
December 31, 2011	$	4.04							$	3.24	$	3.94	$	4.34
December 31, 2012	$	2.79									$	3.54	$	4.03	$	4.23
March 31, 2013	$	3.34											$	4.23	$	4.30	$	4.38
June 30, 2013	$	4.09											$	3.91	$	4.14	$	4.33
September 30, 2013	$	3.58											$	3.86	$	4.06	$	4.17
December 31, 2013	$	3.60											$	4.19	$	4.14	$	4.13

___________

(a) Represents the annual average of NYMEX Henry Hub monthly forward prices at the date presented. Three years of forward prices are presented as such period is generally deemed to be the liquid period.

(b) Represents the average of NYMEX Henry Hub monthly settled prices of financial contracts for the year/quarter ending on the date presented.

In contrast to our natural gas fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from our nuclear and lignite/coal fueled facilities, which represent the substantial majority of our generation capacity. All other factors being equal, these nuclear and lignite/coal fueled generation assets increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect on wholesale electricity prices in ERCOT.

The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate can be affected by a number of factors including generation resource availability and the efficiency of the marginal supplier (generally natural gas fueled generation facilities) in generating electricity. While market heat rates have generally increased as natural gas prices have declined, wholesale electricity prices have declined due to the greater effect of falling natural gas prices.

Our market heat rate exposure is impacted by changes in the availability, such as additions and retirements of generation facilities, and mix of generation assets in ERCOT. For example, increasing wind generation capacity generally depresses market heat rates. Our heat rate exposure is impacted by potential economic backdown of our generation assets. We expect that decreases in market heat rates would decrease the value of our generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa.

With the exposure to variability of natural gas prices and market heat rates in ERCOT, retail sales price management and hedging activities are critical to the profitability of the business and maintaining consistent cash flow levels.

Our approach to managing electricity price risk focuses on the following:

• employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts intended to partially hedge gross margins;

• continuing focus on cost management to better withstand gross margin volatility;

• following a retail pricing strategy that appropriately reflects the magnitude and costs of commodity price, liquidity risk and retail load variability, and

• improving retail customer service to attract and retain high-value customers.

54

As discussed above in "Significant Activities and Events and Items Influencing Future Performance," we have engaged in natural gas hedging activities to mitigate the risk of lower wholesale electricity prices due to declines in natural gas prices. While current and forward natural gas prices are currently depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales. At December 31, 2013, we have no significant natural gas hedges beyond 2014.

We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term heat rate hedging transactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricity sales contracts where practical considering pricing, credit, liquidity and related factors.

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 our unhedged position and forward prices at December 31, 2013, which for natural gas reflects estimates of electricity generation less amounts hedged through the natural gas hedging positions 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 2014 (a)	2015
$1.00/MMBtu change in natural gas price (b)	$ ~21	$ ~460
0.1/MMBtu/MWh change in market heat rate (c)	$ ~15	$ ~30
$1.00/gallon change in diesel fuel price	$ ~14	$ ~40

___________

(a) Balance of 2014 is from February 1, 2014 through December 31, 2014.

(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 December 31, 2013.

On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based on our desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of overall generation and consumption in our businesses (which is also subject to volatility resulting from customer churn, weather, economic and other factors). Portfolio balancing may include the execution of incremental transactions, including heat rate hedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricity at fixed prices. As a result, commodity price exposures and their effect on earnings could materially change from time to time.

New and Changing Environmental Regulations

We are subject to various environmental laws and regulations related to SO₂, NO_X and mercury as well as other emissions that impact air and water quality. We believe we are in compliance with all current laws and regulations, but regulatory authorities have recently adopted or proposed new rules, such as the EPA's CSAPR and MATS, which could require material capital expenditures if the rules take effect, and authorities continue to evaluate existing requirements and consider proposals for further rule changes. If we make any major modifications to our power generation facilities, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures. (See Note 11 to Financial Statements for discussion of "Litigation Related to Generation Facilities," "Litigation Related to EPA Reviews" and "Environmental Contingencies" and Items 1 and 2, "Business and Properties – Environmental Regulations and Related Considerations.")

We also continue to closely monitor any potential legislative, regulatory and judicial changes pertaining to global climate change. In view of the fact that a substantial portion of our generation portfolio consists of lignite/coal fueled generation facilities, our results of operations, liquidity or financial condition could be materially affected by the enactment of any legislation, regulation or judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities that produce GHG emissions, or that establishes federal renewable energy portfolio standards. For example, federal, state or regional legislation or regulation addressing global climate change could result in us either incurring material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program. See further discussion under Items 1 and 2, "Business and Properties – Environmental Regulations and Related Considerations."

55

Competitive Retail Markets and Customer Retention

Competitive retail activity in Texas has resulted in retail customer churn. Our total retail customer counts declined 3% in 2013, 4% in 2012 and 9% in 2011. Based upon 2013 results discussed below in "Results of Operations," a 1% decline in residential customers would result in a decline in annual revenues of approximately $30 million. In responding to the competitive landscape in the ERCOT marketplace, we have reduced overall customer losses by focusing on the following key initiatives:

• Maintaining competitive pricing initiatives on residential service plans;

• Actively competing for new customers in areas in Texas open to competition, including those outside our traditional service territory, while continuing to strive to enhance the experience of our existing customers. The customer retention strategy remains focused on continuing to implement initiatives to deliver world-class customer service and improve the overall customer experience;

• Establishing TXU Energy as the most innovative retailer in the Texas market by continuing to develop tailored product offerings to meet customer needs. Since the Merger, TXU Energy has invested more than $100 million in retail initiatives aimed at helping consumers conserve energy and demand-side management initiatives that are intended to moderate consumption and reduce peak demand for electricity, and

• Focusing business market initiatives largely on programs targeted to retain the existing highest-value customers and to recapture customers who have switched REPs. Initiatives include maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improved customer service, aided by an enhanced customer management system, new product price/service offerings and a multichannel approach for the small business market.

Financial Services Reform Legislation

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

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

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. Based on our assessments, we are not a Swap Dealer or Major Swap Participant. However, 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. 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.

Certain issues remain uncertain; for example, the Financial Reform Act requires the posting of collateral for uncleared swaps, but the final rule for margin requirements for Swap Dealers and Major Swap Participants has not been issued. 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. Also, in November 2013 the CFTC proposed certain changes to its Position Limit Rule (PLR), which was vacated and remanded to the CFTC by the District Court for the District of Columbia. The PLR provides for specific position limits related to futures and Swap contracts that we utilize in our hedging activities. The proposed PLR will require that we comply with the portion of the PLR applicable to these contracts, which will result in increased monitoring and reporting requirements and can also impact the types of contracts that we utilize as hedging instruments in our operations.

56

Exposures Related to Nuclear Asset Outages

Our nuclear assets are comprised of two generation units at the Comanche Peak plant site, each with an installed nameplate capacity of 1,150 MW. These units represent approximately 15% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated (based upon forward electricity market prices for 2014 at December 31, 2013) to be approximately $1.7 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 11 to Financial Statements.

The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review and regulation by the NRC, including potential regulation as a result of the NRC's ongoing analysis and response to the effects of the natural disaster on nuclear generation facilities in Japan in 2010, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs, and it may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down the Comanche Peak units as a precautionary measure.

We participate in industry groups and with regulators to remain current on the latest developments in nuclear safety, operation and maintenance and on emerging threats and mitigating techniques. These groups include, but are not limited to, the NRC and the Institute of Nuclear Power Operations (INPO). We also apply the knowledge gained by continuing to invest in technology, processes and services to improve our operations and detect, mitigate and protect our nuclear generation assets. The Comanche Peak plant has not experienced an extended unplanned outage, and management continues to focus on the safe, reliable and efficient operations at the plant.

Adequacy of Generation Resources in ERCOT

Reserve margin represents the percentage by which estimated system generation capacity exceeds anticipated peak load. ERCOT's current target reserve margin is 13.75%, which is a level anticipated to provide reasonable assurance of reliability of electricity supply. ERCOT publishes a Capacity, Demand and Reserves report (CDR Report) twice each year that projects the reserve margin in ERCOT over a ten year horizon. In its February 2014 CDR Report, ERCOT projected that reserve margins in the ERCOT market would not fall below the current target reserve margin of 13.75% until 2017. The CDR Report projects reserve margins of 12.8% in 2017, 13.4% in 2018 and 10.9% in 2019. The February 2014 CDR Report employed revised forecast methodologies that indicated a slower pace of peak demand growth as compared to the May 2013 CDR Report, which projected that reserve margins would fall below the target reserve margin beginning in 2015.

In August 2013, the PUCT directed ERCOT to work with the Brattle Group, an independent consulting firm, to conduct a study of the ERCOT wholesale electricity market and estimate an economically optimal planning reserve margin. In January 2014, the Brattle Group released its study and concluded that the economically optimal reserve margin, which balances the marginal costs of additional reserves against the marginal costs of unserved load, is approximately 10%, while the current ERCOT market design would generally result in a reserve margin of 11.5% over the long-term. The report further concluded that mandating a planning reserve margin in the 13% to 15% range would result in modest cost increases to electricity consumers while offering meaningful risk mitigation benefits for both policymakers and market participants.

Forecasting generation resource availability and consumption demand is inherently complex, particularly considering the volatility of natural gas prices, inevitable weather extremes and changing environmental rules and regulations. We believe that the prevailing wholesale electricity market conditions in ERCOT currently result in wholesale prices that do not provide adequate economic returns for the development of the additional generation resources that will ultimately be needed to support economic and population growth and electricity reliability in Texas.

57

We and the ERCOT market broadly experienced the effects of weather extremes and reduced generation availability in 2011. Severe cold weather in North Texas in February 2011 caused some generation units to go off-line, including certain of our generation units, resulting in electricity outages and reduced customer satisfaction, as well as loss of revenues and higher costs as we worked to bring our units back on line. The unusually hot 2011 summer in Texas drove higher electricity demand that resulted in wholesale electricity price spikes and requests to consumers to conserve energy during peak load periods, while increasing stress on generation and other electricity grid assets. Unplanned generation unit outages during periods of high electricity demand, combined with low reserve margins, increase the risk of spikes in wholesale power prices and could have significant adverse effects on our results of operations, liquidity and financial condition. Other weather events such as drought that often accompanies hot weather extremes reduces cooling water levels at our generation facilities and can ultimately result in reduced output. Heavy rains present other challenges as flooding in other states can halt rail transportation of coal, and local flooding can reduce our lignite mining capabilities, resulting in fuel shortages and reduced generation.

While there can be no assurance that we can fully mitigate the risks of severe weather events and unanticipated generation unit outages, we have emergency preparedness, business continuity and regulatory compliance policies and procedures that are continuously reviewed and updated to address these risks. Further, we have initiatives in place to improve monitoring of generation equipment maintenance and readiness to increase system reliability and help ensure generation availability. With the learnings from the winter and summer events of 2011, we have implemented new procedures and continuously evaluate plans to assure the highest possible delivery of generation during critical periods and also deliver demand side management responses. We continue to work with ERCOT and other market participants to develop policies and protocols that provide appropriate pricing signals that encourage the development of generation resources sufficient to support demand growth in ERCOT and mitigate the effects of weather extremes and other unexpected events that can disrupt electricity reliability. See "Significant Activities and Events and Items Influencing Future Performance – Recent PUCT/ERCOT Actions."

Cyber Security and Infrastructure Protection Risk

A breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could materially affect our reputation, expose the company to legal claims or impair our ability to execute on business strategies.

We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques. These groups include, but are not limited to, the US Cyber Emergency Response Team, the National Electric Sector Cyber Security Organization, the NRC and NERC.

While the company has not experienced a cyber event causing any material operational, reputational or financial impact, we recognize the growing threat within our industry and are proactively making strategic investments in our perimeter and internal defenses, cyber security operations center and regulatory compliance activities. We also apply the knowledge gained through industry and government organizations to continuously improve our technology, processes and services to detect, mitigate and protect our cyber assets.

58

APPLICATION OF CRITICAL ACCOUNTING POLICIES

Our significant accounting policies are discussed in Note 1 to Financial Statements. We follow accounting principles generally accepted in the US. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Push Down of Merger-Related Debt

Merger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing at the time of the Merger. Debt issued in exchange for Merger-related debt is considered Merger-related. Debt issuances are considered Merger-related debt to the extent the proceeds are used to repurchase Merger-related debt. Merger-related debt of EFH Corp. (parent) that is fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH 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 EFCH's financial statements. Merger-related debt of EFH Corp. held by its subsidiaries is not subject to push down. The amount reflected in EFCH's balance sheet represents 50% of the EFH Corp. Merger-related debt guaranteed by EFCH. 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., EFCH records the settlement of such amounts (net of income tax) as noncash capital contributions from EFH Corp. As a result of transactions completed in January 2013, $60 million principal amount of debt remains subject to push down at December 31, 2013. See Note 10 to Financial Statements.

Impairment of Goodwill and Other Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. One of those indications is a current expectation that "more likely than not" a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. For our nuclear and lignite/coal fueled generation assets, another possible indication would be an expectation of continuing long-term declines in natural gas prices and/or market heat rates. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing. In 2013, we evaluated the recoverability of the assets of our joint venture to develop additional nuclear generation units. See Note 8 to Financial Statements for a discussion of the impairment of those assets.

Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (we have selected December 1) or whenever events or changes in circumstances indicate an impairment may exist, such as the triggers to evaluate impairments to long-lived assets discussed above. As required by accounting guidance related to goodwill and other intangible assets, we have allocated goodwill to our reporting unit, which essentially consists of TCEH, and goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit's operating assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.

59

The determination of enterprise value involves a number of assumptions and estimates. We use a combination of fair value inputs to estimate enterprise values of our reporting units: internal discounted cash flow analyses (income approach), and comparable publicly traded company values (market approach). The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance and retail sales volume trends, as well as determination of a terminal value using the Gordon Growth Model. Another key variable in the income approach is the discount rate, or weighted average cost of capital, applied to the forecasted cash flows. The determination of the discount rate takes into consideration the capital structure, debt ratings and current debt yields of comparable public companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. Enterprise value estimates based on comparable company values involve using trading multiples of EBITDA of those selected public companies to derive appropriate multiples to apply to the EBITDA of the reporting units. This approach requires an estimate, using historical acquisition data, of an appropriate control premium to apply to the reporting unit values calculated from such multiples. Critical judgments include the selection of comparable companies and the weighting of the value metrics in developing the best estimate of enterprise value.

Since the Merger, we have recorded goodwill impairment charges totaling $14.370 billion, including $1.0 billion recorded in 2013, $1.2 billion recorded in 2012, $4.1 billion recorded in 2010 and $8.070 billion recorded largely in 2008. The total impairment charges represent 78% of the goodwill balance resulting from purchase accounting for the Merger. The impairments in 2013, 2012 and 2010 reflected the effect of lower wholesale power prices in ERCOT, driven by the sustained decline in forward natural gas prices. The impairment in 2008 primarily arose from the dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies in the second half of 2008. See Note 4 to Financial Statements for additional discussion of goodwill impairments.

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We estimate fair value as described in Note 13 to Financial Statements and discussed under "Fair Value Measurements" below.

Accounting standards related to derivative instruments and hedging activities allow for "normal" purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. "Normal" purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the election as normal is made. Hedge accounting designations are made with the intent to match the accounting recognition of the contract's financial performance to that of the transaction the contract is intended to hedge. The intent of our hedging activity is generally to enter into positions that reduce our exposure to future variable cash flows, and such hedges are referred to as cash flow hedges.

Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in other comprehensive income are reclassified to net income in the period that the hedged transactions are recognized in net income. Although at December 31, 2013 and 2012 we did not have any derivatives designated as cash flow hedges, we continually assess potential hedge elections and could, as we have in the past, designate positions such as natural gas hedges and interest rate swaps as cash flow hedges in the future. See further discussion of natural gas hedging activities and interest rate swap transactions under "Significant Activities and Events and Items Influencing Future Performance."

60

The following tables provide the effects on both the statements of consolidated income (loss) and comprehensive income (loss) of accounting for those derivative instruments (both commodity-related and interest rate swaps) that we have determined to be subject to fair value measurement under accounting standards related to derivative instruments.

	Year Ended December 31,
	2013			2012			2011
Amounts recognized in net income (loss) (after-tax):
Unrealized net gains on positions marked-to-market in net income	$	649		$	287		$	205
Unrealized net losses representing reversals of previously recognized fair values of positions settled in the period	(668		)	(1,162		)	(696		)
Reclassifications of net losses on cash flow hedge positions from other comprehensive income	(6		)	(7		)	(19		)
Total net loss recognized	$	(25	)	$	(882	)	$	(510	)
Amounts recognized in other comprehensive income (loss) (after-tax):
Reclassifications of net losses on cash flow hedge positions to net income	$	6		$	7		$	19

The effect of mark-to-market and hedge accounting for derivatives on the balance sheet is as follows:

	December 31,
	2013		2012
Commodity contract assets	$	788	$	2,047
Commodity contract liabilities	$	263	$	383
Interest rate swap assets	$	—	$	2
Interest rate swap liabilities	$	1,012	$	2,067
Net accumulated other comprehensive loss included in shareholders' equity (amounts after tax)	$	36	$	42

We report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the balance sheet. See Note 14 to Financial Statements.

Fair Value Measurements

We determine value under the fair value hierarchy established in accounting standards. We utilize several 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.

Under the fair value hierarchy, Level 1 and Level 2 valuations generally apply to our commodity-related contracts for natural gas, electricity and fuel, including coal and uranium, derivative instruments entered into for hedging purposes, securities associated with the nuclear decommissioning trust and interest rate swaps intended to fix and/or lower interest payments on our debt. Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

Our Level 3 valuations generally apply to interest rate swaps intended to fix and/or lower interest payments on TCEH's debt, congestion revenue rights, certain coal contracts, options to purchase or sell electricity, and electricity purchase and sales agreements for which the valuations include unobservable inputs, including the hourly shaping of the price curve. Level 3 valuations use largely unobservable inputs, with little or no supporting market activity, and assets and liabilities are classified as Level 3 if such inputs are significant to the fair value determination. Valuation risk is mitigated through the performance of stress testing of the significant inputs to understand the impact that varying assumptions may have on the valuation and other review processes performed to ensure appropriate valuation.

61

As part of our valuation of assets subject to fair value accounting, counterparty credit risk is taken into consideration by measuring the extent of netting arrangements in place with the counterparty along with credit enhancements and the estimated credit ratings, default rate factors and debt trading values of the counterparty. Our valuation of liabilities subject to fair value accounting takes into consideration the market's view of our credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancements posted by us. We consider the credit risk adjustment to be a Level 3 input since judgment is used to assign credit ratings, recovery rate factors and default rate factors. The risk adjustment for our credit is what drove our interest rate swap valuations to be Level 3 in 2013.

Valuations of Level 3 assets and liabilities are sensitive to the assumptions used for the significant inputs. Where market data is available, the inputs used for valuation reflect that information as of our valuation date. In periods of extreme volatility, lessened liquidity or in illiquid markets, there may be more variability in market pricing or a lack of market data to use in the valuation process. An illiquid market is one in which little or no observable activity has occurred or one that lacks willing buyers.

Valuations of several of our Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing model inputs such as volatility factors and credit risk adjustments. At December 31, 2013 and 2012, a 10% change in electricity price (per MWh) assumptions across unobservable inputs would cause an approximate $3 million change in net Level 3 liabilities and $8 million change in net Level 3 assets, respectively. A 10% change in coal price assumptions across unobservable inputs would cause an approximate $4 million change in net Level 3 liabilities and $8 million change in net Level 3 assets, respectively. At December 31, 2013, a 5% increase in the nonperformance risk adjustment based on TCEH Senior Secured bond rates would cause an approximate $70 million change in net Level 3 liabilities. See Note 13 for discussion of TCEH interest rate swaps transfer into Level 3 effective September 30, 2013.

See Note 13 to Financial Statements for additional information about fair value measurements, including information on unobservable inputs and related valuation sensitivities and a table presenting the changes in Level 3 assets and liabilities for the years ended December 31, 2013, 2012 and 2011.

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. Determining whether or not to consolidate a VIE requires interpretation of accounting rules and their application to existing business relationships and underlying agreements. Amended accounting rules related to VIEs became effective January 1, 2010. 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 rights granted to the interest holders of the VIE to determine whether we have the right or obligation to absorb profit and loss from the VIE and the power to direct the significant activities of the VIE. See Note 3 to Financial Statements for information regarding our consolidated variable interest entities.

Revenue Recognition

Our revenue includes an estimate for unbilled revenue that represents estimated daily kWh consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using metered consumption as well as historical kWh usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $272 million, $260 million and $269 million at December 31, 2013, 2012 and 2011, respectively.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies. A significant contingency that we account for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions, effects of hurricanes and other natural disasters and customers' behaviors. Changes in customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of the estimation process. Historical results alone are not always indicative of future results, causing management to consider potential changes in customer behavior and make judgments about the collectability of accounts receivable. Bad debt expense, the substantial majority of which relates to our retail operations, totaled $33 million, $26 million and $56 million for the years ended December 31, 2013, 2012 and 2011, respectively.

62

Litigation contingencies also may require significant judgment in estimating amounts to accrue. We accrue liabilities for litigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable. No significant amounts have been accrued for such contingencies during the three-year period ended December 31, 2013. See Note 11 to Financial Statements for discussion of significant litigation.

Accounting for Income Taxes

EFH Corp. files a US federal income tax return that includes the results of EFCH and TCEH. 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 each of EFCH, TCEH and any other subsidiaries under the agreement 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.

Our income tax expense and related balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgments of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. EFH Corp.'s income tax returns are regularly subject to examination by applicable tax authorities. In management's opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination.

We recorded an income tax benefit totaling $80 million in the year ended December 31, 2013 related to resolution of IRS audit matters (see Note 5 to Financial Statements regarding uncertain tax positions).

See Notes 1, 5 and 6 to Financial Statements for discussion of income tax matters.

Depreciation and Amortization

Depreciation expense related to generation facilities is based on the estimates of fair value and economic useful lives as determined in the application of purchase accounting for the Merger. The accuracy of these estimates directly affects the amount of depreciation expense. Depreciation estimates are also affected by the level of componentization of major equipment categories. Determining components of certain equipment items requires judgments that can change over time. If future events indicate that the estimated lives are no longer appropriate, depreciation expense will be recalculated prospectively from the date of such determination based on the new estimates of useful lives.

The estimated remaining lives range from 19 to 56 years for the lignite/coal and nuclear fueled generation units.

Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 4 to Financial Statements for additional information.

Accounting in Reorganization

Consolidated financial statements for periods following commencement of the Chapter 11 Cases on April 29, 2014 will be prepared in accordance with Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, "Reorganizations," which contemplates the realization of assets and the satisfaction of liabilities on a going concern basis. However, as a result of the Chapter 11 Cases, such realization of assets and satisfaction of liabilities are subject to a number of uncertainties. ASC 852 will require the following:

• Reclassification of unsecured or under-secured pre-petition debt, including unamortized deferred financing costs and discounts/premiums associated with debt, and other liabilities to a separate line item in the balance sheet, called "Liabilities subject to compromise;"

• Nonaccrual of interest expense for financial reporting purposes, to the extent not paid during bankruptcy and not expected to be an allowable claim;

63

• Reporting in a new line in the statement of income of incremental costs of bankruptcy, such as professional fees, as well as adjustments of liabilities to allowed claim amounts and ultimately settlement amounts as a separate line item in the statement of income;

• Evaluation of actual or potential bankruptcy claims, which are not already reflected as a liability on the balance sheet, under ASC 450, "Contingencies." If valid unrecorded claims meeting the ASC 450 criteria are presented to us in future periods, we will accrue for these amounts at the expected amount of the allowed claim; and

• Upon emergence from Chapter 11 reorganization, "fresh-start accounting" under GAAP may be required. Under fresh-start accounting, the reorganization value of the entity would be allocated to the entity’s individual assets and liabilities on a fair value basis in conformity with the procedures specified by ASC 805, "Business Combinations."

64

RESULTS OF OPERATIONS

Sales Volume and Customer Count Data

	Year Ended December 31,						2013		2012
	2013		2012		2011		% Change		% Change
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential	22,791		23,283		27,337		(2.1	)	(14.8	)
Small business (a)	5,387		5,914		7,059		(8.9	)	(16.2	)
Large business and other customers	9,816		10,373		12,828		(5.4	)	(19.1	)
Total retail electricity	37,994		39,570		47,224		(4.0	)	(16.2	)
Wholesale electricity sales volumes (b)	38,320		34,524		34,496		11.0		0.1
Total sales volumes	76,314		74,094		81,720		3.0		(9.3	)
Average volume (kWh) per residential customer (c)	14,815		14,617		16,100		1.4		(9.2	)
Weather (North Texas average) – percent of normal (d):
Cooling degree days	103.0	%	114.7	%	132.7	%	(10.2	)	(13.6	)
Heating degree days	117.8	%	82.0	%	109.7	%	43.7		(25.3	)
Customer counts:
Retail electricity customers (end of period, in thousands) (e):
Residential	1,516		1,560		1,625		(2.8	)	(4.0	)
Small business (a)	176		176		185		—		(4.9	)
Large business and other customers	17		17		19		—		(10.5	)
Total retail electricity customers	1,709		1,753		1,829		(2.5	)	(4.2	)

___________

(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.

65

Revenue and Commodity Hedging and Trading Activities

	Year Ended December 31,								2013		2012
	2013			2012			2011		% Change		% Change
Operating revenues:
Retail electricity revenues:
Residential	$	2,984		$	2,918		$	3,377	2.3		(13.6	)
Small business (a)	680			738			896		(7.9	)	(17.6	)
Large business and other customers	675			717			997		(5.9	)	(28.1	)
Total retail electricity revenues	4,339			4,373			5,270		(0.8	)	(17.0	)
Wholesale electricity revenues (b)(c)	1,282			1,005			1,482		27.6		(32.2	)
Amortization of intangibles (d)	22			21			18		4.8		16.7
Other operating revenues	256			237			270		8.0		(12.2	)
Total operating revenues	$	5,899		$	5,636		$	7,040	4.7		(19.9	)
Net gain (loss) from commodity hedging and trading activities:
Realized net gains on settled positions	$	1,057		$	1,953		$	971
Unrealized net gains (losses)	(1,111		)	(1,564		)	40
Total	$	(54	)	$	389		$	1,011

___________

(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:

	Year Ended December 31,
	2013			2012			2011
Reported in revenues	$	(2	)	$	(1	)	$	—
Reported in fuel and purchased power costs	22			39			18
Net gain	$	20		$	38		$	18

(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.

66

Production, Purchased Power and Delivery Cost Data

	Year Ended December 31,									2013		2012
	2013			2012			2011			% Change		% Change
Fuel, purchased power costs and delivery fees ($ millions):
Fuel for nuclear facilities	$	173		$	175		$	160		(1.1	)	9.4
Fuel for lignite/coal facilities (a) (b)	869			816			992			6.5		(17.7	)
Total nuclear and lignite/coal facilities (a)	1,042			991			1,152			5.1		(14.0	)
Fuel for natural gas facilities and purchased power costs (a) (b)	292			323			426			(9.6	)	(24.2	)
Amortization of intangibles (c)	37			48			111			(22.9	)	(56.8	)
Other costs	196			194			309			1.0		(37.2	)
Fuel and purchased power costs	1,567			1,556			1,998			0.7		(22.1	)
Delivery fees	1,281			1,260			1,398			1.7		(9.9	)
Total	$	2,848		$	2,816		$	3,396		1.1		(17.1	)
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
Nuclear facilities	$	8.45		$	8.78		$	8.30		(3.8	)	5.8
Lignite/coal facilities (a) (d)	$	19.93		$	20.54		$	19.79		(3.0	)	3.8
Natural gas facilities and purchased power (a) (e)	$	46.62		$	45.06		$	53.26		3.5		(15.4	)
Delivery fees per MWh	$	33.57		$	31.75		$	29.52		5.7		7.6
Production and purchased power volumes (GWh):
Nuclear facilities	20,487			19,897			19,283			3.0		3.2
Lignite/coal facilities (f)	52,023			49,298			58,165			5.5		(15.2	)
Total nuclear and lignite/coal facilities	72,510			69,195			77,448			4.8		(10.7	)
Natural gas facilities	899			1,295			1,233			(30.6	)	5.0
Purchased power (g)	2,905			3,604			3,039			(19.4	)	18.6
Total energy supply volumes	76,314			74,094			81,720			3.0		(9.3	)
Capacity factors:
Nuclear facilities	101.7		%	98.5		%	95.7		%	3.2		2.9
Lignite/coal facilities (f)	74.1		%	70.0		%	83.5		%	5.9		(16.2	)
Total	80.2		%	76.4		%	86.2		%	5.0		(11.4	)

___________

(a) 2011 reflects reclassifications of start-up fuel to lignite/coal from natural gas facilities to conform to current period presentation.

(b) See note (b) to the "Revenue and Commodity Hedging and Trading Activities" table on previous page.

(c) 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.

(d) Includes depreciation and amortization of lignite mining assets (except for incremental depreciation in 2011 due to the CSAPR as discussed in Note 4 to Financial Statements), which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs and excludes unrealized amounts as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table on previous page.

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

(f) Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal fueled units totaling 12,460 GWh, 10,410 GWh and 4,290 GWh in 2013, 2012 and 2011, respectively.

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

67

Financial Results – Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Operating revenues increased $263 million, or 5%, to $5.899 billion in 2013.

Retail electricity revenues decreased $34 million, or 1%, to $4.339 billion reflecting a $174 million decline in sales volumes partially offset by $140 million in higher average prices. Sales volumes fell 4% reflecting declines in both business and residential markets. Business market volumes declined 7% reflecting changes in customer mix and competitive intensity. Residential volumes declined 2% reflecting a 3% decrease in customer counts, partially offset by higher average usage driven by the effect of colder weather in the fourth quarter 2013. 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 $277 million, or 28%, to $1.282 billion in 2013 reflecting a $166 million increase due to higher average prices and a $111 million increase in sales volumes. Higher average prices reflected an increase in natural gas prices. Wholesale sales volumes increased 11% reflecting higher generation volumes and lower volumes sold in our retail operations.

Fuel, purchased power costs and delivery fees increased $32 million, or 1%, to $2.848 billion in 2013. Lignite/coal fuel costs increased $53 million driven by higher generation volumes, higher lignite mining costs and lower lignite in the fuel blend, partially offset by lower western coal prices. Delivery fees increased $21 million reflecting higher rates, partially offset by lower retail volumes. Natural gas fuel costs decreased $32 million primarily reflecting decreases in natural gas fueled generation volumes. Amortization of the nuclear fuel intangible asset arising from purchase accounting at the Merger date decreased $8 million.

Lignite/coal fueled generation volumes increased 6% and nuclear fueled volumes increased 3% reflecting fewer unplanned and planned outage days.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $54 million in net losses and $389 million in net gains for the years ended December 31, 2013 and 2012, respectively, and includes the natural gas hedging positions discussed above under "Significant Activities and Events and Items Influencing Future Performance - Natural Gas Hedging Program," as well as other hedging positions.

	Year Ended December 31, 2013
	Net Realized Gains		Net Unrealized Losses			Total
Hedging positions	$	1,055	$	(1,090	)	$	(35	)
Trading positions	2		(21		)	(19		)
Total	$	1,057	$	(1,111	)	$	(54	)

	Year Ended December 31, 2012
	Net Realized Gains		Net Unrealized Losses			Total
Hedging positions	$	1,885	$	(1,542	)	$	343
Trading positions	68		(22		)	46
Total	$	1,953	$	(1,564	)	$	389

The decreases in net realized gains and unrealized losses reflected lower volumes and prices of maturing natural gas hedging positions. 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 $20 million and $38 million in net gains in 2013 and 2012, respectively (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).

Operating costs decreased $7 million, or 1%, to $881 million in 2013. The decrease reflected $8 million in lower lease expense due to purchase of the interest in a trust holding certain combustion turbines and $8 million in lower information technology project costs, partially offset by $7 million in higher nuclear generation costs driven by the scope of planned outage maintenance projects and $4 million in higher maintenance costs associated with lignite/coal fueled generation unit outages.

68

SG&A expenses increased $22 million, or 3%, to $681 million in 2013. The increase reflected $63 million in legal and consulting costs in 2013 associated with our debt restructuring initiatives, compared to $11 million in 2012. This increase is partially offset by $29 million in lower employee-related costs driven by lower incentive compensation expenses.

In 2013 and 2012, impairments of goodwill of $1.0 billion and $1.2 billion, respectively, were recorded as discussed in Note 4 to Financial Statements.

Other income totaled $9 million in 2013 and $13 million in 2012. See Note 7 to Financial Statements.

Other deductions totaled $162 million in 2013 and $188 million in 2012. Other deductions in 2013 include a $140 million impairment of the assets of the nuclear generation development joint venture and $10 million in other asset impairments. Other deductions in 2012 included a $141 million charge related to pension plan actions discussed in Note 15 to Financial Statements and a $24 million impairment of mineral interest assets as a result of lower natural gas drilling activity and prices. See Notes 7 and 8 to Financial Statements.

Interest income decreased $41 million to $5 million in 2013. The decrease was driven by EFH Corp.'s settlement of the TCEH Demand Notes. See Note 17 to Financial Statements.

Interest expense and related charges decreased $909 million, or 32%, to $1.933 billion in 2013. The decrease was driven by $887 million in higher unrealized mark-to-market net gains on interest rate swaps in 2013 and lower interest expense due to a reduction in debt pushed down. See Note 13 to Financial Statements regarding nonperformance risk adjustment related to interest rate swaps. This change was partially offset by $82 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 $737 million and $924 million on pretax losses in 2013 and 2012, respectively. Excluding the $80 million in total income tax benefit recorded in 2013 related to resolution of IRS audit matters, the 2013 impairment of the assets of the nuclear generation development joint venture and the nondeductible goodwill impairment charges in both years, the effective tax rates were 33.7% and 33.8% in 2013 and 2012, respectively. See Note 8 to Financial Statements for discussion of the impairment of the joint venture's assets. See Note 4 to Financial Statements for discussion of goodwill impairments. See Note 5 to Financial Statements for discussion of uncertain tax positions. See Note 6 to Financial Statements for reconciliation of these comparable effective rates to the US federal statutory rate.

Net loss decreased $691 million to $2.317 billion in 2013. The net losses in 2013 and 2012 reflected goodwill impairment charges of $1.0 billion and $1.2 billion, respectively. Other factors contributing to the change included $887 million in higher unrealized mark-to-market net gains on interest rate swaps, $231 million in higher revenues net of fuel, purchased power and delivery fees, a $141 million pension charge in 2012 and an $80 million income tax benefit in 2013 due to resolution of IRS audit matters. These items were partially offset by $54 million in net losses from commodity hedging and trading activities in 2013 compared to $389 million in net gains in 2012, as well as the $140 million impairment of the assets of the nuclear generation development joint venture.

Net loss attributable to noncontrolling interests of $107 million represents the noncontrolling interest share of the impairment of the assets of the nuclear generation development joint venture.

69

Financial Results – Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Operating revenues decreased $1.404 billion, or 20%, to $5.636 billion in 2012.

Retail electricity revenues decreased $897 million, or 17%, to $4.373 billion reflecting an $854 million decline in sales volumes and $43 million in lower average prices. Sales volumes fell 16% reflecting declines in both the residential and business markets. Residential volumes were lower due to much milder weather and a 4% decrease in customer counts driven by competitive activity. Business market volumes were lower due to a change in customer mix and lower customer counts driven by competitive intensity. Overall average retail pricing declined 1% driven by business markets.

Wholesale electricity revenues decreased $477 million, or 32%, to $1.005 billion in 2012 driven by lower average prices, which reflected much milder weather, including the effects on prices of very hot weather in the summer of 2011, as well as lower natural gas prices.

Fuel, purchased power costs and delivery fees decreased $580 million, or 17%, to $2.816 billion in 2012. Lignite/coal fuel costs decreased $176 million driven by an increase in economic backdown and planned and unplanned generation unit outages. Purchased power and other costs (including ancillary services) decreased $124 million reflecting lower wholesale electricity prices and natural gas prices. Delivery fees declined $138 million reflecting lower retail volumes. Natural gas fuel costs decreased $63 million reflecting lower prices. Amortization of intangibles decreased $63 million reflecting lower amortization of emission allowances due to an impairment recorded in the third quarter 2011 and expiration of contracts fair-valued under purchase accounting at the Merger date.

A 15% decrease in lignite/coal fueled generation volumes was driven by increased economic backdown and generation unit planned and unplanned outages, while nuclear fueled generation volumes increased 3% reflecting one refueling outage in 2012 and two in 2011.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities, which totaled $389 million and $1.011 billion in net gains for the years ended December 31, 2012 and 2011, respectively, and includes the natural gas hedging positions discussed above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program," as well as other hedging positions.

	Year Ended December 31, 2012
	Net Realized Gains		Net Unrealized Losses			Total
Hedging positions	$	1,885	$	(1,542	)	$	343
Trading positions	68		(22		)	46
Total	$	1,953	$	(1,564	)	$	389

	Year Ended December 31, 2011
	Net Realized Gains		Net Unrealized Gains		Total
Hedging positions	$	912	$	21	$	933
Trading positions	59		19		78
Total	$	971	$	40	$	1,011

While unrealized losses were recorded in both 2012 and 2011 to reverse previously recorded unrealized gains on positions settled in the periods, the effect of greater declines in natural gas prices in 2011 on a larger hedge position resulted in net unrealized gains in 2011.

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 $38 million and $18 million in net gains in 2012 and 2011, respectively (as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above).

Operating costs decreased $36 million, or 4%, to $888 million in 2012. The decrease reflected $17 million in lower nuclear generation maintenance costs reflecting one refueling outage in 2012 and two in 2011, $10 million in lower costs related to new systems implementation and process improvements at generation facilities and $5 million in lower lignite-fueled generation maintenance costs reflecting timing and scope of work.

70

Depreciation and amortization decreased $127 million, or 9%, to $1.343 billion in 2012. The decrease reflected increased useful lives and retirements of certain generation assets and accelerated mine asset depreciation in 2011 due to then planned mine closures needed to comply with the CSAPR.

SG&A expenses decreased $69 million, or 9%, to $659 million in 2012. The decrease reflected $30 million in lower bad debt expense due to improved collection and customer care processes, customer mix and lower revenues, $25 million in lower retail marketing and related expense and $21 million in lower employee compensation and benefits costs.

In 2012, a $1.2 billion impairment of goodwill was recorded as discussed in Note 4 to Financial Statements.

Other income totaled $13 million in 2012 and $48 million in 2011. Other income in 2012 included a $6 million fee received to novate certain hedge transactions between counterparties. Other income in 2011 included $21 million related to the settlement of bankruptcy claims against a counterparty, $7 million for a property damage claim and $6 million from a franchise tax refund related to prior years. See Note 7 to Financial Statements.

Other deductions totaled $188 million in 2012 and $524 million in 2011. Other deductions in 2012 included a $141 million charge related to pension plan actions discussed in Note 15 to Financial Statements and a $24 million impairment of mineral interest assets as a result of lower natural gas drilling activity and prices. Other deductions in 2011 resulting from the issuance of the CSAPR included a $418 million impairment charge for excess SO₂ emission allowances due to emission allowance limitations under the CSAPR and a $9 million impairment of mining assets. Other deductions in 2011 also included $86 million in third party fees related to the amendment and extension of the TCEH Senior Secured Facilities. See Note 7 to Financial Statements.

Interest income decreased $40 million, or 47%, to $46 million. The decrease was driven by lower intercompany debt balances.

Interest expense and related charges decreased $950 million, or 25%, to $2.842 billion in 2012. The decrease was driven by a $978 million favorable change in unrealized mark-to-market net gains/losses on interest rate swaps, reflecting a mark-to-market gain of $166 million in 2012 compared to an unrealized mark-to-market loss of $812 million in 2011.

Income tax benefit totaled $924 million and $943 million on pretax losses in 2012 and 2011, respectively. Excluding the $1.2 billion nondeductible goodwill impairment charge recorded in 2012, the effective rate was 33.8% and 34.4% in 2012 and 2011, respectively. The decrease in the effective rate was driven by the absence of the domestic production deduction due to an expected loss for federal income tax purposes in 2012 compared to income in 2011.

Net loss increased $1.206 billion to $3.008 billion in 2012 reflecting the $1.2 billion goodwill impairment charge, lower revenues net of fuel, purchased power and delivery fees as well as lower results from commodity hedging and trading activities, partially offset by a favorable change in unrealized mark-to-market net gains/losses on interest rate swaps and the emission allowances impairment in 2011.

71

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

The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2013, 2012 and 2011. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.093 billion and $1.521 billion in unrealized net losses in 2013 and 2012, respectively, and $58 million in unrealized net gains in 2011, 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.

	Year Ended December 31,
	2013			2012			2011
Commodity contract net asset at beginning of period	$	1,664		$	3,190		$	3,097
Settlements of positions (a)	(1,039		)	(1,800		)	(1,081		)
Changes in fair value of positions in the portfolio (b)	(54		)	279			1,139
Other activity (c)	(46		)	(5		)	35
Commodity contract net asset at end of period	$	525		$	1,664		$	3,190

____________

(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 natural gas hedging positions (see discussion above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Hedging Program"), as well as changes in the 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 December 31, 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 December 31, 2013
Source of fair value	Less than 1 year			1-3 years			Total
Prices actively quoted	$	(68	)	$	(2	)	$	(70	)
Prices provided by other external sources	556			—			556
Prices based on models	36			3			39
Total	$	524		$	1		$	525
Percentage of total fair value	100		%	—		%	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 13 to Financial Statements for fair value disclosures and discussion of fair value measurements.

72

FINANCIAL CONDITION

Operating Cash Flows

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 — Cash used in operating activities totaled $271 million and $240 million in 2013 and 2012, respectively. The change of $31 million reflected a decrease of $896 million in net realized gains from commodity hedging and trading activities and an increase of $137 million in interest payments. Key offsetting factors included approximately $600 million in favorable changes in accounts payable, prepaid expenses and accrued liability accounts due primarily to timing of payments, an approximately $200 million effect of increased wholesale electricity prices and a $156 million change in margin deposits.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 — Cash used in operating activities totaled $240 million in 2012 compared to cash provided by operating activities of $1.236 billion in 2011. The change of $1.476 billion reflected net changes in margin deposits totaling $1.0 billion. The change in margin deposits largely relates to the natural gas hedging positions; in 2012 more margin deposits were returned to counterparties due to settlement of maturing positions than were received from counterparties due to decreases in natural gas prices, while activity in 2011 reflected the opposite. The change in cash flows also reflected an increase of $194 million in working capital used reflecting timing of accounts payable and accrued expense payments, $95 million in higher cash interest payments and cash settlements with EFH Corp. of $91 million related to pension plan actions (see Note 15 to Financial Statements).

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $166 million, $178 million and $237 million for the years ended December 31, 2013, 2012 and 2011, 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.

Financing Cash Flows

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 — Cash used in financing activities totaled $174 million in 2013 and cash provided by financing activities totaled $1.161 billion in 2012. Activity in 2013 reflected scheduled repayments of debt and an $82 million repayment resulting from the termination of the accounts receivable securitization program (see Note 9 to Financial Statements). Activity in 2012, including an increase in borrowings of $1.384 billion under the TCEH Revolving Credit Facility, is discussed immediately below.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 — Cash provided by financing activities totaled $1.161 billion in 2012 compared to cash used in financing activities of $973 million in 2011. Activity in 2012 reflected an increase in borrowings of $1.384 billion under the TCEH Revolving Credit Facility (see Note 10 to Financial Statements), partially offset by a $159 million payment to settle transition bond reimbursement agreements with Oncor (see Note 17 to Financial Statements). Activity in 2011 reflected the amendment and extension of the TCEH Senior Secured Facilities, including approximately $800 million in transaction costs, and repayment of certain debt securities, including $415 million of pollution control revenue bonds.

See Note 10 to Financial Statements for further detail of borrowings and debt.

Investing Cash Flows

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 — Cash provided by investing activities totaled $16 million in 2013 and $134 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 17 to Financial Statements). Capital expenditures (excluding nuclear fuel purchases) decreased $159 million to $472 million in 2013 reflecting decreases in generation environmental-related spending and other capital projects, partially offset by increased spending on lignite mine development. Nuclear fuel purchases decreased $97 million to $116 million due to timing of purchases for refueling cycles. Investing activities in 2013 also included $40 million used to acquire the owner participant interest in a trust established to lease six natural gas combustion turbines to TCEH. See Note 10 to Financial Statements and discussion below under "Debt Activity" regarding the debt obligation of the trust.

73

Capital expenditures, including nuclear fuel, in 2013 totaled $588 million and consisted of:

• $366 million for major maintenance, primarily in existing generation operations;

• $93 million for environmental expenditures related to generation units;

• $116 million for nuclear fuel purchases, and

• $13 million for information technology, nuclear generation development and other corporate investments.

Cash capital expenditures in 2013 are net of $12 million of reimbursements from the DOE related to dry cask storage. We expect to be reimbursed for our allowable costs of constructing dry cask storage for spent nuclear fuel through 2016 in accordance with a settlement agreement with the DOE.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 — Cash provided by investing activities totaled $134 million in 2012 compared to cash used of $190 million in 2011. Net repayments of notes due from affiliates increased $580 million in 2012 to $926 million (see Note 17 to Financial Statements). Capital expenditures (excluding nuclear fuel purchases) increased $101 million to $631 million in 2012 reflecting increased environmental-related spending. Nuclear fuel purchases increased $81 million to $213 million due to advance purchases necessary to fabricate fuel assemblies in time for the two nuclear unit refueling outages planned for 2014. Other decreases reflected an asset sale in 2011 and changes in restricted cash.

Capital expenditures, including nuclear fuel, in 2012 totaled $844 million and consisted of:

• $339 million for major maintenance, primarily in existing generation operations;

• $270 million for environmental expenditures related to generation units;

• $213 million for nuclear fuel purchases, and

• $22 million for information technology, nuclear generation development and other corporate investments.

Cash capital expenditures in 2012 are net of $19 million of reimbursements from the DOE related to dry cask storage.

Debt Activity— Debt activities during the year ended December 31, 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	$	(176	)
EFCH (b)	—		(11		)
EFH Corp. (pushed down to EFCH) (c)	—		(420		)
Total	$	385	$	(607	)

____________

(a) Borrowings include $340 million 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 include the repayment of $82 million in net borrowings under the accounts receivable securitization program (see Note 9 to Financial Statements), $82 million of payments of principal at scheduled maturity or mandatory tender dates and $12 million of payments of capital lease liabilities. See Note 10 to Financial Statements.

(b) Settlements represent payments of principal at scheduled maturity dates.

(c) Settlements represent the effects of debt cancellations and other transactions discussed in Note 10 to Financial Statements.

See Note 10 to Financial Statements for further detail of debt and other financing arrangements.

74

Available Liquidity — The following table summarizes changes in available liquidity for the year ended December 31, 2013.

	Available Liquidity
	December 31, 2013		December 31, 2012		Change
Cash and cash equivalents (a)	$	746	$	1,175	$	(429	)
TCEH Letter of Credit Facility	195		183		12
Total liquidity	$	941	$	1,358	$	(417	)

___________

(a) Cash and cash equivalents in 2013 and 2012 exclude $945 million and $947 million, respectively, of restricted cash held for letter of credit support.

The decrease in available liquidity of $417 million in the year ended December 31, 2013 reflected $588 million in cash used for capital expenditures, including nuclear fuel purchases, $273 million in cash used in operating activities, including $2.7 billion in interest payments, $187 million in cash used in repayment of TCEH and EFCH borrowings and $40 million used to acquire the interest in a combustion turbine lease trust, partially offset by EFH Corp.'s settlement of its borrowings from TCEH under the TCEH Demand Notes, which totaled $698 million at December 31, 2012.

At April 25, 2014, cash and cash equivalents totaled $426 million at TCEH.

Liquidity After the Bankruptcy Filing — Subject to certain exceptions under the Bankruptcy Code, the Bankruptcy Filing automatically enjoined, or stayed, the continuation of most pending judicial or administrative proceedings and the filing of other actions against the Debtors or their property to recover on, collect or secure a claim arising prior to the date of the Bankruptcy Filing (including with respect to our debt instruments).

TCEH has received a binding commitment, subject to certain customary conditions, from certain institutions for a DIP Facility as discussed in Note 10 to Financial Statements. The TCEH DIP Facility provides for $4.5 billion in senior secured, super-priority financing. We cannot be certain that the Bankruptcy Court will authorize entry into the DIP Facility.

We have incurred and expect to continue to incur significant costs associated with the Bankruptcy Filing and our reorganization, but we cannot accurately predict the effect the Bankruptcy Filing will have on our operations, liquidity, financial position and results of operations. Based upon our current internal financial forecasts, we believe that we will have sufficient amounts available under the DIP Facility, plus cash generated from operations, to fund our anticipated cash requirements through at least the end of 2014.

Liquidity Needs, Including Capital Expenditures — Capital expenditures and nuclear fuel purchases for 2014 are expected to total approximately $650 million and include:

• $525 million for investments in generation facilities, including approximately:

• $450 million for major maintenance and

• $75 million for environmental expenditures related to the MATS and other regulations;

• $100 million for nuclear fuel purchases and

• $25 million for information technology and other corporate investments.

Pension and OPEB Plan Funding —See Note 15 to Financial Statements.

Liquidity Effects of Commodity Hedging and Trading Activities —At December 31, 2013, over 95% of the natural gas hedging positions, discussed above under "Significant Activities and Events and Items Influencing Future Performance — Natural Gas Hedging Program," were 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, the effect of which is a significant reduction in the liquidity exposure associated with collateral posting requirements for those hedging transactions. We have entered into other commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. TCEH uses cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 10 to Financial Statements for more information about the TCEH Senior Secured Facilities and TCEH Senior Secured Notes.

75

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 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 December 31, 2013, 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 December 31, 2013, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $93 million in cash has been posted with counterparties as compared to $71 million posted at December 31, 2012;

• $302 million in cash has been received from counterparties as compared to $600 million received at December 31, 2012;

• $317 million in letters of credit have been posted with counterparties, as compared to $376 million posted at December 31, 2012, and

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

Because certain agreements related to these activities are deemed to be "forward contracts" under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements. If the agreements are terminated, such cash and letter of credit postings may be used in the ultimate settlement of the positions.

Income Tax Matters — EFH Corp. files a US federal income tax return that includes the results of EFCH and TCEH. EFH Corp. (parent entity) 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.

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.

76

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 annual report on Form 10-K.

Income Tax Payments — In the next twelve months, income tax payments to EFH Corp. under the Federal and State Income Tax Allocation Agreement related to the Texas margin tax are expected to total approximately $30 million, and we do not expect to make any payments to EFH Corp. related to federal income taxes. Net payments totaled $137 million, $84 million and $123 million for the years ended December 31, 2013, 2012 and 2011, respectively. (See Note 17 to Financial Statements.)

We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions, but expect that no material federal income tax payments related to such positions will be made in the next twelve months (see Note 5 to Financial Statements).

Interest Rate Swap Transactions — See Note 10 to Financial Statements for discussion of TCEH's interest rate swaps.

Accounts Receivable Securitization Program — In October 2013, we terminated the Accounts Receivable Securitization Program and repaid all outstanding obligations under the program. See Note 9 to Financial Statements.

Capitalization — Our capitalization ratios consisted of 187.9% and 152.2% debt, less amounts with contractual maturity dates in the next twelve months, and (87.9)% and (52.2)% membership interests and common stock equity, at December 31, 2013 and 2012, respectively. Total debt to capitalization was 161.4% and 146.9% at December 31, 2013 and 2012, respectively.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The Bankruptcy Filing constituted an event of default under the agreements governing the debt of EFH Corp. and its subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities. The creditors are, however, stayed from taking any action against the Debtors as a result of such defaults under the Bankruptcy Code. See Note 10 to Financial Statements for discussion of covenants related to the DIP Facility.

Material Credit Rating Covenants and Creditworthiness Effects on Liquidity — 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 December 31, 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 $9 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 December 31, 2013, TCEH posted letters of credit in the amount of $61 million, which are subject to adjustments.

The RCT has rules in place to assure that parties can meet their mining reclamation obligations, including through self-bonding when appropriate. As a result of the Bankruptcy Filing, TCEH notified the RCT that its Luminant Mining subsidiary no longer qualifies to self-bond and, to collateralize its mining reclamation obligation, will be submitting to the RCT a collateral bond in an amount equal to or in excess of its reclamation bonding obligation. See Note 10 to Financial Statements regarding the DIP Facility. Collateral support 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 18 to Financial Statements, our recorded mining reclamation liability totaled $98 million at December 31, 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 $100 million at December 31, 2013 (which is subject to daily adjustments based on settlement activity with ERCOT).

77

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.

Material Cross Default/Acceleration Provisions — Certain of our financing arrangements contain provisions that 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. The Bankruptcy Filing triggered defaults on our debt obligations, but pursuant to the Bankruptcy Code, the creditors are stayed from taking any actions against the Debtors as a result of such defaults.

Under the terms of a TCEH rail car lease, which has $38 million in remaining lease payments at December 31, 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 Bankruptcy Code, the lessors are stayed from taking any action against the Debtors as a result of the default. However, the noteholders under the related trust agreements may not be prevented from taking actions against TCEH under the Bankruptcy Code.

Under the terms of another TCEH rail car lease, which has $41 million in remaining lease payments at December 31, 2013 and terminates in 2029, 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. Under the Bankruptcy Code, the lessors are stayed from taking any action against the Debtors as a result of the default. However, the noteholders under the related trust agreements may not be prevented from taking actions against TCEH under the Bankruptcy Code.

Contractual Obligations and Commitments— The following table summarizes our contractual cash obligations at December 31, 2013 (see Notes 10 and 11 to Financial Statements for additional disclosures regarding these debt and noncancellable purchase obligations). Prepetition obligations (i.e. obligations incurred or accrued prior to the Bankruptcy Filing) are being administered by the Bankruptcy Court.

Contractual Cash Obligations:	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Debt – principal, including capital leases (a)	$	32,450	$	—	$	—	$	—	$	32,450
Operating leases	26		50		66		151		293
Obligations under commodity purchase and services agreements (b)	780		881		544		678		2,883
Total contractual cash obligations	$	33,256	$	931	$	610	$	829	$	35,626

___________

(a) Includes $2.054 billion of borrowings under the TCEH Revolving Credit Facilities. Excludes unamortized premiums and discounts and fair value premiums and discounts related to purchase accounting. Contractual interest payments are excluded. Based on interest rates in effect and debt balances outstanding as of December 31, 2013, hypothetical projected contractual interest payments would be approximately $2.494 billion for 2014, including net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect at December 31, 2013.

(b) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the year-end 2013 price for all periods except where contractual price adjustment or index-based prices are specified.

The following are not included in the table above:

• arrangements between affiliated entities and intercompany debt (see Note 17 to Financial Statements);

• individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included);

• contracts that are cancellable without payment of a substantial cancellation penalty;

• employment contracts with management, and

• liabilities related to uncertain tax positions totaling $193 million (as well as accrued interest totaling $11 million) discussed in Note 5 to Financial Statements as the ultimate timing of payment, if any, is not known.

78

Guarantees — See Note 11 to Financial Statements for discussion of guarantees.

79

OFF–BALANCE SHEET ARRANGEMENTS

See Notes 3 and 11 to Financial Statements regarding VIEs and guarantees, respectively.

COMMITMENTS AND CONTINGENCIES

See Note 11 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

There have been no recently issued accounting standards effective after December 31, 2013 that are expected to materially impact our financial statements.

80

Item 7A. 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 it markets or purchases. We actively manage the portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads (differences between the market price of electricity and its cost of production).

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

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.

81

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.

	Year Ended December 31,
	2013		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.

	Year Ended December 31,
	2013		2012
Month-end average MtM VaR:	$	69	$	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.

	Year Ended December 31,
	2013		2012
Month-end average EaR:	$	36	$	109
Month-end high EaR:	$	71	$	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 in natural gas hedging positions due to maturities and lower market volatility.

82

Interest Rate Risk

The following table provides information concerning our financial instruments at December 31, 2013 and 2012 that are sensitive to changes in interest rates, which consist of debt obligations and interest rate swaps:

	2013 Total Carrying Amount			2013 Total Fair Value		2012 Total Carrying Amount			2012 Total Fair Value
Debt amounts (a):
Fixed rate debt amount	$	9,556		$	2,194	$	10,024		$	3,955
Average interest rate (b)	11.11		%			11.05		%
Variable rate debt amount	$	20,788		$	14,394	$	20,448		$	13,903
Average interest rate (b)	4.50		%			4.51		%
Total debt	$	30,344		$	16,588	$	30,472		$	17,858
Debt swapped to fixed (c):
Amount (d)	$	30,790				$	31,060
Average pay rate	8.24		%			8.37		%
Average receive rate	4.78		%			4.84		%
Variable basis swaps (c):
Amount	$	1,050				$	11,967
Average pay rate	0.24		%			0.33		%
Average receive rate	0.17		%			0.21		%

___________

(a) Borrowings under the TCEH Revolving Credit Facilities, capital leases and the effects of unamortized premiums and discounts are excluded from the table. The Bankruptcy Filing constituted an event of default under the indentures governing the company's debt instruments. As a result, the accompanying consolidated balance sheet as of December 31, 2013 presents all debt classified as current. See Note 10 to Financial Statements.

(b) The weighted average interest rate presented is based on the rate in effect at December 31, 2013.

(c) In order to hedge our variable rate debt exposure, we have entered into interest rate swaps under which we receive amounts based on variable interest rates and pay amounts based on fixed interest rates. In addition, we have entered into certain interest rate basis swaps to further reduce borrowing costs. The average pay rate and average receive rate for variable rate instruments is based on rates in effect at December 31, 2013.

(d) At December 31, 2013 and 2012, represents $18.19 billion and $18.46 billion, respectively, of swaps that expire through October 2014 and $12.6 billion of swaps at both dates that become effective during October 2014 and expire through October 2017.

At December 31, 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 debt totaled $17 million, taking into account the interest rate swaps discussed in Note 10 to Financial Statements.

The Bankruptcy Filing constituted an event of default under the interest rate swap agreements, and because the agreements are deemed to be "forward contracts" under the Bankruptcy Code, the counterparties may elect to terminate the agreements.

83

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 $1.031 billion at December 31, 2013. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at December 31, 2013 include $526 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $58 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, arising from derivative instruments. 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 December 31, 2013, the exposure to credit risk from these counterparties totaled $505 million taking into account the netting provisions of the master agreements described above but before taking into account $302 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $203 million decreased $52 million in the year ended December 31, 2013.

Of this $203 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 an 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 December 31, 2013. This credit exposure largely represents wholesale trade accounts receivable and net asset positions related to commodity contracts and hedging and trading activities (a substantial majority of which mature in 2014) recognized as derivative assets in the balance sheet, 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 14 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	$	484		$	299	$	185
Noninvestment grade	21			3		18
Totals	$	505		$	302	$	203
Investment grade	95.8		%			91.1		%
Noninvestment grade	4.2		%			8.9		%

84

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

Significant (10% or greater) concentration of credit exposure exists with four counterparties, which represented 17%, 16%, 15% and 11% of the $203 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. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed 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.

85

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 related to our bankruptcy, 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" and the discussion under Item 7, "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:

• our ability to obtain the approval of the Bankruptcy Court with respect to the Debtors' motions in the bankruptcy proceedings, including with respect to the DIP Facility;

• the effectiveness of the overall restructuring activities pursuant to the Bankruptcy Filing and any additional strategies we employ to address our liquidity and capital resources;

• the terms and conditions of any bankruptcy plan that is ultimately approved by the Bankruptcy Court;

• the extent to which the Bankruptcy Filing causes customers, suppliers and others with whom we have commercial relationships to lose confidence in us, which may make it more difficult for us to obtain and maintain such commercial relationships on competitive terms;

• difficulties we may face in retaining and motivating our key employees through the bankruptcy process, and difficulties we may face in attracting new employees;

• the significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations;

• our ability to remain in compliance with the requirements of the DIP Facility;

• our ability to maintain or obtain sufficient financing sources for operations or to fund any bankruptcy plan and meet future obligations;

• limitations on our ability to utilize previously incurred federal net operating losses or alternative minimum tax credits;

• the actions and decisions of creditors, regulators and other third parties that have an interest in the bankruptcy proceedings that may be inconsistent with our plans;

• the length of time that the Debtors will be debtors-in-possession under the Bankruptcy Code;

• the actions and decisions of regulatory authorities relative to our bankruptcy plan;

• restrictions on our operations due to the terms of our debt agreements, including the DIP Facility, and restrictions imposed by the Bankruptcy Court;

• our ability to obtain any required regulatory consent necessary to implement a bankruptcy plan;

• the outcome of potential litigation regarding whether note holders are entitled to make-whole premiums in connection with the treatment of their claims in bankruptcy;

• prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the FERC, the NERC, the TRE, the PUCT, the 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, including the legal proceedings arising out of the bankruptcy;

86

• 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 the ability of vendors to provide or deliver commodities as needed;

• 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 cyber security 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;

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

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

• our ability to generate sufficient cash flow to make interest or adequate assurance payments, or refinance, our debt instruments, including the DIP Facility;

• competition for new energy development and other business opportunities;

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

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

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

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

• changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure under ERISA;

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

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

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• 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.

87

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.

88

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of Energy Future Competitive Holdings Company LLC

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Energy Future Competitive Holdings Company LLC (formerly Energy Future Competitive Holdings Company) (a subsidiary of Energy Future Holdings Corp.) and subsidiaries ("EFCH") as of December 31, 2013 and 2012, and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and membership interests/equity for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of EFCH's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Future Competitive Holdings Company LLC and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements for the year ended December 31, 2013 have been prepared assuming that EFCH will continue as a going concern. As discussed in Notes 2 and 10 to the consolidated financial statements, EFCH is in default of certain covenants contained in its debt agreements and does not expect to be able to settle all its obligations coming due within the next twelve months and on April 29, 2014 Energy Future Holdings Corp. and the substantial majority of its subsidiaries (including Energy Future Competitive Holdings Company LLC), excluding Oncor Electric Delivery Holdings Company LLC and its subsidiaries, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. These circumstances and uncertainties inherent in the bankruptcy proceedings raise substantial doubt about EFCH’s ability to continue as a going concern. Management’s plans concerning these matters are also discussed in Note 2 to the consolidated financial statements. The consolidated financial statements do not include adjustments that might result from the outcome of these uncertainties.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EFCH's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 29, 2014 expressed an unqualified opinion on EFCH's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Dallas, Texas

April 29, 2014

89

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

	Year Ended December 31,
	2013			2012			2011
	(millions of dollars)
Operating revenues	$	5,899		$	5,636		$	7,040
Fuel, purchased power costs and delivery fees	(2,848		)	(2,816		)	(3,396		)
Net gain (loss) from commodity hedging and trading activities	(54		)	389			1,011
Operating costs	(881		)	(888		)	(924		)
Depreciation and amortization	(1,333		)	(1,343		)	(1,470		)
Selling, general and administrative expenses	(681		)	(659		)	(728		)
Franchise and revenue-based taxes	(75		)	(80		)	(96		)
Impairment of goodwill (Note 4)	(1,000		)	(1,200		)	—
Other income (Note 7)	9			13			48
Other deductions (Note 7)	(162		)	(188		)	(524		)
Interest income	5			46			86
Interest expense and related charges (Note 18)	(1,933		)	(2,842		)	(3,792		)
Loss before income taxes	(3,054		)	(3,932		)	(2,745		)
Income tax benefit (Note 6)	737			924			943
Net loss	(2,317		)	(3,008		)	(1,802		)
Net loss attributable to noncontrolling interests	107			—			—
Net loss attributable to EFCH	$	(2,210	)	$	(3,008	)	$	(1,802	)

See Notes to Financial Statements.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2013			2012			2011
	(millions of dollars)
Net loss	$	(2,317	)	$	(3,008	)	$	(1,802	)
Other comprehensive income, net of tax effects – cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $3, $3 and $10)	6			7			19
Comprehensive loss	(2,311		)	(3,001		)	(1,783		)
Comprehensive loss attributable to noncontrolling interests	107			—			—
Comprehensive loss attributable to EFCH	$	(2,204	)	$	(3,001	)	$	(1,783	)

See Notes to Financial Statements.

90

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31,
	2013			2012			2011
	(millions of dollars)
Cash flows — operating activities:
Net loss	$	(2,317	)	$	(3,008	)	$	(1,802	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation and amortization	1,499			1,521			1,707
Deferred income tax benefit, net	(677		)	(952		)	(1,116		)
Income tax benefit due to IRS audit resolutions (Note 5)	(80		)	—			—
Impairment of goodwill (Note 4)	1,000			1,200			—
Unrealized net (gain) loss from mark-to-market valuations of commodity positions	1,091			1,526			(58		)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps (Note 18)	(1,053		)	(166		)	812
Interest expense on toggle notes payable in additional principal (Notes 10 and 18)	—			152			166
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 18)	281			201			227
Interest expense related to pushed-down debt of parent (Notes 10 and 18)	6			75			78
Charges related to pension plan actions (Note 15)	—			50			—
Impairment of emissions allowances intangible assets (Note 4)	—			—			418
Impairment of assets of nuclear generation development joint venture (Note 8)	140			—			—
Other asset impairments (Note 7)	10			31			9
Third-party fees related to debt amendment and extension (reported as financing)	—			—			86
Bad debt expense (Note 9)	33			26			56
Accretion expense related primarily to mining reclamation obligations (Note 18)	33			37			48
Stock-based incentive compensation expense	2			4			5
Net equity (gain) loss from unconsolidated affiliate	(1		)	3			4
Net (gain) loss on sale of assets	2			4			(2		)
Other, net	9			1			2
Changes in operating assets and liabilities:
Affiliate accounts receivable/payable, net	16			(87		)	(4		)
Accounts receivable — trade	(33		)	22			175
Inventories	(6		)	19			(23		)
Accounts payable — trade	(8		)	(126		)	(126		)
Commodity and other derivative contractual assets and liabilities	47			6			(33		)
Margin deposits, net	(320		)	(476		)	540
Other — net assets	81			(52		)	(27		)
Other — net liabilities	(26		)	(251		)	94
Cash provided by (used in) operating activities	(271		)	(240		)	1,236
Cash flows — financing activities:
Issuances of long-term debt	—			—			1,750
Repayments/repurchases of debt (Note 10)	(105		)	(40		)	(1,408		)
Net borrowings (repayments) under accounts receivable securitization program (Note 9)	(82		)	(22		)	8
Increase (decrease) in other borrowings (Note 10)	—			1,384			(455		)
Notes due to affiliates	17			—			—
Decrease in income tax-related note payable to Oncor (Note 17)	—			(20		)	(39		)
Settlement of reimbursement agreements with Oncor (Note 17)	—			(159		)	—

91

	Year Ended December 31,
	2013			2012			2011
	(millions of dollars)
Contributions from noncontrolling interests	6			7			16
Sale/leaseback of equipment	—			15			—
Debt amendment, exchange and issuance costs, including third-party fees expensed	—			(5		)	(843		)
Other, net	(10		)	1			(2		)
Cash provided by (used in) financing activities	(174		)	1,161			(973		)
Cash flows — investing activities:
Capital expenditures	(472		)	(631		)	(530		)
Nuclear fuel purchases	(116		)	(213		)	(132		)
Settlements of notes due from affiliates	698			926			346
Purchase of right to use certain computer-related assets from parent (Note 17)	(29		)	(38		)	—
Proceeds from sales of assets	4			2			49
Acquisition of combustion turbine trust interest (Note 10)	(40		)	—			—
Reduction of restricted cash related to TCEH Letter of Credit Facility	—			—			188
Other changes in restricted cash	2			129			(96		)
Proceeds from sales of environmental allowances and credits	—			—			10
Purchases of environmental allowances and credits	(16		)	(25		)	(17		)
Proceeds from sales of nuclear decommissioning trust fund securities	175			106			2,419
Investments in nuclear decommissioning trust fund securities	(191		)	(122		)	(2,436		)
Other, net	1			—			9
Cash provided by (used in) investing activities	16			134			(190		)
Net change in cash and cash equivalents	(429		)	1,055			73
Cash and cash equivalents — beginning balance	1,175			120			47
Cash and cash equivalents — ending balance	$	746		$	1,175		$	120

See Notes to Financial Statements.

92

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC CONSOLIDATED BALANCE SHEETS
	December 31,
	2013		2012
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	746	$	1,175
Restricted cash (Note 18)	945		—
Trade accounts receivable — net (includes $— and $445 in pledged amounts related to a VIE (Notes 3 and 9))	710		710
Notes receivable from parent (Note 17)	—		698
Inventories (Note 18)	399		393
Commodity and other derivative contractual assets (Note 14)	784		1,463
Accumulated deferred income taxes	121		—
Margin deposits related to commodity positions	93		71
Other current assets	50		120
Total current assets	3,848		4,630
Restricted cash (Note 18)	—		947
Investments (Note 18)	838		710
Property, plant and equipment — net (Note 18)	17,649		18,556
Goodwill (Note 4)	3,952		4,952
Identifiable intangible assets — net (Note 4)	1,717		1,781
Commodity and other derivative contractual assets (Note 14)	4		586
Other noncurrent assets, primarily unamortized debt amendment and issuance costs	790		811
Total assets	$	28,798	$	32,973
LIABILITIES AND MEMBERSHIP INTERESTS/EQUITY
Current liabilities:
Borrowings under credit and other facilities (includes $— and $82 related to a VIE (Notes 3 and 10))	$	2,054	$	2,136
Debt held by affiliates (Note 10)	382		—
Notes, loans and other debt (Note 10)	29,800		96
Trade accounts payable	381		389
Trade accounts and other payables to affiliates	164		139
Notes payable to parent (Note 17)	103		81
Commodity and other derivative contractual liabilities (Note 14)	1,275		894
Margin deposits related to commodity positions	302		600
Accumulated deferred income taxes (Note 6)	—		49
Accrued income taxes payable to parent (Note 17)	21		31
Accrued taxes other than income	120		17
Accrued interest	419		407
Other current liabilities	272		255
Total current liabilities	35,293		5,094
Accumulated deferred income taxes (Note 6)	3,582		3,759
Commodity and other derivative contractual liabilities (Note 14)	—		1,556
Notes or other liabilities due to affiliates	2		5
Long-term debt held by affiliates (Note 17)	—		382
Long-term debt, less amounts due currently (Note 10)	—		29,928
Liability to EFH Corp. under the Federal and State Income Tax Allocation Agreement (Note 5)	535		—
Other noncurrent liabilities and deferred credits (Note 18)	1,654		2,643
Total liabilities	41,066		43,367
Commitments and Contingencies (Note 11)

93

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC CONSOLIDATED BALANCE SHEETS
	December 31,
	2013			2012
	(millions of dollars)
Membership Interests/Equity (Note 12):
Class A common stock (shares outstanding December 31, 2012 - 2,062,768)	$	—		$	383
Class B common stock (shares outstanding December 31, 2012 - 39,192,594)	—			7,282
Retained deficit	—			(18,129		)
Capital account	(12,233		)	—
Accumulated other comprehensive loss	(36		)	(42		)
EFCH membership interests/shareholder's equity	(12,269		)	(10,506		)
Noncontrolling interests in subsidiaries	1			112
Total membership interests/equity	(12,268		)	(10,394		)
Total liabilities and membership interests/equity	$	28,798		$	32,973

See Notes to Financial Statements.

94

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC STATEMENTS OF CONSOLIDATED MEMBERSHIP INTERESTS/EQUITY
	Year Ended December 31,
	2013			2012			2011
	(millions of dollars)
Class A common stock without par value — authorized shares — 9,000,000:
Balance at beginning of period	$	383		$	368		$	358
Effects of debt push-down from EFH Corp. (Note 10)	22			15			10
Capital structure conversion (a)	(405		)	—			—
Balance at end of period (shares outstanding for all periods presented prior to capital structure conversion — 2,062,768)	—			383			368
Class B common stock without par value — authorized shares — 171,000,000:
Balance at beginning of period	7,282			6,983			6,793
Effects of debt push-down from EFH Corp. (Note 10)	412			293			184
Effects of stock-based incentive compensation plans	—			4			6
Gain on settlement of reimbursement agreement with Oncor	—			2			—
Capital structure conversion (a)	(7,694		)	—			—
Balance at end of period (shares outstanding for all periods presented prior to capital structure conversion — 39,192,594)	—			7,282			6,983
Retained deficit:
Balance at beginning of period	(18,129		)	(15,121		)	(13,319		)
Net loss attributable to EFCH	(526		)	(3,008		)	(1,802		)
Other	—			—			—
Capital structure conversion (a)	18,655			—			—
Balance at end of period	—			(18,129		)	(15,121		)
Capital account:
Balance at beginning of period	—			—			—
Net loss attributable to EFCH	(1,684		)	—			—
Effects of debt push-down from EFH Corp. (Note 10)	4			—			—
Effects of stock-based incentive compensation plans	2			—			—
Other	1			—			—
Capital structure conversion (a)	(10,556		)	—			—
Balance at end of period	(12,233		)	—			—
Accumulated other comprehensive loss, net of tax effects (b):
Balance at beginning of period	(42		)	(49		)	(68		)
Change during the period	6			7			19
Balance at end of period	(36		)	(42		)	(49		)
EFCH membership interests/shareholder's equity at end of period	(12,269		)	(10,506		)	(7,819		)

95

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC STATEMENTS OF CONSOLIDATED MEMBERSHIP INTERESTS/EQUITY
	Year Ended December 31,
	2013			2012			2011
	(millions of dollars)
Noncontrolling interests in subsidiaries (Note 12):
Balance at beginning of period	112			103			87
Investment in subsidiary by noncontrolling interests	6			7			16
Cash distribution to EFH Corp. from predecessor receivables company (Note 9)	(10		)	—			—
Net loss attributable to noncontrolling interests (Note 8)	(107		)
Other	—			2			—
Noncontrolling interests in subsidiaries at end of period	1			112			103
Total membership interests/equity at end of period	$	(12,268	)	$	(10,394	)	$	(7,716	)

_________________

(a) In 2013, EFCH was converted from a Texas corporation into a Delaware limited liability company in accordance with an IRS private letter ruling.

(b) All amounts relate to cash flow hedges.

See Notes to Financial Statements.

96

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Bankruptcy Filing

As discussed further in Note 2, on April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, (the Debtors) filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). See Note 10 for discussion of debtor-in-possession financing and classification of debt as current liabilities.

Basis of Presentation

The consolidated financial statements have been prepared in accordance with US GAAP. The consolidated financial statements have been prepared as if EFCH is a going concern but do not reflect the application of ASC 852, Reorganizations. 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. 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.

97

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage our commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the balance sheet. This recognition is referred to as "mark-to-market" accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the balance sheet as commodity and other derivative contractual assets or liabilities. We report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the balance sheet. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 13 and 14 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the "normal" purchase and sale exemption. A commodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.

Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for "hedge accounting," which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. A cash flow hedge mitigates the risk associated with the variability of the future cash flows related to an asset or liability (e.g., a forecasted sale of electricity in the future at market prices or the payment of interest related to variable rate debt), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debt with fixed interest rate payments). In accounting for changes in the fair value of cash flow hedges, derivative assets and liabilities are recorded on the balance sheet with an offset to other comprehensive income to the extent the hedges are effective and the hedged transaction remains probable of occurring. If the hedged transaction becomes probable of not occurring, hedge accounting is discontinued and the amount recorded in other comprehensive income is immediately reclassified into net income. If the relationship between the hedge and the hedged transaction ceases to exist or is dedesignated, hedge accounting is discontinued, and the amounts recorded in other comprehensive income are reclassified to net income as the previously hedged transaction impacts net income. Changes in value of fair value hedges are recorded as derivative assets or liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss associated with the hedge is amortized into income over the remaining life of the hedged item. In the statement of cash flow, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.

To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge's effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Changes in fair value that represent hedge ineffectiveness, even if the hedge continues to be assessed as effective, are immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item.

At December 31, 2013 and 2012, there were no derivative positions accounted for as cash flow or fair value hedges. Accumulated other comprehensive income includes amounts related to interest rate swaps previously designated as cash flow hedges that are being reclassified to net income as the hedged transactions impact net income (see Note 10).

Realized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reported in the income statement in net gain (loss) from commodity hedging and trading activities. In accordance with accounting rules, upon settlement of physical derivative sales and purchase contracts that are marked-to-market in net income, related wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, instead of the contract price. As a result, this noncash difference between market and contract prices is included in the operating revenues and fuel and purchased power costs and delivery fees line items of the income statement, with offsetting amounts included in net gain (loss) from commodity hedging and trading activities.

98

Revenue Recognition

We record revenue from electricity sales under the accrual method of accounting. Revenues are recognized when electricity is provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).

We report physically delivered commodity sales and purchases in the income statement on a gross basis in revenues and fuel, purchased power and delivery fees, respectively, and we report all other commodity related contracts and financial instruments (primarily derivatives) in the income statement on a net basis in net gain (loss) from commodity hedging and trading activities. Volumes under nontrading bilateral purchase and sales contracts, including contracts intended as hedges, are not scheduled as physical power with ERCOT. Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, such contracts are reported net in the income statement in net gain (loss) from commodity hedging and trading activities instead of reported gross as wholesale revenues or purchased power costs. If volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues, and if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record additional purchased power costs. The additional wholesale revenues or purchased power costs are offset in net gain (loss) from commodity hedging and trading activities.

Impairment of Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 8 for discussion of the 2013 impairment of assets of our joint venture to develop additional nuclear units and Note 4 for discussion of impairments of intangible assets and mining-related assets in 2012 and 2011.

Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 4 for additional information.

Goodwill and Intangible Assets with Indefinite Lives

We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually (at December 1). See Note 4 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations and goodwill impairments recorded in 2013 and 2012.

Amortization of Nuclear Fuel

Amortization of nuclear fuel is calculated on the units-of-production method and is reported as fuel costs.

Major Maintenance

Major maintenance costs incurred during generation plant outages and the costs of other maintenance activities are charged to expense as incurred and reported as operating costs.

Defined Benefit Pension Plans and OPEB Plans

We bear a portion of the costs of the EFH Corp. sponsored pension and OPEB plans offering certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company and also offer pension benefits to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. Under multiemployer plan accounting, EFH Corp. has elected to not allocate retirement plan assets and liabilities to us. See Note 15 for additional information regarding pension and OPEB plans, including a discussion of amendments to the EFH Corp. pension plan approved in August 2012.

99

Stock-Based Incentive Compensation

EFH Corp.'s 2007 Stock Incentive Plan authorizes discretionary grants to directors, officers and qualified managerial employees of EFH Corp. or its affiliates of non-qualified stock options, stock appreciation rights, restricted shares, shares of common stock, the opportunity to purchase shares of common stock and other stock-based awards. Stock-based compensation expense is recognized over the vesting period based on the grant-date fair value of those awards. See Note 16 for information regarding stock-based incentive compensation.

Sales and Excise Taxes

Sales and excise taxes are accounted for as a "pass through" item on the balance sheet with no effect on the income statement; i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction.

Franchise and Revenue-Based Taxes

Unlike sales and excise taxes, franchise and gross receipt taxes are not a "pass through" item. These taxes are assessed to us by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers.

Income Taxes

EFH Corp. files a consolidated US federal income tax return that includes the results of EFCH and TCEH; however, our income tax expense and related balance sheet amounts are recorded as if we file separate corporate income tax returns. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as required under accounting rules. See Note 6.

We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 5.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 11 for a discussion of contingencies.

Cash and Cash Equivalents

For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.

Restricted Cash

The terms of certain agreements require the restriction of cash for specific purposes. At December 31, 2013, $945 million of cash was restricted to support letters of credit. See Notes 10 and 18 for more details regarding restricted cash.

Fair Value of Nonderivative Financial Instruments

The carrying amounts of financial assets classified as current assets and the carrying amounts of financial liabilities classified as current liabilities approximate fair value due to the short maturity of such balances, which include cash equivalents, accounts receivable and accounts payable.

100

Property, Plant and Equipment

As a result of purchase accounting, carrying amounts of property, plant and equipment were adjusted to estimated fair values at the Merger date. Subsequent additions have been recorded at cost. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs.

Depreciation of our property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on a component asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives. See Note 18.

Asset Retirement Obligations

A liability is initially recorded at fair value for an asset retirement obligation associated with the retirement of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. 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. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. See Note 18.

Capitalized Interest

Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 18.

Inventories

Inventories are reported at the lower of cost (on a weighted average basis) or market unless expected to be used in the generation of electricity. Also see discussion immediately below regarding environmental allowances and credits.

Environmental Allowances and Credits

We account for all environmental allowances and credits as identifiable intangible assets with finite lives that are subject to amortization. The recorded values of these intangible assets were originally established reflecting fair value determinations as of the date of the Merger under purchase accounting. Amortization expense associated with these intangible assets is recognized on a unit of production basis as the allowances or credits are consumed in generation operations. The environmental allowances and credits are assessed for impairment when conditions or events occur that could affect the carrying value of the assets and are evaluated with the generation units to the extent they are planned to be consumed in generation operations. See Note 7 for details of impairment amounts recorded in 2011.

Investments

Investments in a nuclear decommissioning trust fund are carried at current market value in the balance sheet. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 18 for discussion of these and other investments.

Noncontrolling Interests

See Notes 8 and 12 for discussion of accounting for noncontrolling interests in subsidiaries.

Push-Down of EFH Corp. Debt

In accordance with SEC Staff Accounting Bulletin (SAB) Topic 5-J, we reflect amounts of certain EFH Corp. senior notes on our balance sheets and the related interest expense in our income statement. The amount reflected on our balance sheet was calculated based upon the relative equity investment of EFCH and EFIH in their respective operating subsidiaries at the time of the Merger (see Note 10).

101

2. SUBSEQUENT EVENT - BANKRUPTCY FILING

On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, (the Debtors) filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). During the pendency of the Bankruptcy Filing (the Chapter 11 Cases), the Debtors will operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

The Bankruptcy Filing resulted primarily from the adverse effects on EFCH of lower wholesale electricity prices in ERCOT driven by the sustained decline in natural gas prices since mid-2008. Further, the remaining natural gas hedges that TCEH entered into when forward market prices of natural gas were significantly higher than current prices mature in 2014. These market conditions challenged EFCH's profitability and operating cash flows and resulted in the inability to support its significant interest payments and debt maturities, including the remaining debt obligations due in 2014, and to refinance and/or extend the maturities of its outstanding debt. These liquidity matters raised substantial doubt about EFCH's ability to continue as a going concern without a restructuring of the debt.

In consideration of the liquidity matters discussed above, the report of EFCH's independent registered public accounting firm that accompanies its audited consolidated financial statements for the year ended December 31, 2013 included in this annual report contains an explanatory paragraph regarding the substantial doubt about EFCH's ability to continue as a going concern.

In 2013, EFH Corp. began to engage in discussions with certain creditors, including TCEH creditors, with respect to proposed changes to its capital structure, including the possibility of a consensual, prepackaged restructuring transaction. Because of the recent constructive nature of these discussions, TCEH elected not to make interest payments due in April 2014 totaling $123 million on certain debt obligations. Under the terms of the debt obligations that apply to the substantial majority of the missed interest payments, the lenders had the right to accelerate the payment of the debt if TCEH had not cured the default after an applicable grace period. In anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors entered into a Restructuring Support and Lock-Up Agreement (the Restructuring Support and Lock-Up Agreement) with various stakeholders in order to effect an agreed upon restructuring of the Debtors through a pre-arranged Chapter 11 plan of reorganization (the Restructuring Plan).

Restructuring Support and Lock-Up Agreement

General

In anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors, Texas Holdings and its general partner Texas Energy Future Capital Holdings LLC (TEF and, together with Texas Holdings, the Consenting Interest Holders) and the Consenting Creditors entered into the Restructuring Support and Lock-Up Agreement in order to effect an agreed upon restructuring of the Debtors through the Restructuring Plan.

Pursuant to the Restructuring Support and Lock-Up Agreement, the Consenting Interest Holders and Consenting Creditors agreed, subject to the terms and conditions contained in the Restructuring Support and Lock-Up Agreement, to support the Debtors’ proposed financial restructuring (the Restructuring Transactions), and further agreed to limit certain transfers of any ownership (including any beneficial ownership) in the equity interests of or claims held against the Debtors, including any such interests or claims acquired after executing the Restructuring Support and Lock-Up Agreement.

102

Material Restructuring Terms

The Restructuring Support and Lock-Up Agreement along with the accompanying term sheet sets forth the material terms of the Restructuring Transactions pursuant to which, in general:

TCEH First Lien Secured Claims

As a result of the Restructuring Transactions, holders of TCEH first lien secured claims will receive, among other things, their pro rata share of (i) 100% of the equity of TCEH consummated through a tax-free spin (in accordance with the Private Letter Ruling described below) in connection with TCEH's emergence from bankruptcy (Reorganized TCEH) and (ii) all of the net cash from the proceeds of the issuance of new long-term secured debt of Reorganized TCEH.

TCEH Unsecured Claims

As a result of the Restructuring Transactions, holders of general unsecured claims against EFCH, TCEH and its subsidiaries (including TCEH first lien deficiency claims, TCEH second lien claims and TCEH unsecured note claims) will receive their pro rata share of the unencumbered assets of TCEH.

EFIH First Lien and EFIH Second Lien Settlements

Certain holders of each of the EFIH 6.875% Notes and EFIH 10% Notes (such holders, the EFIH First Lien Note Parties) have agreed to voluntary settlements with respect to EFIH's and EFIH Finance's obligations under the EFIH First Lien Notes held by the EFIH First Lien Note Parties. Under the terms of the settlement, each EFIH First Lien Note Party has agreed to accept as payment in full of any claims arising out of its EFIH First Lien Notes an amount of loans under the EFIH First Lien DIP Facility equal to the greater of (a) 105% of the principal amount on the EFIH First Lien Notes plus 101% of the accrued and unpaid interest at the non-default rate on such principal (which amount will be deemed to include the original issue discount) and (b) 104% of the principal amount of, plus accrued and unpaid interest at the non-default rate on, the EFIH First Lien Notes, in each case held by such EFIH First Lien Note Party. In addition, in the case of (b) above, each EFIH First Lien Note Party will be entitled to original issue discount paid in accordance with the EFIH First Lien Facility. No EFIH First Lien Note Party will receive any other fees, including commitment fees, paid in respect of the EFIH First Lien DIP Facility (such settlement, the EFIH First Lien Settlement).

Certain holders of each of the EFIH 11% Notes and EFIH 11.75% Notes (such holders, the EFIH Second Lien Note Parties) have agreed to voluntary settlements with respect to EFIH's and EFIH Finance's obligations under the EFIH Second Lien Notes held by the EFIH Second Lien Note Parties. Under the terms of the settlement, each EFIH Second Lien Note Party has agreed to accept as payment in full of any claims arising out of its EFIH Second Lien Notes, its pro rata share of an amount in cash equal to (i) 100% of the principal of EFIH Second Lien Notes held by such EFIH Second Lien Party plus (ii) 50% of the aggregate amount of any claim derived from or based upon make-whole or other similar provisions under the EFIH 11% Notes or EFIH 11.75% Notes (such settlement, the EFIH Second Lien Settlement).

As part of the EFIH Second Lien Settlement, a significant EFIH Second Lien Note Party, but not other EFIH Second Lien Note Parties, will have the right to receive up to $500 million of its payment under the EFIH Second Lien Settlement in the form of loans under the EFIH First Lien DIP Facility.

During the early portion of the Chapter 11 Cases, EFIH expects to 1) solicit agreement to and participation in each of the EFIH First Lien Settlement and EFIH Second Lien Settlements from holders of the remaining respective first and second lien notes and 2) initiate litigation to obtain entry of an order from the Bankruptcy Court disallowing the claims of any non-settling holders of the EFIH First Lien Notes and EFIH Second Lien Notes from or based on make-whole or other similar provisions under the respective notes. Following the completion of these solicitations, Non-Settling EFIH First Lien Holders and Non-Settling EFIH Second Lien Note Holders will receive their respective pro rata shares of cash from the proceeds of the EFIH First Lien DIP and EFIH Second Lien DIP Facilities.

EFIH Second Lien DIP Notes Offering

During the early portion of the Chapter 11 Cases, EFIH and EFIH Finance expect to offer (the EFIH Second Lien DIP Notes Offering) to all holders of EFIH Unsecured Notes and a significant EFIH Second Lien Note Party the right to purchase $1.9 billion aggregate principal amount of 8% Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Notes due 2016.

103

Backstop Commitment

In connection with the execution of the Restructuring Support and Lock-Up Agreement, certain holders of the EFIH Unsecured Notes (the Backstop Parties) have entered into a commitment letter with EFH Corp. and EFIH, dated April 29, 2014 (the Commitment Letter), pursuant to which such holders have committed, severally and not jointly, up to $2.0 billion in available funds (the Backstop Commitment) to purchase EFIH Second Lien DIP Notes. Any EFIH Second Lien DIP Notes not sold in the EFIH Second Lien DIP Notes Offering and the concurrent offering (unpurchased notes) will be purchased by the Backstop Parties, pro rata in proportion to their respective share of the Backstop Commitment. If any Backstop Party fails to satisfy its obligation to purchase its pro rata share of the unpurchased notes, the other Backstop Parties would have the right, but not the obligation, to purchase such unpurchased notes. The obligations under the Commitment Letter are not subject to the approval of the Oncor TSA Amendment (as described below) by the Bankruptcy Court.

Under the Commitment Letter and in consideration of the Backstop Commitment, EFIH agreed to pay the Backstop Parties fees consisting of (i) $40 million execution and approval fees payable at various milestones within the bankruptcy process and (ii) a fee equal to $100 million payable in the form of Non-Interest Bearing Mandatorily Convertible Second Lien Subordinated Secured DIP Financing Tranche B Notes due 2016 (EFIH Second Lien DIP Tranche B Notes) to be paid concurrently with the consummation of the EFIH Second Lien DIP Notes Offering. Other than with respect to the requirement not to pay interest and related mechanics and not trading together with any other debt, the EFIH Second Lien DIP Tranche B Notes are expected to have the same terms and conditions as the EFIH Second Lien DIP Notes.

In the event the EFIH Second Lien DIP Notes are repaid in cash prior to the effective date of the plan of reorganization (Effective Date), EFIH agreed to pay the Backstop Parties a termination fee of $380 million. In addition, if the EFIH Second Lien DIP Notes Offering is not consummated at the option of EFIH, EFIH agreed to pay the Backstop Parties a break-up fee of $60 million.

EFIH Unsecured Claims and EFH Corp. Unsecured Claims

On the Effective Date, all of the EFIH Unsecured Notes and EFH Corp. Unsecured Notes will be canceled. In full satisfaction of the claims under the EFIH Unsecured Notes and the EFH Corp. Unsecured Notes, (i) each holder of EFIH Unsecured Notes will receive its pro rata share of 98.0% of the equity interests of newly reorganized EFH Corp. (Reorganized EFH Corp.) (subject to dilution by the Equity Conversion as described below) and (ii) each holder of EFH Corp. Unsecured Notes will receive its pro rata share of 1.0% of the equity interests of Reorganized EFH Corp. (subject to dilution by the Equity Conversion).

Holders of the EFH Corp. Unsecured Notes will also receive on the Effective Date their pro rata share of either (A) if the Oncor TSA Amendment (described below) has then been approved, (1) $55 million in cash from EFIH, provided, however, that if the Oncor tax payments received by EFIH under the Oncor TSA Amendment through the Effective Date are less than 80% of projected amounts, the $55 million payment will be reduced on a dollar for dollar basis by the amount of such shortfall, and (2) cash on hand at EFH Corp. (not including the settlement payment in clause (1) hereof); or (B) if the Oncor TSA Amendment has not then been approved, all assets of EFH Corp., including cash on hand but excluding the equity interests in EFIH.

EFH Corp. Equity Interests

On the Effective Date, all of the equity interests in EFH Corp. (EFH Corp. Interests) will be canceled. In full satisfaction of the claims under the EFH Corp. Interests, each holder of EFH Corp. Interests will receive its pro rata share of 1.0% of the equity interests of Reorganized EFH Corp. (subject to dilution by the Equity Conversion).

Equity Conversion

On the Effective Date, the EFIH Second Lien DIP Notes will automatically convert (Equity Conversion) on a pro rata basis into approximately 64% of the equity interests of Reorganized EFH Corp.

104

Oncor TSA Amendment

The Restructuring Support and Lock-Up Agreement provides that the Debtors will request authority from the Bankruptcy Court to amend, or otherwise assign the right to payments under, the Oncor Tax Sharing Agreement (the Oncor TSA Amendment) to provide that any payment required to be made to EFH Corp. under the Oncor Tax Sharing Agreement after March 31, 2014, will instead be made to EFIH. Any tax payments received by EFH Corp. before the Bankruptcy Court enters or denies an order authorizing the Oncor TSA Amendment will be deposited by EFH Corp. into a segregated account until the earlier of (i) the date the Bankruptcy Court enters the order authorizing the Oncor TSA Amendment, in which case such amounts will be remitted to EFIH, or (ii) the date the Bankruptcy Court denies authorization of the Oncor TSA Amendment, in which case such amounts will be remitted to EFH Corp.

The Oncor TSA Amendment will automatically terminate and be of no further force and effect in the event that the Commitment Letter is terminated by the Backstop Parties; provided, however, that any amounts that were paid to EFIH in accordance with the Oncor TSA Amendment before its termination will be retained by EFIH if the Commitment Letter terminates or the EFIH Second Lien DIP Facility is not fully funded in accordance with its terms (i.e., except as a result of a breach by the Backstop Parties). Neither EFH Corp. nor EFIH will have the right to terminate or modify the Oncor TSA Amendment during the Chapter 11 Cases if the EFIH Second Lien DIP Facility is consummated.

If the Bankruptcy Court has not approved the Oncor TSA Amendment within 90 days after the Petition Date, the interest rate on the EFIH Second Lien DIP Tranche A-1 Notes, EFIH Second Lien DIP Tranche A-2 Notes and EFIH Second Lien DIP Tranche A-3 Notes will increase by 4.0% with such additional interest to be paid-in-kind (compounded quarterly) until such approval is received from the Bankruptcy Court. If the Bankruptcy Court has not approved the Oncor TSA Amendment by May 1, 2015, each holder of EFIH Second Lien DIP Notes will receive additional EFIH Second Lien DIP Notes equal to 10.0% of the amount of EFIH Second Lien DIP Notes held by such holder.

Private Letter Ruling

The Restructuring Support and Lock-Up Agreement provides that EFH Corp. will file a request with the IRS for a private letter ruling (Private Letter Ruling) that, among other things, will provide (a) that (i) the transfer by TCEH of all of its assets and its ordinary course operating liabilities to Reorganized TCEH, (ii) the transfer by the Debtors to Reorganized TCEH of certain operating assets and liabilities that are reasonably necessary to the operation of Reorganized TCEH and (iii) the distribution by TCEH of (A) the equity it holds in Reorganized TCEH and (B) the cash proceeds TCEH receives from Reorganized TCEH to the holders of TCEH First Lien Claims, will qualify as a "reorganization" within the meaning of Sections 368(a)(1)(G) , 355 and 356 of the Code and (b) for certain other rulings under Sections 368(a)(1)(G) and 355 of the Code.

There are various conditions precedent to the restructuring transactions under the Restructuring Support and Lock-Up Agreement including, but not limited to the receipt of the Private Letter Ruling, requisite regulatory approvals and orders from the Bankruptcy Court.

Operation and Implications of the Chapter 11 Cases

Subject to certain exceptions, under the Bankruptcy Code, the Bankruptcy Filing automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Accordingly, although the Bankruptcy Filing triggered defaults on the Debtors' debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the Debtors' prepetition liabilities are subject to settlement under the Bankruptcy Code.

Following the Petition Date, the Debtors intend to seek approval from the Bankruptcy Court to pay or otherwise honor certain prepetition obligations generally designed to stabilize their operations. These obligations relate to certain employee wages and benefits, taxes, certain customer programs and certain obligations to vendors and hedging and trading counterparties. The Debtors intend to continue paying claims arising after the Petition Date in the ordinary course of business.

The Debtors have retained, pursuant to Bankruptcy Court approval, legal and financial professionals to advise them in connection with the Chapter 11 Cases and certain other professionals to provide services and advice in the ordinary course of business. From time to time, the Debtors may seek Bankruptcy Court approval to retain additional professionals. We have incurred and expect to continue to incur significant costs associated with the Chapter 11 Cases and our reorganization, but we cannot accurately predict the effect the Chapter 11 Cases will have on our liquidity, operations, financial position and results of operations.

105

The accompanying consolidated financial statements contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Our ability to continue as a going concern is contingent upon our ability to comply with the financial and other covenants contained in the debtor-in-possession financing (DIP Facility, described below), the Bankruptcy Court's approval of the Restructuring Plan or another Chapter 11 plan and our ability to successfully implement the Restructuring Plan or another Chapter 11 plan and obtain new financing, among other factors. As a result of the Chapter 11 Cases, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession under Chapter 11, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Facility), for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Restructuring Plan or another Chapter 11 plan could materially change the amounts and classifications of assets and liabilities reported in our consolidated financial statements.

Financing During the Chapter 11 Cases

As discussed in Note 10, we intend to file motions with the Bankruptcy Court for approval of the TCEH DIP Facility. The TCEH DIP Facility provides for $4.5 billion in senior secured, super-priority financing.

Chapter 11 Plan

A Chapter 11 plan (including the Restructuring Plan) determines the rights and satisfaction of claims of various creditors and security holders and is subject to the ultimate outcome of negotiations and Bankruptcy Court decisions ongoing through the date on which the Chapter 11 plan is confirmed. The Debtors currently expect that any proposed Chapter 11 plan (including the Restructuring Plan) will provide, among other things, mechanisms for settlement of claims against the Debtors' estates, treatment of EFH Corp.'s existing equity holders and the Debtors' respective existing debt holders, potential income tax liabilities and certain corporate governance and administrative matters pertaining to a reorganized EFH Corp. and EFCH. Any proposed Chapter 11 plan will (and the Restructuring Plan may) be subject to revision prior to submission to the Bankruptcy Court based upon discussions with the Debtors' creditors and other interested parties, and thereafter in response to creditor claims and objections and the requirements of the Bankruptcy Code or the Bankruptcy Court. There can be no assurance that the Debtors will be able to secure approval for the Restructuring Plan or any other Chapter 11 plan from the Bankruptcy Court or that any Chapter 11 plan will be accepted by the Debtors' creditors.

In order for the Debtors to emerge successfully from the Chapter 11 Cases as reorganized companies, they must obtain approval from the Bankruptcy Court and certain of their respective creditors for a Chapter 11 plan, which will enable each of the Debtors to transition from the Chapter 11 Cases into reorganized companies conducting ordinary course operations outside of bankruptcy. In connection with an exit from bankruptcy, TCEH will require a new credit facility, or "exit financing." TCEH's ability to obtain such approval, and TCEH's ability to obtain such financing will depend on, among other things, the timing and outcome of various ongoing matters in the Chapter 11 Cases.

Regulatory Requirements Related to the Bankruptcy Filing

Pursuant to the Bankruptcy Code, the Debtors intend to comply with all applicable regulatory requirements, including all requirements related to environmental and safety law compliance, during the pendency of the Chapter 11 Cases. In addition, the Debtors will seek all necessary and appropriate regulatory approvals necessary to consummate any transactions proposed in the Chapter 11 plan. Moreover, to the extent the Debtors either maintain insurance policies or self-insure their regulatory compliance obligations, the Debtors intend to continue such insurance policies or self-insurance in the ordinary course of business.

106

3. 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 9 regarding the VIE related to our accounts receivable securitization program that was consolidated under the accounting standards. We also consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), a joint venture 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 12). See Note 8 for discussion of impairment of the joint venture's assets.

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

	December 31,					December 31,
Assets:	2013		2012		Liabilities:	2013		2012
Cash and cash equivalents	$	4	$	43	Short-term borrowings	$	—	$	82
Accounts receivable	—		445		Trade accounts payable	1		1
Property, plant and equipment	2		134		Other current liabilities	—		7
Other assets, including $— million and $12 million of current assets	—		16
Total assets	$	6	$	638	Total liabilities	$	1	$	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.

107

4. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides information regarding our goodwill balance, all of which arose in connection with accounting for the Merger. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges	$	18,322
Accumulated noncash impairment charges through 2012 (a)	(13,370		)
Balance at December 31, 2012	4,952
Additional impairment charge in 2013	(1,000		)
Balance at December 31, 2013 (b)	$	3,952

___________

(a) Includes $1.2 billion and $4.1 billion recorded in 2012 and 2010, respectively, and $8.070 billion largely recorded in 2008.

(b) Net of accumulated impairment charges totaling $14.370 billion.

Goodwill Impairments

Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (we have selected a December 1 test date) or whenever events or changes in circumstances indicate an impairment may exist.

We perform the following steps in testing goodwill for impairment: first, we estimate the debt-free enterprise value of the business as of the testing date taking into account future estimated cash flows and current securities values of comparable companies; second, we estimate the fair values of the individual operating assets and liabilities of the business at that date; third, we calculate "implied" goodwill as the excess of the estimated enterprise value over the estimated value of the net operating assets; and finally, we compare the implied goodwill amount to the carrying value of goodwill and, if the carrying amount exceeds the implied value, we record an impairment charge for the amount the carrying value of goodwill exceeds implied goodwill.

Wholesale electricity prices in the ERCOT market, in which TCEH largely operates, have generally moved with natural gas prices as marginal electricity demand is generally supplied by natural gas fueled generation facilities. Accordingly, the sustained decline in natural gas prices, which we have experienced since mid-2008, negatively impacts our profitability and cash flows and reduces the value of our generation assets, which consist largely of lignite/coal and nuclear fueled facilities. While we have partially mitigated these effects with hedging activities, we are significantly exposed to this price risk. Because of this market condition, our analyses over the past several years have indicated that the carrying value of TCEH exceeds its estimated fair value (enterprise value). Consequently, we continually monitor trends in natural gas prices, market heat rates, capital spending for environmental and other projects and other operational factors to determine if goodwill impairment testing should be done during the course of a year and not only at the annual December 1 testing date.

During the quarter ended September 30, 2013, we completed our annual update of our long-range operating plan, which reflected a forecast of lower wholesale power prices than reflected in our December 1, 2012 impairment testing analyses. As a result, the likelihood of a goodwill impairment had increased, and we initiated further testing of goodwill as of September 30, 2013. We also updated that testing for any changes in conditions between September 30 and our annual December 1 testing date. Our testing indicated a goodwill impairment of $1.0 billion at September 30, 2013, which was recorded in the fourth quarter 2013. The update through December 1 did not indicate a further impairment.

108

Key inputs into our goodwill impairment testing at September 30 and December 1, 2013 and December 1, 2012 were as follows:

• The carrying value (excluding debt) of TCEH exceeded its estimated enterprise value by approximately 43% and 41% at December 1 and September 30, 2013, respectively, and by 40% at December 31, 2012.

• Enterprise value was estimated using a two-thirds weighting of value based on internally developed cash flow projections and a one-third weighting of value using implied cash flow multiples based on current securities values of comparable publicly traded companies.

• The discount rate applied to internally developed cash flow projections was 8.75% at both December 1 and September 30, 2013 and was 9.25% at December 31, 2012, respectively. The discount rate represents the weighted average cost of capital consistent with the risk inherent in future cash flows, taking into account the capital structure, debt ratings and current debt yields of comparable public companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry.

• The cash flow projections used in 2013 assume rising wholesale electricity prices, although the forecasted electricity prices are less than those assumed in the cash flow projections used in the 2012 goodwill impairment testing, which were less than those assumed in the cash flow projections used in the 2011 goodwill impairment testing.

• Enterprise value based on internally developed cash flow projections reflected annual estimates through 2018, with a terminal year value calculated using the "Gordon Growth Formula."

Changes in the above and other assumptions could materially affect the calculated amount of implied goodwill.

In the fourth quarter 2013, we recorded a $1.0 billion goodwill impairment charge. In the fourth quarter 2012, we recorded an estimated goodwill impairment charge of $1.2 billion pending finalization of the fair value calculations, which were completed in the first quarter 2013 without any adjustment to the amount recorded. The impairment charges in 2013 and 2012 reflected declines in our estimated enterprise value. The declines reflected lower wholesale electricity prices, reflecting the sustained decline in natural gas prices, and the maturing of positions in our natural gas hedge program, as well as declines in market values of securities of comparable companies.

The impairment determinations involved significant assumptions and judgments. The calculations supporting the estimates of the enterprise value of our business and the fair values of its operating assets and liabilities utilized models that take into consideration multiple inputs, including commodity prices, discount rates, capital expenditures, the effects of environmental rules, securities prices of comparable publicly traded companies and other inputs, assumptions regarding each of which could have a significant effect on valuations. The fair value measurements resulting from these models are classified as non-recurring Level 3 measurements consistent with accounting standards related to the determination of fair value (see Note 13). Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

109

Identifiable Intangible Assets

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

	December 31, 2013						December 31, 2012
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	402	$	61	$	463	$	378	$	85
Favorable purchase and sales contracts	352		139		213		552		314		238
Software and other computer-related assets	348		147		201		320		112		208
Environmental allowances and credits (a)	209		20		189		594		393		201
Mining development costs	156		69		87		163		82		81
Total identifiable intangible assets subject to amortization	$	1,528	$	777	751		$	2,092	$	1,279	813
Retail trade name (not subject to amortization)					955						955
Mineral interests (not currently subject to amortization) (b)					11						13
Total identifiable intangible assets					$	1,717					$	1,781

___________

(a) See discussion below regarding impairment of emission allowance intangible assets in 2011 (reported in other deductions) as a result of the EPA's issuance of the CSAPR in July 2011.

(b) In 2012, we recorded an impairment charge (reported in other deductions) totaling $24 million related to certain mineral interests whose fair value declined as a result of lower expected natural gas drilling activity and prices. The impairment was based on a Level 3 valuation (see Note 13).

At December 31, 2013, amounts related to fully amortized assets that are expired or of no economic value have been excluded from both the gross carrying and accumulated amortization amounts.

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

Identifiable Intangible Asset	Income Statement Line	Useful lives at December 31, 2013 (weighted average in years)	Year Ended December 31,
			2013		2012		2011
Retail customer relationship	Depreciation and amortization	4	$	24	$	34	$	51
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	10	24		25		31
Software and other computer-related assets	Depreciation and amortization	4	47		34		29
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	24	14		18		71
Mining development costs	Depreciation and amortization	3	31		27		38
Total amortization expense (a)			$	140	$	138	$	220

____________

(a) Amounts recorded in depreciation and amortization totaled $102 million, $95 million and $118 million in 2013, 2012 and 2011, respectively.

110

Following is a description of the separately identifiable intangible assets recorded as part of purchase accounting for the Merger. The intangible assets were recorded at estimated fair value as of the Merger date, based on observable prices or estimates of fair value using valuation models.

• Retail customer relationship – Retail customer relationship intangible asset represents the fair value of the non-contracted customer base and is being amortized using an accelerated method based on customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.

• Favorable purchase and sales contracts – Favorable purchase and sales contracts intangible asset primarily represents the above market value of commodity contracts for which: (i) we had made the "normal" purchase or sale election allowed by accounting standards related to derivative instruments and hedging transactions or (ii) the contracts did not meet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of the contracts. Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 18).

• Retail trade name – The trade name intangible asset represents the fair value of the TXU Energy trade name, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other intangible assets.

• Environmental allowances and credits – This intangible asset represents the fair value of environmental credits, substantially all of which were expected to be used in our power generation activities. These credits are amortized utilizing a units-of-production method.

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
2014	$	148
2015	$	135
2016	$	108
2017	$	83
2018	$	58

Cross-State Air Pollution Rule Issued by the EPA

In 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR), compliance with which would have required significant additional reductions of sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions from our fossil fueled generation units. In order to meet the emissions reduction requirements by the dates mandated, we determined at that time it would be necessary to idle certain lignite/coal fueled generation units and reduce our reliance on lignite coal, resulting in a plan to cease certain lignite mining operations in early 2012. The plan to cease operations at the mines required an evaluation of the remaining useful lives and recoverability of recorded values of tangible and intangible assets related to the mines. This evaluation resulted in the recording of accelerated depreciation and amortization expense in 2011 related to mine assets totaling $44 million. We also recorded asset impairments totaling $9 million related to capital projects in progress at the mines.

Additionally, because of emissions allowance limitations under the CSAPR, we would have had excess SO₂ emission allowances under the Clean Air Act's existing acid rain cap-and-trade program, and market values of such allowances were estimated to be de minimis based on Level 3 fair value estimates, which are described in Note 13. Accordingly, we recorded a noncash impairment charge of $418 million (before deferred income tax benefit) related to our existing SO₂ emission allowance intangible assets in 2011. SO₂ emission allowances granted to us were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger.

In light of a judicial stay of the CSAPR at the end of 2011 and the U.S. Court of Appeals' for the District of Columbia Circuit 2012 decision to vacate the CSAPR and remand it to the EPA for further proceedings (see Note 11), we did not idle the generation units and did not cease the lignite mining operations.

111

5. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES

Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.

EFH Corp. and its subsidiaries file or have filed income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of income tax returns filed by EFH Corp. and any of its subsidiaries for the years ending prior to January 1, 2007 are complete. Federal income tax returns are under examination for tax years 2007 to 2009. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2006.

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 related to one significant accounting method issue and other less significant issues. As a result of the agreement on terms with the IRS, we reduced the liability for uncertain tax positions to reflect the terms of the agreement, resulting in a net decrease of $794 million, including $139 million in interest accruals.

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. As a result, we reduced the liability for uncertain tax positions to reflect the effects of the settlement, resulting in a net decrease of $84 million. 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, under the Federal and State Income Tax Allocation Agreement (see Note 6).

In total, the settlements in March and May 2013 resulted in an increase of $1.063 billion in the accumulated deferred income tax liability, and an income tax benefit of $80 million. Of the total income tax benefit, $90 million (after-tax)was attributable to the release of accrued interest. In addition, in accordance with the provisions of the Federal and State Income Tax Allocation Agreement with EFH Corp., amounts previously reported as accumulated deferred income taxes totaling $535 million were reclassified to the liability to EFH Corp. under the Federal and State Income Tax Allocation Agreement, the total amount of which is not expected to be settled within the next twelve months. The settlements resulted in the elimination of net operating loss carryforwards and a substantial majority of alternative minimum tax credit carryforwards generated through 2013.

In September 2013, the US Treasury and the IRS issued final tangible property regulations that relate to repair and maintenance costs. As a result of our analysis of these regulations, in the fourth quarter 2013 we reduced the liability for uncertain tax positions by $159 million and reclassified that amount to the accumulated deferred income tax liability and recorded a $6 million income tax benefit representing a reversal of accrued interest.

We classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled an expense of $13 million and $15 million in 2012 and 2011, respectively, (all amounts after tax). Ongoing accruals of interest in 2013 are not material.

Noncurrent liabilities included a total of $11 million and $172 million in accrued interest at December 31, 2013 and 2012, respectively. The federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes.

The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheet, during the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
	2013			2012			2011
Balance at January 1, excluding interest and penalties	$	1,078		$	1,069		$	931
Additions based on tax positions related to prior years	246			19			80
Reductions based on tax positions related to prior years	(1,070		)	(33		)	(6		)
Additions based on tax positions related to the current year	13			23			64
Settlements with taxing authorities	(74		)	—			—
Balance at December 31, excluding interest and penalties	$	193		$	1,078		$	1,069

112

Of the balance at December 31, 2013, $122 million represents tax positions for which the uncertainty relates to the timing of recognition in tax returns. The disallowance of such positions would not affect the effective tax rate, but could accelerate the payment of cash to the taxing authority to an earlier period.

With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should EFH Corp. sustain such positions on income tax returns previously filed, our liabilities recorded would be reduced by $71 million, and accrued interest would be reversed resulting in a $6 million after-tax benefit, resulting in increased net income and a favorable impact on the effective tax rate.

Other than the items discussed above, we do not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.

113

6. INCOME TAXES

EFH Corp. files a US federal income tax return that includes the results of EFCH and TCEH. EFH Corp. and its subsidiaries (including EFCH and TCEH) are parties to a Federal and State Income Tax Allocation Agreement, which provides for the computation of income tax liabilities and benefits, and 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.

The components of our income tax expense (benefit) are as follows:

	Year Ended December 31,
	2013			2012			2011
Current:
US Federal	$	(166	)	$	(7	)	$	125
State	41			35			48
Total current	(125		)	28			173
Deferred:
US Federal	(611		)	(932		)	(1,120		)
State	(1		)	(20		)	4
Total deferred	(612		)	(952		)	(1,116		)
Total	$	(737	)	$	(924	)	$	(943	)

Reconciliation of income taxes computed at the US federal statutory rate to income tax benefit recorded:

	Year Ended December 31,
	2013			2012			2011
Loss before income taxes	$	(3,054	)	$	(3,932	)	$	(2,745	)
Income taxes at the US federal statutory rate of 35%	$	(1,069	)	$	(1,376	)	$	(961	)
IRS audit and appeals settlement	(80		)	—			—
Nondeductible goodwill impairment	350			420			—
Texas margin tax, net of federal benefit	8			9			33
Lignite depletion allowance	(12		)	(19		)	(23		)
Production activities deduction	—			—			(20		)
Interest accrued for uncertain tax positions, net of tax	(17		)	14			15
Nondeductible interest expense	21			20			14
Nondeductible debt restructuring costs	4			—			—
Impairment of joint venture assets attributable to noncontrolling interests (Note 8)	37			—			—
Reversal of previously disallowed interest resulting from debt exchanges	—			—			(1		)
Other	21			8			—
Income tax benefit	$	(737	)	$	(924	)	$	(943	)
Effective tax rate	24.1		%	23.5		%	34.4		%

114

Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2013 and 2012 are as follows:

	December 31,
	2013							2012
	Total		Current			Noncurrent		Total		Current		Noncurrent
Deferred Income Tax Assets
Alternative minimum tax credit carryforwards	$	22	$	—		$	22	$	222	$	—	$	222
Net operating loss (NOL) carryforwards	—		—			—		428		—		428
Unfavorable purchase and sales contracts	210		—			210		221		—		221
Commodity contracts and interest rate swaps	208		188			20		—		—		—
Debt extinguishment gains	831		—			831		749		—		749
Employee benefit obligations	49		5			44		42		—		42
Accrued interest	236		—			236		235		—		235
Other	53		2			51		130		—		130
Total	1,609		195			1,414		2,027		—		2,027
Deferred Income Tax Liabilities
Property, plant and equipment	4,319		—			4,319		4,353		—		4,353
Commodity contracts and interest rate swaps	—		—			—		729		31		698
Identifiable intangible assets	491		—			491		522		—		522
Debt fair value discounts	186		—			186		213		—		213
Debt extinguishment gains	74		74			—		—		—		—
Other	—		—			—		18		18		—
Total	5,070		74			4,996		5,835		49		5,786
Net Accumulated Deferred Income Tax (Asset) Liability	$	3,461	$	(121	)	$	3,582	$	3,808	$	49	$	3,759

At December 31, 2013, we had $22 million in alternative minimum tax (AMT) credit carryforwards available to offset future tax payments. The AMT credit carryforwards have no expiration date. At December 31, 2013, we had no net operating loss (NOL) carryforwards for federal income tax purposes. As discussed in Note 5, audit settlements reached in 2013 resulted in the elimination of all NOL carryforwards generated through 2013 and substantially all available AMT credits.

The income tax effects of the components included in accumulated other comprehensive income at December 31, 2013 and 2012 totaled a net deferred tax asset of $19 million and $23 million, respectively.

See Note 5 for discussion regarding accounting for uncertain tax positions, including the effects of the resolution of IRS audit matters in 2013.

115

7. OTHER INCOME AND DEDUCTIONS

	Year Ended December 31
	2013		2012		2011
Other income:
Consent fee related to novation of hedge positions between counterparties	$	—	$	6	$	—
Insurance/litigation settlements	2		2		—
Sales tax refunds	—		—		5
Settlement of counterparty bankruptcy claims (a)	—		—		21
Property damage claim	—		—		7
Franchise tax refund	—		—		6
All other	7		5		9
Total other income	$	9	$	13	$	48
Other deductions:
Charges related to pension plan actions (Note 15)	$	—	$	141	$	—
Impairment of assets held by CPNPC (Note 8)	140		—		—
Impairment of mineral interests (Note 4)	—		24		—
Impairment of emission allowances (b)	—		—		418
Impairment of assets related to mining operations (b)	—		—		9
Other asset impairments	10		5		—
Counterparty contract settlement	—		4		—
Loss on sales of land	—		4		—
Net third-party fees paid in connection with the amendment and extension of the TCEH Senior Secured Facilities (Note 10)	—		1		86
All other	12		9		11
Total other deductions	$	162	$	188	$	524

____________

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

(b) Charges resulting from the EPA's issuance of the CSAPR in July 2011, including a $418 million impairment charge for excess emission allowances and $9 million in mining asset write-offs.

116

8. IMPAIRMENT OF ASSETS OF NUCLEAR GENERATION DEVELOPMENT JOINT VENTURE

In 2008, we filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at our existing Comanche Peak nuclear plant site. In connection with the filing of the application, in 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company LLC (CPNPC), to further the development of the two new nuclear generation units using MHI's US-Advanced Pressurized Water Reactor (US-APWR) technology. The TCEH subsidiary owns an 88% interest in CPNPC, and an MHI subsidiary owns a 12% interest. As discussed in Note 3, CPNPC is a consolidated VIE.

In the fourth quarter 2013, MHI notified us and the NRC of its plans to refocus MHI's US resources on the restart of nuclear reactors in Japan and thus reduce its support of review activities related to the NRC's Design Certification of MHI's US-APWR technology. As a result, Luminant has notified the NRC of its intent to suspend all reviews associated with the combined operating license application by March 31, 2014. Luminant does not intend to withdraw the license application at this time. MHI expressed to the NRC its continuing commitment to obtaining an NRC design certification for its technology. Luminant has filed a loan guarantee application with the DOE for financing the proposed units prior to commencement of construction and expects to continue to update the application in accordance with the loan solicitation guidelines.

In early 2014, MHI and Luminant expect to amend their development agreement. The amendments are expected to include provisions that allow the parties to unilaterally take certain actions with respect to future development activities, including cessation of such activities. MHI's decision and the expected amendment of the agreement triggered an analysis of the recoverability of the joint venture's assets.

Because of the significant uncertainty regarding the development of the nuclear generation units, considering the wholesale electricity price environment in ERCOT and risks related to financing and cost escalation, in the fourth quarter 2013 essentially all the joint venture's assets were impaired resulting in a charge of $140 million. The assets largely represented costs incurred related to the filing with the NRC of a combined operating license application, the filing with the DOE of a loan guarantee application and initial operational readiness activities for the two units. The charge is reported as other deductions. MHI's allocated portion of the impairment charge totaled $107 million and is reported in net loss attributable to noncontrolling interests in the statement of income. A deferred income tax benefit was recorded for our $33 million allocated portion of the impairment charge and is included in income tax benefit in the statement of income.

117

9. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

In October 2013, TCEH terminated its 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.

The TCEH securitization program was implemented in November 2012 upon the termination of a predecessor program that except as noted was substantially the same as TCEH's program and was accounted for similarly. Under the predecessor program, the borrowing entity was a wholly owned subsidiary of EFH Corp.

Under TCEH's 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 were reported in the financial statements as pledged balances, and the related funding amounts were reported as short-term borrowings.

The maximum funding amount available under the program was $200 million, which approximated the expected usage and applied only to receivables related to non-executory retail sales contracts. Program funding totaled $82 million at December 31, 2012.

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 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. There was no subordinated note limit under the predecessor program. The balance of the subordinated note payable, which was eliminated in consolidation, totaled $97 million at December 31, 2012.

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:

	Year Ended December 31,
	2013	2012	2011
Program fees	$5	$9	$9
Program fees as a percentage of average funding (annualized)	4.7%	6.7%	6.4%

118

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

	Year Ended December 31,
	2013			2012			2011
Cash collections on accounts receivable	$	3,589		$	4,566		$	5,080
Face amount of new receivables purchased (a)	(3,144		)	(4,496		)	(4,992		)
Discount from face amount of purchased receivables	32			11			11
Program fees paid to financial institution	(5		)	(9		)	(9		)
Servicing fees paid for recordkeeping and collection services	(1		)	(2		)	(2		)
Decrease in subordinated notes payable	(97		)	(323		)	(96		)
Settlement of accrued income taxes payable	(9		)	—			—
Cash contribution from TCEH, net of cash held	52			275			—
Capital distribution to TCEH upon termination of the program	(335		)	—			—
Cash flows used (provided) under the program	$	82		$	22		$	(8	)

____________

(a) Net of allowance for uncollectible accounts.

Trade Accounts Receivable

	December 31,
	2013			2012
Wholesale and retail trade accounts receivable	$	724		$	719
Allowance for uncollectible accounts	(14		)	(9		)
Trade accounts receivable — reported in balance sheet, including $— and $445 in pledged retail receivables	$	710		$	710

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

Allowance for Uncollectible Accounts Receivable

	Year Ended December 31,
	2013			2012			2011
Allowance for uncollectible accounts receivable at beginning of period	$	9		$	27		$	64
Increase for bad debt expense	33			26			56
Decrease for account write-offs	(28		)	(44		)	(67		)
Reversal of reserve related to counterparty bankruptcy (Note 7)	—			—			(26		)
Allowance for uncollectible accounts receivable at end of period	$	14		$	9		$	27

119

10. BORROWING FACILITIES AND DEBT

Debtor-In-Possession (DIP) Facility

TCEH DIP Facility— TCEH has received a binding commitment, subject to certain customary conditions, from certain financial institutions for a debtor-in-possession (DIP) facility described below (DIP Facility), and intends to file a motion with the Bankruptcy Court for approval of its DIP Facility. In general, the commitment would terminate (unless waived by the lenders) within 10 business days from the Petition Date in the event the Bankruptcy Court has not issued an interim order approving such financing.

The proposed TCEH DIP Facility is a Senior Secured, Super-Priority Credit Agreement by and among EFCH, the TCEH Debtors, the lenders that are party thereto from time to time and an administrative and collateral agent (the TCEH DIP Credit Agreement).

The TCEH DIP Facility provides for up to $4.475 billion in financing consisting of (i) a senior secured, super-priority revolving credit facility of up to $1.95 billion, (ii) a senior secured, super-priority delayed-draw term loan in the amount of up to $1.1 billion, and (iii) a senior secured, super-priority term loan in the amount of $1.425 billion.

The principal amounts outstanding under the TCEH DIP Facility bear interest based on applicable LIBOR or base rates plus applicable margins as set forth in the TCEH DIP Facility. The TCEH DIP Facility also provides for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available TCEH DIP Facility.

The TCEH DIP Facility will mature on the twenty-fourth month after the closing date of such facility. The maturity date may be extended to the thirtieth month after the closing date of the TCEH DIP Facility subject to the satisfaction of certain conditions, including the payment of a 25 basis points extension fee, a requirement that an acceptable plan of reorganization has been filed on or prior to such extension and the availability of certain metrics of liquidity applicable to the TCEH Debtors.

The TCEH Debtors' obligations under the TCEH DIP Facility will be secured by a lien covering substantially all of the TCEH Debtors' assets, rights and properties, subject to certain exceptions set forth in the TCEH DIP Facility. The TCEH DIP Facility provides that all obligations thereunder will constitute administrative expenses in the Chapter 11 Cases, with administrative priority and senior secured state under Section 364(c) and 364(d) of the Bankruptcy Code and, subject to certain exceptions set forth in the TCEH DIP Facility, will have priority over any and all administrative expense claims, unsecured claims and costs and expenses in the Chapter 11 Cases.

The TCEH DIP Facility provides for a specific carve-out related to mining reclamation requirements that TCEH's Luminant Mining subsidiary has with the RCT (the RCT Carve-Out); provided that the delayed-draw term loan under the TCEH DIP Facility may not be used so long as the RCT Carve-Out remains in place. The RCT Carve-Out would be used by Luminant Mining to secure up to $1.1 billion of its mining reclamation obligations with the RCT. The RCT Carve-Out would provide to the RCT a super-priority "carve out" from the super-priority liens under the TCEH DIP Facility that will enable the RCT to be paid before the TCEH DIP Facility lenders and the TCEH Debtor's prepetition secured creditors. In the event the RCT doesn't allow Luminant Mining to use the RCT Carve-Out, then TCEH could terminate the RCT Carve-Out and use the delayed-draw term loan to collateralize Luminant Mining's reclamation obligations with a cash collateralized letter of credit.

The TCEH DIP Facility also will permit certain hedging agreements to be secured on a pari-passu basis with the TCEH DIP Facility in the event those hedging agreements meet certain criteria set forth in the TCEH DIP Facility.

The TCEH DIP Facility provides for affirmative and negative covenants applicable to the TCEH Debtors, including affirmative covenants requiring the TCEH Debtors to provide financial information, budgets and other information to the agents under the TCEH DIP Facility, and negative covenants restricting the TCEH Debtors' ability to incur additional indebtedness, grant liens, dispose of assets, make investments, pay dividends or take certain other actions, in each case except as permitted in the TCEH DIP Facility. The TCEH Debtors' ability to borrow under the TCEH DIP Facility is subject to the satisfaction of certain customary conditions precedent set forth therein.

120

The TCEH DIP Facility provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or other amounts when due, material breaches of representations and warranties, material breaches of covenants in the TCEH DIP Facility or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against the TCEH Debtors. The TCEH DIP Facility also includes an event of default that may arise from our failure to meet a consolidated super-priority leverage test. Upon the existence of an event of default, the TCEH DIP Facility provides that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

Borrowings Under Other Credit Facilities

At December 31, 2013, outstanding borrowings totaled $2.054 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.67%, excluding customary fees. In October 2013, we terminated the accounts receivable securitization program and repaid all outstanding obligations under the program (see Note 9).

At December 31, 2012, outstanding 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 at December 31, 2013

The Bankruptcy Filing constituted an event of default under the TCEH credit facilities. Under the Bankruptcy Code, the creditors under such facilities are stayed from taking any action against the Debtors as a result of the default.

Credit facilities and related cash borrowings at December 31, 2013 are presented below. The facilities are all senior secured facilities of TCEH.

		December 31, 2013
Facility	Maturity Date	Facility Limit		Cash Borrowings		Available L/C Capacity
TCEH Revolving Credit Facility (a)	October 2016	$	2,054	$	2,054	$	—
TCEH Letter of Credit (L/C) Facility (b)	October 2017 (b)	1,062		1,062		195
Total TCEH		$	3,116	$	3,116	$	195

___________

(a) Facility used for borrowings for general corporate purposes. Borrowings are classified as borrowings under credit and other facilities. Borrowings under the facility bore interest at LIBOR plus 4.50%, and a commitment fee was 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 has a maturity date of 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 the TCEH L/C Facility have been recorded by TCEH as restricted cash that supports issuances of letters of credit. At December 31, 2013, the restricted cash held by TCEH totaled $945 million, after reduction for letters of credit drawn. At December 31, 2013, the restricted cash supports $750 million in letters of credit outstanding, leaving $195 million in available letter of credit capacity.

In the first quarter 2014, pollution control revenue bonds totaling $185 million in principal amount were tendered and the related letters of credit, which were outstanding at December 31, 2013, were drawn upon. Also in the first quarter 2014, TCEH issued a $157 million letter of credit to a subsidiary of EFH Corp. to secure its current and future amounts payable to the subsidiary arising from recurring transactions in the normal course of business, and the subsidiary drew on the letter of credit in the amount of $100 million to settle amounts receivable from TCEH. As a result of these transactions, the restricted cash amount was reduced by $285 million to $660 million. Through March 31, 2014, available capacity under the TCEH L/C Facility was reduced by $34 million in net letter of credit issuances in 2014 to unaffiliated counterparties in addition to the $157 million letter of credit issued to a subsidiary of EFH Corp., resulting in $4 million of available capacity at that date. As a result of the Bankruptcy Filing, the available letter of credit capacity cannot be utilized.

121

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.

122

Debt

The Bankruptcy Filing constituted an event of default under the Credit Agreement governing the TCEH Senior Secured Facilities and the indentures governing the company's other debt instruments listed below as well as capital lease obligations, and those debt obligations became immediately due and payable. As a result, the accompanying consolidated balance sheet as of December 31, 2013 presents all debt classified as current. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against the Debtors as a result of the default.

At December 31, 2013 and 2012, notes, loans and other debt consisted of the following:

	December 31,
	2013			2012
TCEH
Senior Secured Facilities:
3.730% TCEH Term Loan Facilities with maturity date of October 10, 2014 (a)(b)	$	3,809		$	3,809
3.669% TCEH Letter of Credit Facility with maturity date of October 10, 2014 (b)	42			42
4.730% TCEH Term Loan Facilities with maturity date of October 10, 2017 (a)(b)(c)	15,710			15,370
4.669% TCEH Letter of Credit Facility with maturity date of 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 was April 1, 2013	—			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
0.070% Floating Series 2001D-2 due May 1, 2033 (d)	97			97
0.220% Floating Taxable Series 2001I due December 1, 2036 (e)	62			62
0.070% Floating Series 2002A due May 1, 2037 (d)	45			45
6.75% Fixed Series 2003A due April 1, 2038, remarketing date was April 1, 2013	—			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 (f)	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)	(105		)	(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

123

	December 31,
	2013			2012
Capital leases	52			64
Other	3			3
Unamortized discount	(103		)	(10		)
Unamortized fair value discount (g)	—			(1		)
Total TCEH	30,086			29,880
EFCH (parent entity)
9.58% Fixed Notes due in annual installments through December 4, 2019 (h)	29			35
8.254% Fixed Notes due in quarterly installments through December 31, 2021 (h)	34			39
1.042% 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	66			76
EFH Corp. debt pushed down (i)
10% Fixed Senior Secured First Lien Notes due January 15, 2020	—			330
9.75% Fixed Senior Secured First Lien 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)	96			526
Subtotal	30,182			30,406
Less amount due currently held by affiliates	(382		)	—
Less amount due currently	(29,800		)	(96		)
Less amount held by affiliates (Note 17)	—			(382		)
Total EFCH consolidated	$	—		$	29,928

____________

(a) Interest rate swapped to fixed on $18.19 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 December 31, 2013.

(c) As discussed below and in Note 17, principal amounts of notes/term loans totaling $382 million at both December 31, 2013 and 2012 were held by EFH Corp. and EFIH.

(d) Interest rates in effect at December 31, 2013. These series are in a daily interest rate mode and are supported by long-term irrevocable letters of credit. In March 2014, $80 million principal amount of the 2001D-2 bonds due May 1, 2033 and all $45 million principal amount of the 2002A bonds due May 1, 2037 were tendered and the related letters of credit were drawn upon.

(e) Interest rate in effect at December 31, 2013. This series is in a weekly interest rate mode and is supported by long-term irrevocable letters of credit. In March 2014, $60 million principal amount of these bonds were tendered and the related letters of credit were drawn upon.

(f) This series is in the multiannual interest rate mode and is 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.

(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."

124

Debt Related Activity in 2013

Principal amounts of debt issued in the year ended December 31, 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 debt in the year ended December 31, 2013 totaled $105 million and consisted of $93 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 $12 million of contractual payments under capital leases.

In April 2013, TCEH acquired for $40 million in cash the owner participant interest in a trust established to lease six natural gas 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 December 31, 2013, the principal amount of the trust's debt totaled $36 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 distribution 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.

Debt Related Activity in 2012

Issuances of debt in 2012 consisted of $181 million of TCEH Toggle Notes issued through the PIK election, in lieu of making cash interest payments.

Repayments of long-term debt in the year ended December 31, 2012 totaled $40 million and consisted of $26 million of payments of principal at scheduled maturity dates and $14 million of contractual payments under capital leases.

Issuance of EFIH Toggle Notes in Exchange for EFH Corp. Debt Guaranteed by EFCH —In exchanges in December 2012, EFIH and EFIH Finance issued $1.304 billion principal amount of EFIH Toggle Notes in exchange for $1.761 billion total principal amount of EFH Corp. debt consisting of $132 million of EFH Corp. 10.875% Notes, $432 million of EFH Corp. Toggle Notes and $1.197 billion of other EFH Corp. unsecured debt. The EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes in these exchanges were guaranteed by EFCH as discussed below in “Guarantees and Push Down of EFH Corp. Debt.”

125

Guarantees 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 December 31, 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 December 31, 2013 and 2012, respectively, as shown in the 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.

Payments of interest by EFH Corp. on debt pushed down totaled $23 million, $53 million and $60 million in the years ended December 31, 2013, 2012 and 2011, respectively.

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 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 (c)		Total Guaranteed December 31, 2013 (d)
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 17.

(c) See discussion above regarding distributions by EFIH to EFH Corp. of its holdings of EFH Corp. debt.

(d) These amounts are subject to push down.

126

Information Regarding Other Significant Outstanding Debt

TCEH Senior Secured Facilities — Borrowings under the TCEH Senior Secured Facilities totaled $22.635 billion at December 31, 2013 and consisted of:

• $3.809 billion of TCEH Term Loan Facilities that have a maturity date in October 2014 with interest payable at LIBOR plus 3.50%;

• $15.710 billion of TCEH Term Loan Facilities that have a maturity date in October 2017 with interest payable at LIBOR plus 4.50%, including $19 million aggregate principal amount held by EFH Corp;

• $42 million of cash borrowed under the TCEH Letter of Credit Facility that have a maturity date 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 that have a maturity date 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 December 31, 2013. See "Credit Facilities" above for discussion regarding the maturity date extension of $645 million in commitments from 2013 to 2016.

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. See Note 2 for discussion of the default under the TCEH Senior Secured Facilities.

TCEH 11.5% Senior Secured Notes —At December 31, 2013, the principal amount of the TCEH 11.5% Senior Secured Notes totaled $1.750 billion. The notes have a maturity date 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.

The guarantees of the TCEH Senior Secured Notes by the Guarantors are effectively senior to any unsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. The guarantees are effectively subordinated to all debt of the Guarantors secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt.

TCEH 15% Senior Secured Second Lien Notes(including Series B)— At December 31, 2013, the principal amount of the TCEH 15% Senior Secured Second Lien Notes totaled $1.571 billion. These notes have a maturity date 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.

127

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.

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

TCEH 10.25% Senior Notes (including Series B) and 10.50%/11.25% Senior Toggle Notes (collectively, the TCEH Senior Notes)— At December 31, 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 have a maturity date 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 have a maturity date 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.

Material Cross Default/Acceleration Provisions — Certain of our financing arrangements contain provisions that 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. The Bankruptcy Filing triggered defaults on our debt obligations, but pursuant to the Bankruptcy Code, the creditors are stayed from taking any actions against the Debtors as a result of such defaults.

Intercreditor Agreement — TCEH has entered into an intercreditor agreement with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). The intercreditor agreement takes into account, among other things, the possibility that TCEH could have issued notes and/or loans secured by collateral (other than the collateral that secures the TCEH Senior Secured Facilities) that ranks on parity with, or junior to, TCEH's existing first lien obligations under the TCEH Senior Secured Facilities. The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties ranks pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties are entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties' lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.

128

Second Lien Intercreditor Agreement — TCEH has also entered into a second lien intercreditor agreement (the Second Lien Intercreditor Agreement) with Citibank, N.A., as senior collateral agent, and The Bank of New York Mellon Trust Company, N.A., as initial second priority representative. The Second Lien Intercreditor Agreement provides that liens on the collateral that secure the obligations under the TCEH Senior Secured Facilities, the obligations of the Secured Commodity Hedge Counterparties and any other obligations which are permitted to be secured on a pari passu basis therewith (collectively, the First Lien Obligations) rank prior to the liens on such collateral securing the obligations under the TCEH Senior Secured Second Lien Notes, and any other obligations which are permitted to be secured on a pari passu basis (collectively, the Second Lien Obligations). The Second Lien Intercreditor Agreement provides that the holders of the First Lien Obligations are entitled to the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral until paid in full, and that the holders of the Second Lien Obligations are not entitled to receive any such proceeds until the First Lien Obligations have been paid in full. The Second Lien Intercreditor Agreement also provides that the holders of the First Lien Obligations control enforcement actions with respect to such collateral, and the holders of the Second Lien Obligations are not entitled to commence any such enforcement actions, with limited exceptions. The Second Lien Intercreditor Agreement also provides that releases of the liens on the collateral by the holders of the First Lien Obligations automatically require that the liens on such collateral by the holders of the Second Lien Obligations be automatically released, and that amendments, waivers or consents with respect to any of the collateral documents in connection with the First Lien Obligations apply automatically to any comparable provision of the collateral documents in connection with the Second Lien Obligations.

Fair Value of Debt

At December 31, 2013 and 2012, the estimated fair value of our notes, loans and other debt (excluding capital leases) totaled $16.588 billion and $17.858 billion, respectively, and the carrying amount totaled $30.130 billion and $30.342 billion, respectively. At December 31, 2013 and 2012, the estimated fair value of our borrowings under the TCEH Revolving Credit Facilities totaled $1.397 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 13, and at December 31, 2013, our debt fair value represents Level 2 valuations. We obtain security pricing from a vendor who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.

TCEHInterest Rate Swap Transactions

TCEH has employed interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at December 31, 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%	January 2014 through October 2014		$	18.19	billion (a)
6.8	%	-	9.0%	October 2015 through October 2017		$	12.60	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 $1.330 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 December 31, 2013 totaled $1.050 billion notional amount, a decrease of $10.917 billion from December 31, 2012 reflecting expired swaps. The remaining basis swaps expire in August 2014.

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

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

	Year Ended December 31,
	2013			2012			2011
Realized net loss	$	(620	)	$	(670	)	$	(684	)
Unrealized net gain (loss)	1,053			166			(812		)
Total	$	433		$	(504	)	$	(1,496	)

129

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.012 billion and $2.065 billion at December 31, 2013 and 2012, respectively, of which $56 million and $65 million (both pretax), respectively, were reported in accumulated other comprehensive income. The net liability reflects a nonperformance risk adjustment as discussed in Note 13.

The Bankruptcy Filing constituted an event of default under the interest rate swap agreements, and because the agreements are deemed to be "forward contracts" under the Bankruptcy Code, the counterparties may elect to terminate the agreements. See Note 14 for discussion of classification of the interest rate swap derivative liabilities as current.

130

11. COMMITMENTS AND CONTINGENCIES

Contractual Commitments

At December 31, 2013, we had noncancellable commitments under energy-related contracts, leases and other agreements as follows:

	Coal purchase  and transportation agreements		Pipeline transportation and storage reservation fees		Nuclear Fuel Contracts		Other Contracts
2014	$	344	$	31	$	152	$	101
2015	270		12		189		27
2016	157		1		115		26
2017	136		1		111		24
2018	43		1		149		21
Thereafter	—		9		530		120
Total	$	950	$	55	$	1,246	$	319

Expenditures under our coal purchase and coal transportation agreements totaled $353 million, $245 million and $463 million for the years ended December 31, 2013, 2012 and 2011, respectively.

In consideration of the Bankruptcy Filing, all capital lease liabilities are classified as current at December 31, 2013 (also see Note 10). At December 31, 2013, future minimum lease payments under both capital leases and operating leases are as follows:

	Capital Leases		Operating Leases (a)
2014	$	10	$	26
2015	7		26
2016	6		24
2017	35		34
2018	—		32
Thereafter	—		151
Total future minimum lease payments	58		$	293
Less amounts representing interest	6
Present value of future minimum lease payments	52
Less current portion	52
Long-term capital lease obligation	$	—

___________

(a) Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.

Rent reported as operating costs, fuel costs and SG&A expenses totaled $57 million, $72 million and $66 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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 10 for discussion of guarantees and security for certain of our debt and EFCH guarantees of certain EFH Corp. debt.

131

Letters of Credit

At December 31, 2013, TCEH had outstanding letters of credit under its credit facilities totaling $750 million as follows:

• $317 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;

• $61 million to support TCEH's REP financial requirements with the PUCT, and

• $164 million for miscellaneous credit support requirements.

See Note 10 for discussion of letter of credit draws in 2014.

The Bankruptcy Filing may result in some or all letter of credit beneficiaries drawing on their letters of credit if the terms of a particular letter of credit so provide. The automatic stay will not prevent third parties from drawing on their letters of credit.

Litigation

Aurelius Capital Master, Ltd. and ACP Master, Ltd. (Aurelius) filed a lawsuit in March 2013, amended in May 2013, in the US 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 alleged 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 sought recovery for the benefit of EFCH. EFCH and the directors filed a motion to dismiss this lawsuit in June 2013. In January 2014, the district court granted the motion to dismiss and in February 2014 entered final judgment dismissing the lawsuit. In January 2014, the district court granted the motion to dismiss and in February 2014 entered final judgment dismissing the lawsuit. Aurelius has appealed the district court's judgment to the US Court of Appeals for the Fifth Circuit (Fifth Circuit 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. Oral argument was held in April 2014. 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 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 (a wholly owned subsidiary of TCEH) for alleged violations of the Clean Air Act (CAA) at Luminant's Big Brown generation facility. The Big Brown trial was held in February 2014. In pre-trial filings submitted in January 2014, the Sierra Club stated it was seeking over $337 million in civil penalties for the alleged violations and injunctive relief. In March 2014, the district court entered final judgment denying all of the Sierra Club's claims and all relief requested by the Sierra Club. The Sierra Club has appealed the district court's decision to the Fifth Circuit Court.

In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC for alleged violations of the CAA at Luminant's Martin Lake generation facility. In April 2014, the Martin Lake trial setting of May 2014 was vacated by the district court so that the district court could consider the effects of the decision in the Big Brown case. The Sierra Club has stated that it intends to ask the district court in this case to impose civil penalties of approximately $147 million. The Sierra Club has also stated that the district court can impose the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation depending on the date of the alleged violation. In addition, the Sierra Club has requested injunctive relief, including the installation of new emissions control equipment at the plant. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. While we are unable to estimate any possible loss or predict the outcome of the Martin Lake case, we believe that, as the judge ruled in the Big Brown case, the Sierra Club's claims are without merit, and we intend to vigorously defend the lawsuit.

132

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.

Notwithstanding the foregoing, the affirmative claims asserted against EFH Corp. and Luminant Generation Company LLC described above were automatically stayed as a result of the Bankruptcy Filing. The matters will be subject to resolution in accordance with the Bankruptcy Code and the orders of the Bankruptcy Court.

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 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 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. The consolidated cases are now fully briefed and before the Fifth Circuit Court. Oral argument has been scheduled for June 2014.

In August 2013, the US 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. In January 2014, the district court granted our motion to stay the lawsuit until the Fifth Circuit Court resolves our petitions for 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 against these allegations. The lawsuit requests civil penalties of up to $32,500 to $37,500 per day for each alleged violation (the maximum penalties available under the CAA), depending on the date of the alleged violation, and injunctive relief, including an order requiring the installation of best available control technology at the affected units. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. 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.

133

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's decision. The US Supreme Court granted review of the D.C. Circuit Court's decision in June 2013 and heard oral arguments in December 2013. In April 2014, the US Supreme Court issued its opinion in the CSAPR litigation, reversing the D.C. Circuit Court's decision in which that court vacated CSAPR. The US Supreme Court has remanded the case to the D.C. Circuit Court for further proceedings consistent with its opinion. We are evaluating the decision and cannot predict the timing or outcome of future proceedings related to CSAPR, including any compliance timeframe or the financial effects, if any.

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. In February 2014, the Fifth Circuit Court ordered the EPA to issue a final rule on the standard permit for pollution control projects by May 19, 2014. We cannot predict the 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.

134

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.

Environmental Contingencies

See discussion above regarding the CSAPR issued by the EPA in July 2011 and revised in February 2012 that include provisions which, among other things, place limits on SO₂ and NO_X emissions produced by electricity generation plants. The CSAPR provisions and the Mercury and Air Toxics Standard (MATS) issued by the EPA in December 2011 would require substantial additional capital investment in our lignite/coal fueled generation facilities.

We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. We believe that we are in compliance with current environmental laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable and could materially affect our financial condition, results of operations and liquidity.

The costs to comply with environmental regulations could be significantly affected by the following external events or conditions:

• enactment of state or federal regulations regarding CO₂and other greenhouse gas emissions;

• other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters, including revisions to CAIR currently being developed by the EPA as a result of court rulings discussed above and MATS, and

• the identification of sites requiring clean-up or the filing of other complaints in which we may be asserted to be a potential responsible party under applicable environmental laws or regulations.

Labor Contracts

Certain personnel engaged in TCEH activities are represented by labor unions and covered by collective bargaining agreements with varying expiration dates. In November 2011, three-year labor agreements were reached covering bargaining unit personnel engaged in lignite fueled generation operations (excluding Sandow) and lignite mining operations (excluding Three Oaks). In March 2014, these agreements were extended for an additional year through November 2015. Also in November 2011, a four-year labor agreement was reached covering bargaining unit personnel engaged in natural gas fueled generation operations. In January and August 2013, labor agreements expiring in November 2015 were reached covering bargaining unit personnel engaged in the Three Oaks lignite mining operations and the Sandow lignite fueled generation operations, respectively. In December 2013, a labor agreement expiring in August 2015 was reached covering bargaining unit personnel engaged in nuclear fueled generation operations. We do not expect any changes in collective bargaining agreements to have a material effect on our results of operations, liquidity or financial condition.

Nuclear Insurance

Nuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverage and accidental outage and/or extra expense coverage. Nuclear insurance maintained meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. The company is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses could have a material effect on our financial condition and results of operations and liquidity.

135

With regard to liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $13.6 billion and requires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.6 billion limit for a single incident mandated by the Act. As required, the company provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As the first layer of financial protection, the company has $375 million of liability insurance from American Nuclear Insurers (ANI), a joint underwriting association created by some of the largest insurance companies in the US. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP). Neither the primary nor secondary layers of financial protection are subject to any deductibles.

Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in the US is subject to an assessment of up to $127.3 million and this amount is subject to increases for inflation every five years, with the next adjustment expected in September 2018. Assessments are currently limited to $19 million per operating licensed reactor per year per incident. The company's maximum potential assessment under the industry retrospective plan would be $254.6 million per incident but no more than $37.9 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375 million per accident at any nuclear facility.

With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plant license-holders maintain at least $1.06 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. The company maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $2.25 billion (subject to $5 million deductible per accident), above which the company is self-insured. This insurance coverage consists of a primary layer of coverage of $1.750 billion provided by Nuclear Electric Insurance Limited (NEIL). The European Mutual Association for Nuclear Insurance (EMANI) provides additional insurance limits of $500 million in excess of NEIL's $1.75 billion coverage.

The company maintains Accidental Outage insurance through NEIL to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The total maximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.

If NEIL's or EMANI's losses exceeded their reserves for the applicable coverage, potential assessments in the form of a retrospective premium call could be made up to ten times annual premiums in the case of NEIL and up to six times annual premiums in the case of EMANI. The company maintains insurance coverage against these potential retrospective premium calls.

Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.

136

12. MEMBERSHIP INTERESTS/EQUITY

Cash Distributions to Parent

We paid no cash distributions to EFH Corp. in 2013, 2012 or 2011.

Dividend Restrictions

While EFCH has no contractual dividend restrictions, the TCEH Senior Secured Facilities generally restricted 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 December 31, 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 restricted TCEH's ability to make distributions or loans to any of its parent companies, EFCH and EFH Corp., unless such distributions or loans were expressly permitted under the TCEH Senior Secured Facilities and the indentures governing such notes.

Under applicable law, we were also prohibited from paying any distribution to the extent that immediately following payment of such distribution, we would be insolvent.

Noncontrolling Interests

As discussed in Notes 3 and 8, 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 noncontrolling interests of $107 million for the year ended December 31, 2013 reflected the noncontrolling interest share of the impairment of the assets of the nuclear generation development joint venture. As discussed in Notes 3 and 9, prior to November 2012, we also consolidated a VIE owned by EFH Corp. related to our accounts receivable securitization program, which resulted in a noncontrolling interests component of equity. Net loss attributable to the noncontrolling interests was immaterial for the years ended December 31, 2012 and 2011.

137

13. 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 14 for additional information regarding credit risk associated with our derivatives). We utilize published credit ratings, default rate factors and debt trading values in calculating these fair value measurement adjustments.

138

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 on a recurring basis consisted of the following:

	December 31, 2013
	Level 1		Level 2		Level 3 (a)		Total
Assets:
Commodity contracts	$	161	$	570	$	57	$	788
Interest rate swaps	—		—		—		—
Nuclear decommissioning trust – equity securities (b)	330		191		—		521
Nuclear decommissioning trust – debt securities (b)	—		270		—		270
Total assets	$	491	$	1,031	$	57	$	1,579
Liabilities:
Commodity contracts	$	231	$	14	$	18	$	263
Interest rate swaps	—		—		1,012		1,012
Total liabilities	$	231	$	14	$	1,030	$	1,275

	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 (b)	249		144		—		393
Nuclear decommissioning trust – debt securities (b)	—		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) The nuclear decommissioning trust investment is included in the investments line in the balance sheet. See Note 18.

139

Because certain of these instruments are deemed to be "forward contracts" under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements.

Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal agreements and include financial instruments entered into for hedging purposes as well as physical contracts that have not been designated "normal" purchases or sales. See Note 14 for further discussion regarding the company's use of derivative instruments.

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 10 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 years ended December 31, 2013, 2012 and 2011. 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 for the years ended December 31, 2013, 2012 and 2011.

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 December 31, 2013 and 2012:

December 31, 2013
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	2	$	(2	)	$	—		Valuation Model	Illiquid pricing locations (c)	$25 to $45/MWh
										Hourly price curve shape (d)	$20 to $70/MWh
Electricity spread options	15		(2		)	13			Option Pricing Model	Gas to power correlation (e)	45% to 95%
										Power volatility (f)	10% to 30%
Electricity congestion revenue rights	35		(2		)	33			Market Approach (g)	Illiquid price differences between settlement points (h)	$0.00 to $25.00
Coal purchases	—		(11		)	(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	—		(1,012		)	(1,012		)	Valuation Model	Nonperformance risk adjustment (l)	25% to 35%
Other	5		(1		)	4
Total	$	57	$	(1,030	)	$	(973	)

140

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 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 debt trading values. See discussion immediately below regarding transfers into Level 3.

141

The following table presents the changes in fair value of the Level 3 assets and liabilities for the years ended December 31, 2013, 2012 and 2011. 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 10). At December 31, 2013, the estimated fair value of these interest rate swaps totaled $1.363 billion before consideration of nonperformance risk adjustment and $1.012 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.

	Year Ended December 31,
	2013			2012			2011
Net asset balance at beginning of period	$	29		$	53		$	342
Total unrealized valuation losses	(48		)	(17		)	(1		)
Purchases, issuances and settlements (a):
Purchases	92			73			117
Issuances	(7		)	(23		)	(15		)
Settlements	138			(12		)	(41		)
Transfers into Level 3 (b)	(1,181		)	(42		)	—
Transfers out of Level 3 (b)	4			(3		)	(349		)
Net change (c)	(1,002		)	(24		)	(289		)
Net asset (liability) balance at end of period	$	(973	)	$	29		$	53
Unrealized valuation gains (losses) relating to instruments held at end of period	435			(24		)	17

____________

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

(b) Includes transfers due to changes in the observability of significant inputs. Transfers in and out occur at the end of each quarter, which is when the assessments are performed. Transfers out during 2012 reflect increased observability of pricing related to certain congestion revenue rights. Transfers in during 2012 were driven by an increase in nonperformance risk adjustments related to certain coal purchase contracts as well as certain power contracts that include unobservable inputs related to the hourly shaping of the price curve. Transfers out during 2011 were driven by the effect of an increase in option market trading activity on our natural gas collars for 2014 and increased liquidity in forward periods for coal purchase contracts for 2014. All Level 3 transfers during the years 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.

142

14. 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 natural gas hedging positions and the hedging of interest costs on our debt. See Note 13 for a discussion of the fair value of derivatives. Because certain of these instruments are deemed to be "forward contracts" under the Bankruptcy Code, they are not subject to the automatic stay, and counterparties may elect to terminate the agreements.

Commodity Hedging and Trading Activity — TCEH has natural gas hedging positions 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. TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2014 in order to hedge a portion of electricity price exposure related to expected lignite/coal and nuclear fueled generation. TCEH also enters into derivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for short-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets. Unrealized gains and losses arising from changes in the fair value of hedging and trading instruments 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 10 for additional information about interest rate swap agreements.

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 December 31, 2013 and 2012:

December 31, 2013
	Derivative assets				Derivative liabilities
	Commodity contracts		Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	784	$	—	$	—		$	—		$	784
Noncurrent assets	4		—		—			—			4
Current liabilities	—		—		(263		)	(1,012		)	(1,275		)
Net assets (liabilities)	$	788	$	—	$	(263	)	$	(1,012	)	$	(487	)

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	)

The Bankruptcy Filing constituted an event of default under the interest rate swap agreements and certain commodity contract agreements, and because the agreements are "forward contracts" under the Bankruptcy Code. the counterparties may elect to terminate the agreements. Consequently, the derivative liabilities are classified as current at December 31, 2013, including $647 million that otherwise would be classified as noncurrent, essentially all of which relates to interest rate swaps.

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

143

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

	Year Ended December 31,
Derivative (income statement presentation)	2013			2012			2011
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a)	$	(54	)	$	279		$	1,139
Interest rate swaps (Interest expense and related charges) (b)	433			(504		)	(1,496		)
Net gain (loss)	$	379		$	(225	)	$	(357	)

_______________

(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 18).

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 years ended December 31, 2013, 2012 or 2011.

Derivative (income statement presentation of loss reclassified from accumulated OCI into income)	Year Ended December 31,
	2013			2012			2011
Interest rate swaps (Interest expense and related charges)	$	(7	)	$	(8	)	$	(27	)
Interest rate swaps (Depreciation and amortization)	(2		)	(2		)	(2		)
Total	$	(9	)	$	(10	)	$	(29	)

There were no transactions designated as cash flow hedges during the years ended December 31, 2013, 2012 or 2011.

Accumulated other comprehensive income related to cash flow hedges at December 31, 2013 and 2012 totaled $36 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 $1 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at December 31, 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. We may enter into offsetting positions with the same counterparty, resulting in both assets and liabilities. Volatility in underlying commodity prices can result in significant changes in assets and liabilities 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 December 31, 2013 and 2012, 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 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 hedging positions and our interest rate swaps and have entered into master agreements that provide for netting and setoff of amounts related to these positions.

144

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:

December 31, 2013
	Amounts Presented in Balance Sheet			Offsetting Instruments (a)			Financial Collateral (Received) Pledged (b)			Net Amounts (c)
Derivative assets:
Commodity contracts	$	788		$	(389	)	$	(299	)	$	100
Interest rate swaps	—			—			—			—
Total derivative assets	788			(389		)	(299		)	100
Derivative liabilities:
Commodity contracts	(263		)	168			70			(25		)
Interest rate swaps	(1,012		)	221			—			(791		)
Total derivative liabilities	(1,275		)	389			70			(816		)
Net amounts	$	(487	)	$	—		$	(229	)	$	(716	)

December 31, 2012
	Amounts Presented in Balance Sheet			Offsetting 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 instruments with respect to commodity contracts include amounts related to interest rate swaps and vice versa. Amounts exclude trade accounts receivable and payable related to settled financial instruments.

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

(c) Includes net liability positions totaling approximately $1.1 billion (before nonperformance risk adjustment of $351 million related to interest rate swaps, which is reflected in the net amount presented at December 31, 2013) 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.

145

Derivative Volumes — The following table presents the gross notional amounts of derivative volumes at December 31, 2013 and 2012:

	December 31,
	2013		2012
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed (a)	$	30,790	$	31,060	Million US dollars
Basis	$	1,050	$	11,967	Million US dollars
Natural gas (b)	2,150		2,919		Million MMBtu
Electricity	16,482		76,767		GWh
Congestion Revenue Rights (c)	77,799		111,185		GWh
Coal	9		13		Million US tons
Fuel oil	26		47		Million gallons
Uranium	450		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 10).

(b) Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.

(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 have already been effective.

At December 31, 2013 and 2012, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully collateralized totaled $4 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 $3 million and $12 million at December 31, 2013 and 2012, respectively. All of the credit risk-related contingent features related to these derivatives were triggered upon the Bankruptcy Filing.

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 as a result of the Bankruptcy Filing. At December 31, 2013 and 2012, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.023 billion and $2.150 billion, respectively, before consideration of the amount of assets subject to the liens, and after reduction for derivative assets under netting arrangements, totaled $1.140 billion and $1.122 billion, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $6 million at December 31, 2013. No cash collateral or letters of credit were posted with these counterparties at December 31, 2012 to reduce the liquidity exposure. All of the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, were triggered upon the Bankruptcy Filing. See Note 10 for a description of other obligations that are supported by liens on certain of our assets.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $1.027 billion and $2.208 billion at December 31, 2013 and 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.

146

Concentrations of Credit Risk Related to Derivatives

TCEH has concentrations of credit risk with the counterparties to its derivative contracts. At December 31, 2013, total credit risk exposure to all counterparties related to derivative contracts totaled $889 million (including associated accounts receivable). The net exposure to those counterparties totaled $194 million at December 31, 2013 after taking into effect netting arrangements, setoff provisions and collateral. At December 31, 2013, the credit risk exposure to the banking and financial sector represented 87% of the total credit risk exposure and 47% of the net exposure, a significant amount of which is related to the natural gas hedging positions, and the largest net exposure to a single counterparty totaled $35 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.

147

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

Pension Plan

Our subsidiaries are participating employers in the EFH Retirement Plan (the Retirement Plan), a defined benefit pension plan sponsored by EFH Corp. After the amendments in 2012 discussed below, participating employees in the Retirement Plan now consist entirely of our active collective bargaining unit employees. The Retirement Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code) and is subject to the provisions of ERISA. All benefits are funded by the participating employers. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is EFH Corp.'s policy to fund the Retirement Plan assets to the extent deductible under existing federal tax regulations.

In August 2012, EFH Corp. approved certain amendments to the Retirement Plan. These actions were completed in the fourth quarter 2012, and the amendments resulted in:

• splitting off assets and liabilities under the Retirement Plan associated with active 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 (the Terminating Plan) other than collective bargaining unit employees.

EFH Corp.'s competitive operations recorded charges totaling $285 million in the fourth quarter 2012, including $92 million related to the settlement of the Terminating Plan and $193 million related to the competitive business obligations (including discontinued businesses) that were assumed under the Oncor Plan. These amounts represent the previously unrecognized actuarial losses reported in EFH Corp.'s accumulated other comprehensive income (loss). TCEH's allocated share of these charges totaled $141 million. TCEH settled $91 million of this allocation with EFH Corp. in cash in 2012 and settled the remaining $50 million with EFH Corp. in the first quarter 2013.

Settlement of the liabilities and the full funding of the EFH Corp. competitive operations portion of liabilities (including discontinued businesses) under the Oncor Plan resulted in an aggregate pension plan cash contribution by EFH Corp.'s competitive operations of $259 million in the fourth quarter 2012.

Our subsidiaries also participate in EFH Corp.'s supplemental unfunded retirement plans for certain employees whose retirement benefits cannot fully be earned under the qualified Retirement Plan, the information for which is included below.

Other Postretirement Employee Benefit (OPEB) Plan

Our subsidiaries participate with EFH Corp. and certain other affiliated subsidiaries of EFH Corp. to offer OPEB in the form of health care and life insurance to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service. In 2011, we announced a change to the OPEB plan whereby, effective January 1, 2013, Medicare-eligible retirees from the competitive business will be subject to a cap on increases in subsidies received under the plan to offset medical costs.

148

Pension and OPEB Costs Recognized as Expense

The following details net pension and OPEB costs recognized as expense. Ongoing allocations of pension and OPEB costs are reimbursed to EFH Corp. See discussion above regarding reimbursements related to the 2012 Retirement Plan amendments. The pension and OPEB amounts provided represent allocations to us of amounts related to EFH Corp.'s plans.

	Year Ended December 31,
	2013		2012		2011
Pension costs (a)	$	9	$	178	$	38
OPEB costs	3		1		14
Total benefit costs recognized as expense	$	12	$	179	$	52

____________

(a) As a result of pension plan actions discussed above, 2012 includes $141 million recorded by TCEH as a settlement charge.

For determining net periodic pension cost, EFH Corp. uses the calculated value method to determine the market-related value of the assets held in trust. EFH Corp. includes the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year. For determining net periodic OPEB cost, EFH Corp. uses the fair value method of determining the market-related value of the assets held in trust.

Regulatory Recovery of Pension and OPEB Costs

PURA provides for the recovery by Oncor, in its regulated revenue rates, of pension and OPEB costs applicable to services of Oncor's active and retired employees, as well as services of active and retired personnel engaged in TCEH's activities, related to their service prior to the deregulation and disaggregation of EFH Corp.'s electric utility business effective January 1, 2002. Accordingly, Oncor and TCEH entered into an agreement whereby Oncor assumed responsibility for applicable pension and OPEB costs related to those personnel.

Additional Multiemployer Plan Participation Disclosures

We have not been allocated any overfunded asset or underfunded liability related to our participation in EFH Corp.'s pension and OPEB plans. However, we are jointly and severally liable for all EFH Corp. pension and OPEB plan liabilities and are subject to certain risks including the following:

• Funding/assets contributed by us may be used to provide benefits to employees from other participating entities;

• We may be required to bear the unfunded obligations of another participating employer that stops making contributions, and

• If we stop participating, we may be required to pay an amount to the plan based on the underfunded status of the plan.

Our share of contributions to the Retirement Plan assets was 37% in the year ended December 31, 2012. We made no contributions to the Retirement Plan assets in the years ended December 31, 2013 and December 31, 2011. The Retirement Plan was at least 80% funded for those periods as determined under the provisions of ERISA. The Employer Identification Number of the Retirement Plan is 75-2669310 and the plan number is 002.

Assumed Discount Rate

The discount rate reflected in net pension costs was 4.30% for the year ended December 31, 2013, 5.00% for January through July 2012, 4.15% for August through September 2012, 4.20% for October through December 2012 and 5.50% for the year ended December 31, 2011. The discount rate reflected in net OPEB costs was 4.10%, 4.95% and 5.55% for the years ended December 31, 2013, 2012 and 2011, respectively. The expected rate of return on plan assets reflected in the 2013 cost amounts is 5.4% and 6.7% for the pension plan assets and OPEB assets, respectively.

149

Contribution in 2014

In February 2014, a cash contribution totaling $84 million was made to the Retirement Plan assets, of which $64 million was contributed by Oncor and $20 million was contributed by TCEH, resulting in the plan being fully funded as calculated under the provisions of ERISA. As a result of the Bankruptcy Filing, participants in the Retirement Plan who choose to retire would not be eligible for the lump sum payout option under the Retirement Plan unless the Retirement Plan is fully funded.

Thrift Plan

Our employees may participate in a qualified savings plan, the EFH Thrift Plan (Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options. Our contributions to the Thrift Plan totaled $21 million, $19 million and $18 million for the years ended December 31, 2013, 2012 and 2011, respectively.

150

16. STOCK-BASED COMPENSATION

In December 2007, EFH Corp. established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007 SIP). We bear the costs of EFH Corp.'s 2007 SIP for applicable management personnel engaged in our business activities. Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferred shares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in whole or in part by reference to, or are otherwise based on the fair market value of EFH Corp.'s shares of common stock. Given the Bankruptcy Filing, EFH Corp.'s common stock is deemed to have de minimis value as of December 31, 2013.

Our stock-based compensation expense recorded for the years ended December 31, 2013, 2012 and 2011 was as follows:

	Year Ended December 31,
Type of award	2013			2012			2011
Restricted stock units (a)	$	3		$	3		$	2
Stock options (a)	(1		)	2			4
Other share and share-based awards	—			(1		)	(1		)
Total compensation expense	$	2		$	4		$	5

_______________

(a) The expense is offset as a contribution to membership interests.

Restricted Stock Units — Restricted stock units vest as common stock of EFH Corp. upon the earlier of September 2014 or a change of control, or on a prorated basis upon certain defined events such as termination of employment. Compensation expense per unit is based on the estimated value of EFH Corp. stock at the grant date, less a marketability discount factor. To determine expense related to units issued in exchange for stock options, the unit value is further reduced by the fair value of the options exchanged. At December 31, 2013, there was approximately $2.5 million of unrecognized compensation expense related to nonvested restricted stock units expected to be recognized by us through September 2014. Restricted stock units outstanding at December 31, 2013 are all held by employees. See discussion below regarding stock options exchanged for restricted stock units in 2011.

A summary of restricted stock unit activity is presented below:

Restricted Stock Unit Activity in 2013:	Units (millions)		Weighted Average Grant Date Fair Value
Total outstanding at beginning of period	14.2		$	0.38	-	$	0.93
Granted	1.3		$	0.28	-	$	0.28
Exercised	—		$	—	-	$	—
Forfeited	(5.2	)	$	0.38	-	$	0.93
Total outstanding at end of period	10.3		$	0.28	-	$	0.93
Expected forfeitures	—		$	—	-	$	—
Expected to vest at end of period	10.3		$	0.28	-	$	0.93

Restricted Stock Unit Activity in 2012:	Units (millions)		Weighted Average Grant Date Fair Value
Total outstanding at beginning of period	13.0		$	0.81	-	$	0.93
Granted	1.4		$	0.38	-	$	0.38
Exercised	—		$	—	-	$	—
Forfeited	(0.2	)	$	0.81	-	$	0.93
Total outstanding at end of period	14.2		$	0.38	-	$	0.93
Expected forfeitures	—		$	—	-	$	—
Expected to vest at end of period	14.2		$	0.38	-	$	0.93

151

Restricted Stock Unit Activity in 2011:	Units (millions)		Weighted Average Grant Date Fair Value
Total outstanding at beginning of period	—		$	—	-	$	—
Granted	13.4		$	0.81	-	$	0.93
Exercised	—		$	—	-	$	—
Forfeited	(0.4	)	$	0.81	-	$	0.93
Total outstanding at end of period	13.0		$	0.81	-	$	0.93
Expected forfeitures	—		$	—	-	$	—
Expected to vest at end of period	13.0		$	0.81	-	$	0.93

Stock Options — No options were granted in 2013, 2012 or 2011. Stock options outstanding at December 31, 2013 are all held by current or former employees.

The exercise period for vested awards was 10 years from grant date. The terms of the options were fixed at grant date. One-half of the options initially granted in 2009 were to vest solely based upon continued employment over a specific period of time, generally five years, with the options vesting ratably on an annual basis over the period (Time-Based Options). One-half of the options initially granted were to vest based upon both continued employment and the achievement of targeted five-year EFH Corp. EBITDA levels (Performance-Based Options). Prior to vesting, expenses were recorded if the achievement of the EBITDA levels was probable, and amounts recorded were adjusted or reversed if the probability of achievement of such levels changed. Probability of vesting was evaluated at least each quarter.

In October 2009, in consideration of the then recent economic dislocation and the desire to provide incentives for retention, grantees of Performance-Based Options (excluding named executive officers and a small group of other employees) were provided an offer, which substantially all accepted, to exchange their unvested Performance-Based Options granted under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options (Cliff-Vesting Options) with a strike price of $3.50 per share (the then most recent market valuation of each share), with one-half of these options to vest in September 2012 and one-half of these options to vest in September 2014. Additionally, certain named executive officers and a small group of other employees were granted an aggregate 2.0 million Cliff-Vesting Options with a strike price of $3.50 per share, to vest in September 2014, and substantially all of these employees also accepted an offer to exchange half of their unvested Performance-Based Options with a strike price of $5.00 per share and a vesting schedule through December 2012 for new time-based stock options with a strike price of $3.50 per share, to vest in September 2014.

In December 2010, in consideration of the desire to enhance retention incentives, EFH Corp. offered employee grantees of all stock options (excluding named executive officers and a limited number of other employees) the right to exchange their vested and unvested options for restricted stock units payable in shares (at a ratio of two options for each stock unit). The exchange offer closed in February 2011, and substantially all of our eligible employees accepted the offer, which resulted in the issuance of 6.5 million restricted stock units in exchange for 11.1 million time-based options (including 3.5 million that were vested) and 1.9 million performance-based options (including 1.4 million that were vested).

In October 2011, in consideration of the desire to enhance retention incentives, EFH Corp. offered its named executive officers and a limited number of other officers (including certain of our officers) the right to exchange their vested and unvested options for restricted stock units payable in shares on terms largely consistent with offers made in December 2010 to other employee grantees of stock options. The exchange offer closed in October 2011, and all eligible employees accepted the offer, which resulted in the issuance of 4.6 million restricted stock units in exchange for 7.3 million time-based options (including 3.2 million that were vested) and 1.9 million performance-based options (including 1.8 million that were vested).

The fair value of all options granted was estimated using the Black-Scholes option pricing model. Since EFH Corp. is a private company, expected volatility was based on actual historical experience of comparable publicly-traded companies for a term corresponding to the expected life of the options. The expected life represents the period of time that options granted were expected to be outstanding and was calculated using the simplified method prescribed by the SEC Staff Accounting Bulletin No. 107. The simplified method was used since EFH Corp. did not have stock option history upon which to base the estimate of the expected life and data for similar companies was not reasonably available. The risk-free rate was based on the US Treasury security with terms equal to the expected life of the option at the grant date.

152

Compensation expense for Time-Based Options is based on the grant-date fair value and recognized over the original vesting period as employees perform services. At December 31, 2013, there was no unrecognized compensation expense related to nonvested Time-Based Options granted to employees. The exchange of time-based options for restricted stock units was considered a modification of the option award for accounting purposes.

There was no change in the number of Time-Based Options outstanding during 2013 or 2012. A summary of activity for 2011 is presented below:

Time-Based Options Activity in 2011:	Options (millions)		Weighted Average Exercise Price
Total outstanding at beginning of period	18.7		$	4.30
Granted	—		$	—
Exercised	—		$	—
Forfeited	—		$	—
Exchanged	(18.4	)	$	4.30
Total outstanding at end of period (weighted average remaining term of 6 – 10 years)	0.3		$	4.30
Exercisable at end of period (weighted average remaining term of 6 – 10 years)	—		$	—
Expected forfeitures	(0.3	)	$	4.30
Expected to vest at end of period (weighted average remaining term of 6 – 10 years)	—		$	—

	2011
Nonvested Time-Based Options Activity:	Options (millions)		Grant-Date Fair Value
Total nonvested at beginning of period	11.7		$	1.55
Granted	—		$	—
Vested	—		$	—
Forfeited	—		$	—
Exchanged	(11.7	)	$	1.55
Total nonvested at end of period	—		$	—

Compensation expense for Performance-Based Options was based on the grant-date fair value and recognized over the requisite performance and service periods for each tranche of options depending upon the achievement of financial performance.

At December 31, 2013, there was no unrecognized compensation expense related to nonvested Performance-Based Options because the options are no longer expected to vest as a result of exchanges.

153

There was no change in the number of Performance-Based Options outstanding or vested in 2013 or 2012. A summary of activity for 2011 is presented below:

Performance-Based Options Activity in 2011:	Options (millions)		Weighted Average Exercise Price
Outstanding at beginning of period	3.8		$	5.00
Granted	—		$	—
Exercised	—		$	—
Forfeited	—		$	—
Exchanged	(3.8	)	$	5.00
Total outstanding at end of period (weighted average remaining term of 6 - 8 years)	—		$	—
Exercisable at end of period (weighted average remaining term of 6 - 8 years)	—		$	—
Expected forfeitures	—		$	—
Expected to vest at end of period (weighted average remaining term of 6 - 8 years)	—		$	—

	2011
Performance-Based Nonvested Options Activity:	Options (millions)		Grant-Date Fair Value
Total nonvested at beginning of period	0.5		$	1.16	-	$	2.01
Granted	—		—		-	—
Vested	—		—		-	—
Forfeited	—		—		-	—
Exchanged	(0.5	)	$	1.16	-	$	2.01
Total nonvested at end of period	—		$	1.16	-	$	2.01

Other Share and Share-Based Awards — In 2008, EFH Corp. granted 1.75 million deferred share awards, each of which represents the right to receive one share of EFH Corp. stock, to certain of our management employees who agreed to forego share-based awards that vested at the Merger date. These deferred share awards are payable in cash or stock upon the earlier of a change of control or separation of service. No expense was recorded in 2008 related to these awards. An additional 150 thousand deferred share awards were granted to certain of our management employees in 2008, which are payable in cash or stock, all of which have since vested or have been surrendered upon termination of employment. The deferred share awards are accounted for as liability awards; therefore, the effects of changes in the estimated value of EFH Corp. shares are recognized in earnings. As a result of the decline in estimated value of EFH Corp. shares, share-based compensation expense in 2013, 2012 and 2011 was reduced by $1.0 million in each year.

154

17. RELATED-PARTY TRANSACTIONS

The following represent our significant related-party transactions. Also see Note 2 for discussion of the Restructuring Support and Lock-up Agreement entered into in anticipation of the Bankruptcy Filing.

• 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 $1.0 billion for each of the years ended December 31, 2013, 2012 and 2011. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at December 31, 2013 and 2012 reflect amounts due currently to Oncor totaling $135 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. The settlement was executed by EFIH acquiring the right to reimbursement under the agreements from Oncor and then selling these rights for the same amount to TCEH. The transaction resulted in a $2 million (after tax) increase in equity for the year ended December 31, 2012 in accordance with accounting rules for related party transactions.

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 $20 million and $39 million for the years ended December 31, 2012 and 2011, respectively.

Under an interest reimbursement agreement, TCEH had reimbursed Oncor on a monthly basis for interest expense on the transition bonds. The remaining interest to be paid through 2016 under the agreement totaled $53 million at the August 2012 settlement date. Only the monthly accrual of interest under this agreement was reported as a liability. This interest expense prior to the August 2012 settlement totaled $16 million and $32 million for the years ended December 31, 2012 and 2011, 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 December 31, 2012, the notes consisted of:

	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. In connection with the amendment to the TCEH Senior Secured Facilities in 2011, $770 million of the SG&A Note was repaid in April 2011. The TCEH Demand Notes were pledged as collateral under the TCEH Senior Secured Facilities. In February 2012, $950 million of the P&I Note was repaid by EFH Corp. The repayment was funded by a debt issuance at EFIH in February 2012. At December 31, 2012, EFIH had in escrow $680 million of the proceeds from its August 2012 debt issuance to pay a dividend to EFH Corp., which EFH Corp. had agreed to use to repay the balance of the TCEH Demand Notes. 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 $57 million, $789 million and $1.542 billion for the years ended December 31, 2013, 2012 and 2011, 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 $3 million, $42 million and $82 million for the years ended December 31, 2013, 2012 and 2011, respectively.

155

• TCEH had a demand note payable to EFH Corp. totaling $770 million for the period January to April 2011. The proceeds from the note were used to repay borrowings under the TCEH Revolving Credit Facility. The average daily balance of the note was $184 million for the year ended December 2011. The note carried interest at a rate based on the one-month LIBOR rate plus 3.50%, and interest expense related to this note totaled $7 million for the year ended December 31, 2011. In addition, EFCH has a demand note payable to EFH Corp., the proceeds from which were used to repay outstanding debt. The note totaled $103 million and $81 million at December 31, 2013 and 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 $5 million, $3 million and $2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

• Receivables from affiliates are measured at historical cost and primarily consist of notes receivable for cash loaned to EFH Corp. for debt principal and interest payments and other general corporate purposes of EFH Corp. 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 December 31, 2013 and 2012, respectively.

• 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 $241 million, $265 million and $213 million for the years ended December 31, 2013, 2012 and 2011, respectively. These amounts include allocated expense, which totaled $29 million, $38 million and $37 million for the years ended December 31, 2013, 2012 and 2011, respectively, for management fees owed and paid by EFH Corp. to the Sponsor Group. Beginning in the fourth quarter 2012, we reimburse a subsidiary of EFH Corp. for an allocated share of computer equipment purchased by the subsidiary. Amounts we paid in 2013 and 2012 related to computer equipment totaled $29 million and $38 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.

• See Note 10 for discussion of a letter of credit issued by TCEH in 2014 to a subsidiary of EFH Corp. to secure its amounts payable to the subsidiary.

• 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 $16 million, $16 million and $17 million for the years ended December 31, 2013, 2012 and 2011, respectively. 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 December 31, 2013 and 2012, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $400 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 Federal and State Income Tax Allocation 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 December 31, 2013, we had current income tax liabilities of $21 million and noncurrent income tax liabilities of $535 million payable to EFH Corp. As of December 31, 2012, we had current income tax liabilities of $31 million payable to EFH Corp. We made tax payments to EFH Corp. totaling $137 million, $84 million and $123 million for the years ended December 31, 2013, 2012 and 2011, respectively. The 2013 payment included $103 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 December 31, 2013 and 2012, TCEH had posted letters of credit in the amount of $9 million and $11 million, respectively, for the benefit of Oncor.

156

• 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.

• For the year ended December 31, 2011, fees paid to Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, related to debt issuances, exchanges, amendments and extensions totaled $26 million, described as follows: (i) Goldman acted as a joint lead arranger and joint book-runner in the April 2011 amendment and extension of the TCEH Senior Secured Facilities and received fees totaling $17 million and (ii) Goldman acted as a joint book-running manager and initial purchaser in the issuance of $1.750 billion principal amount of TCEH Senior Secured Notes as part of the April 2011 amendment and extension and received fees totaling $9 million. Affiliates of KKR and TPG served as advisers to these transactions, and each received $5 million as compensation for their services.

• 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.

• As a result of debt repurchase and exchange transactions in 2009 through 2011, EFH Corp. and EFIH held TCEH debt securities at both December 31, 2013 and 2012 as follows (principal amounts):

	Principal Amount
TCEH Senior Notes:
Held by EFH Corp.	$	284
Held by EFIH	79
TCEH Term Loan Facilities:
Held by EFH Corp.	19
Total	$	382

Interest expense on the notes totaled $38 million, $38 million and $34 million for the years ended December 31, 2013, 2012 and 2011, respectively.

See Notes 10 and 11 for guarantees and push-down of certain EFH Corp. debt and Note 15 for allocation of EFH Corp. pension and OPEB costs to us and amendments to the EFH Corp. pension plan in 2012.

157

18. SUPPLEMENTARY FINANCIAL INFORMATION

Interest Expense and Related Charges

	Year Ended December 31,
	2013			2012			2011
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	2,724		$	2,616		$	2,540
Interest related to pushed down debt	6			75			78
Interest expense on toggle notes payable in additional principal (Note 10)	—			152			166
Unrealized mark-to-market net (gain) loss on interest rate swaps	(1,053		)	(166		)	812
Amortization of interest rate swap losses at dedesignation of hedge accounting	7			8			27
Amortization of fair value debt discounts resulting from purchase accounting	10			11			17
Amortization of debt issuance, amendment and extension costs and discounts	264			182			183
Capitalized interest	(25		)	(36		)	(31		)
Total interest expense and related charges	$	1,933		$	2,842		$	3,792

Restricted Cash

At December 31, 2013, all restricted cash relates to TCEH's Letter of Credit Facility and has been classified as current in consideration of the Bankruptcy Filing. See Note 10 for discussion of letter of credit draws in 2014.

Inventories by Major Category

	December 31,
	2013		2012
Materials and supplies	$	216	$	201
Fuel stock	154		168
Natural gas in storage	29		24
Total inventories	$	399	$	393

Investments

	December 31,
	2013		2012
Nuclear plant decommissioning trust	$	791	$	654
Assets related to employee benefit plans, including employee savings programs, net of distributions	1		8
Land	37		41
Miscellaneous other	9		7
Total investments	$	838	$	710

158

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 17). The nuclear decommissioning trust fund is not a debtor under the Bankruptcy Filing. A summary of investments in the fund follows:

	December 31, 2013
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	266	$	8	$	(4	)	$	270
Equity securities (c)	255		271		(5		)	521
Total	$	521	$	279	$	(9	)	$	791

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

____________

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

(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.96% and 4.38% at December 31, 2013 and 2012, respectively, and an average maturity of 6 years at both December 31, 2013 and 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 December 31, 2013 mature as follows: $103 million in one to five years, $57 million in five to ten years and $110 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.

	Year Ended December 31,
	2013			2012			2011
Realized gains	$	2		$	1		$	1
Realized losses	$	(4	)	$	(2	)	$	(3	)
Proceeds from sales of securities	$	175		$	106		$	2,419
Investments in securities	$	(191	)	$	(122	)	$	(2,436	)

Property, Plant and Equipment

	December 31,
	2013		2012
Generation and mining	$	23,448	$	23,144
Other assets	477		452
Total	23,925		23,596
Less accumulated depreciation	6,957		5,845
Net of accumulated depreciation	16,968		17,751
Construction work in progress	348		444
Nuclear fuel (net of accumulated amortization of $1.096 billion and $941 million)	333		361
Property, plant and equipment — net	$	17,649	$	18,556

159

Depreciation expense totaled $1.231 billion, $1.228 billion and $1.330 billion for the years ended December 31, 2013, 2012 and 2011, respectively.

Assets related to capital leases included above totaled $59 million and $70 million at December 31, 2013 and 2012, respectively, net of accumulated depreciation.

The estimated remaining lives range from 19 to 56 years for the lignite/coal and nuclear fueled generation units.

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 years ended December 31, 2013 and 2012:

	Nuclear Plant Decommissioning		Mining Land Reclamation			Other		Total
Liability at January 1, 2012	$	348	$	158		$	30	$	536
Additions:
Accretion	20		34			3		57
Incremental reclamation costs (a)	—		36			—		36
Reductions:
Payments	—		(93		)	—		(93		)
Liability at December 31, 2012	$	368	$	135		$	33	$	536
Additions:
Accretion	22		30			3		55
Incremental reclamation costs (a)	—		20			—		20
Reductions:
Payments	—		(87		)	—		(87		)
Liability at December 31, 2013	390		98			36		524
Less amounts due currently	—		(84		)	—		(84		)
Noncurrent liability at December 31, 2013	$	390	$	14		$	36	$	440

____________

(a) Reflecting additional land to be reclaimed.

Other Noncurrent Liabilities and Deferred Credits

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

	December 31,
	2013		2012
Uncertain tax positions (including accrued interest) (Note 5)	$	204	$	1,250
Asset retirement and mining reclamation obligations	440		452
Unfavorable purchase and sales contracts	589		620
Nuclear decommissioning cost over-recovery (Note 17)	400		284
Other, including other postretirement employee benefits	21		37
Total other noncurrent liabilities and deferred credits	$	1,654	$	2,643

160

Unfavorable Purchase and Sales Contracts — Unfavorable purchase and sales contracts primarily represent the extent to which contracts on a net basis were unfavorable to market prices at the date of the Merger. These are contracts for which: (i) TCEH has made the "normal" purchase or sale election allowed or (ii) the contract did not meet the definition of a derivative under accounting standards related to derivative instruments and hedging transactions. Under purchase accounting, TCEH recorded the value at October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is primarily on a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of purchased power costs as appropriate. The amortization amount totaled $25 million, $27 million and $26 million for the years ended December 31, 2013, 2012 and 2011, respectively. See Note 4 for intangible assets related to favorable purchase and sales contracts.

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

Year	Amount
2014	$	24
2015	$	23
2016	$	23
2017	$	23
2018	$	23

Supplemental Cash Flow Information

	Year Ended December 31,
	2013			2012			2011
Cash payments related to:
Interest paid (a)	$	2,695		$	2,569		$	2,469
Capitalized interest	(25		)	(36		)	(31		)
Interest paid (net of capitalized interest) (a)	$	2,670		$	2,533		$	2,438
Income taxes	$	137		$	84		$	123
Noncash investing and financing activities:
Effect of Parent's payment of interest, net of tax, on pushed-down debt (b)	$	23		$	22		$	33
Principal amount of TCEH Toggle Notes issued in lieu of cash interest	$	—		$	181		$	162
Construction expenditures (c)	$	45		$	46		$	62
Contribution to membership interests (Note 16)	$	2		$	5		$	5
Reduction of debt pushed down from EFH Corp. (Note 10) (d)	$	(420	)	$	(282	)	$	(167	)
Debt exchange and extension transactions (e)	$	(340	)	$	—		$	—
Debt assumed related to acquisition of combustion turbine trust interest (Note 10)	$	(45	)	$	—		$	—

____________

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

(b) Amounts include cash interest and EFH Toggle Notes issued through the PIK election (at 50%) (see Note 10).

(c) Represents end-of-period accruals.

(d) For the year ended December 31, 2013, represents $838 million principal amount of EFH Corp. debt exchanged (at 50%). For the year ended December 31, 2012, represents $564 million principal amount of EFH Corp. debt exchanged (at 50%). See Note 10.

(e) Represents term loans issued related to credit facility extension (see Note 10).

161

19. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

At December 31, 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 10). 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 12.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, "Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered" in order to present the condensed consolidating statements of income and of cash flows of EFCH (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors for the years ended December 31, 2013, 2012 and 2011 and the condensed consolidating balance sheets at December 31, 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% Senior Notes and EFH Corp. 11.25%/12.00% Senior Toggle Notes to the Parent at December 31, 2013 and December 31, 2012, respectively, $388 million of the EFH Corp. 10% and 9.75% Senior Secured 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 December 31, 2013 and December 31, 2012 (see Note 10). 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. Amounts reported as advances to affiliates arise from recurring intercompany transactions among EFCH, TCEH and TCEH’s subsidiaries in the normal course of business. In consideration of the Bankruptcy Filing, the ultimate settlement of the advances is uncertain and is dependent on the Chapter 11 plan ultimately approved. The advances may be cancelled as part of a recapitalization of the entities.

EFCH (parent entity) received no dividends/distributions from its consolidated subsidiaries for the years ended December 31, 2013, 2012 and 2011.

162

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Consolidating Statements of Income (Loss)

Year Ended December 31, 2013

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	5,899		$	59		$	(59	)	$	5,899
Fuel, purchased power costs and delivery fees	—			—			(2,848		)	—			—			(2,848		)
Net gain (loss) from commodity hedging and trading activities	—			(56		)	2			—			—			(54		)
Operating costs	—			—			(881		)	—			—			(881		)
Depreciation and amortization	—			—			(1,333		)	—			—			(1,333		)
Selling, general and administrative expenses	—			(64		)	(648		)	(28		)	59			(681		)
Franchise and revenue-based taxes	—			—			(75		)	—			—			(75		)
Impairment of goodwill	—			(1,000		)	—			—			—			(1,000		)
Other income	—			—			9			—			—			9
Other deductions	—			—			(22		)	(140		)	—			(162		)
Interest income	1			243			795			—			(1,034		)	5
Interest expense and related charges	(19		)	(2,716		)	(2,462		)	(10		)	3,274			(1,933		)
Income (loss) before income taxes	(18		)	(3,593		)	(1,564		)	(119		)	2,240			(3,054		)
Income tax benefit (expense)	5			828			664			4			(764		)	737
Equity earnings (losses) of subsidiaries	(2,304		)	461			(23		)	—			1,866			—
Net loss	(2,317		)	(2,304		)	(923		)	(115		)	3,342			(2,317		)
Net loss attributable to noncontrolling interests	107			107			—			107			(214		)	107
Net loss attributable to EFCH	$	(2,210	)	$	(2,197	)	$	(923	)	$	(8	)	$	3,128		$	(2,210	)

163

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Consolidating Statements of Comprehensive Income (Loss)

Year Ended December 31, 2013

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations					Consolidated
Net loss	(2,317		)	(2,304		)	(923		)	(115		)	3,342					(2,317		)
Other comprehensive income	6			6			—			—			(6		)			6
Comprehensive loss	(2,311		)	(2,298		)	(923		)	(115		)	3,336					(2,311		)
Comprehensive loss attributable to noncontrolling interests	107			107			—			107			(214		)			107
Comprehensive loss attributable to EFCH	$	(2,204	)	$	(2,191	)	$	(923	)	$	(8	)	$	3,122		(2,204,000,000	)	$	(2,204	)

164

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Consolidating Statements of Income (Loss)

Year Ended December 31, 2012

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	5,636		$	31		$	(31	)	$	5,636
Fuel, purchased power costs and delivery fees	—			—			(2,816		)	—			—			(2,816		)
Net gain from commodity hedging and trading activities	—			269			120			—			—			389
Operating costs	—			—			(888		)	—			—			(888		)
Depreciation and amortization	—			—			(1,343		)	—			—			(1,343		)
Selling, general and administrative expenses	—			(11		)	(662		)	(17		)	31			(659		)
Franchise and revenue-based taxes	—			—			(80		)	—			—			(80		)
Impairment of goodwill	—			(1,200		)	—			—			—			(1,200		)
Other income	—			6			7			—			—			13
Other deductions	—			—			(185		)	(3		)	—			(188		)
Interest income	—			301			739			—			(994		)	46
Interest expense and related charges	(90		)	(3,491		)	(2,374		)	(9		)	3,122			(2,842		)
Income (loss) before income taxes	(90		)	(4,126		)	(1,846		)	2			2,128			(3,932		)
Income tax benefit (expense)	30			1,005			615			(1		)	(725		)	924
Equity earnings (losses) of subsidiaries	(2,948		)	173			(2		)	—			2,777			—
Net income (loss)	(3,008		)	(2,948		)	(1,233		)	1			4,180			(3,008		)
Other comprehensive income	7			7			—			—			(7		)	7
Comprehensive income (loss)	$	(3,001	)	$	(2,941	)	$	(1,233	)	$	1		$	4,173		$	(3,001	)

165

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Consolidating Statements of Income (Loss)

Year Ended December 31, 2011

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	7,040		$	11		$	(11	)	$	7,040
Fuel, purchased power costs and delivery fees	—			—			(3,396		)	—			—			(3,396		)
Net gain (loss) from commodity hedging and trading activities	—			1,018			(7		)	—			—			1,011
Operating costs	—			—			(924		)	—			—			(924		)
Depreciation and amortization	—			—			(1,470		)	—			—			(1,470		)
Selling, general and administrative expenses	—			—			(735		)	(4		)	11			(728		)
Franchise and revenue-based taxes	—			—			(96		)	—			—			(96		)
Other income	6			(16		)	58			—			—			48
Other deductions	—			(87		)	(437		)	—			—			(524		)
Interest income	—			381			694			—			(989		)	86
Interest expense and related charges	(94		)	(4,370		)	(2,301		)	(7		)	2,980			(3,792		)
Loss before income taxes	(88		)	(3,074		)	(1,574		)	—			1,991			(2,745		)
Income tax benefit	26			1,067			520			—			(670		)	943
Equity earnings (losses) of subsidiaries	(1,740		)	267			—			—			1,473			—
Net loss	(1,802		)	(1,740		)	(1,054		)	—			2,794			(1,802		)
Other comprehensive income	19			19			—			—			(19		)	19
Comprehensive loss	$	(1,783	)	$	(1,721	)	$	(1,054	)	$	—		$	2,775		$	(1,783	)

166

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Consolidating Statements of Cash Flows

Year Ended December 31, 2013

(millions of dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(1	)	$	(1,643	)	$	1,458		$	(85	)	$	—		$	(271	)
Cash flows – financing activities:
Notes due to affiliates	12			1,461			—			—			(1,456		)	17
Issuances of long-term debt	—			—			—			—			—			—
Repayments/repurchases of debt	(11		)	(64		)	(30		)	—			—			(105		)
Increase in other borrowings	—			—			—			—			—			—
Contributions from parent	—			—			—			136			(136		)	—
Contributions from noncontrolling interests	—			—			—			6			—			6
Other, net	—			—			—			(10		)	—			(10		)
Cash provided by (used in) financing activities	1			1,397			(30		)	50			(1,592		)	(174		)
Cash flows – investing activities:
Capital expenditures	—			—			(467		)	(5		)	—			(472		)
Nuclear fuel purchases	—			—			(116		)	—			—			(116		)
Notes/loans due from affiliates	—			—			(758		)	—			1,456			698
Investment in subsidiary	—			(146		)	10			—			136			—
Purchase of right to use certain computer-related assets from parent	—			—			(29		)	—			—			(29		)
Proceeds from sales of assets	—			—			4			—			—			4
Acquisition of combustion turbine trust interest	—			—			(40		)				—			(40		)
Changes in restricted cash	—			2			—			—			—			2
Purchases of environmental allowances and credits	—			—			(16		)	—			—			(16		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			—			175			—			—			175
Investments in nuclear decommissioning trust fund securities	—			—			(191		)	—			—			(191		)
Other, net	—			—			1			—			—			1
Cash provided by (used in) investing activities	—			(144		)	(1,427		)	(5		)	1,592			16
Net change in cash and cash equivalents	—			(390		)	1			(40		)	—			(429		)
Cash and cash equivalents – beginning balance	—			1,115			15			45			—			1,175
Cash and cash equivalents – ending balance	$	—		$	725		$	16		$	5		$	—		$	746

167

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Consolidating Statements of Cash Flows

Year Ended December 31, 2012

(millions of dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(3	)	$	(964	)	$	963		$	(236	)	$	—		$	(240	)
Cash flows – financing activities:
Notes due to affiliates	14			908			—			—			(922		)	—
Repayments/repurchases of long-term debt	(11		)	—			(29		)	—			—			(40		)
Net short-term borrowings under accounts receivable securitization program	—			—			—			(22		)	—			(22		)
Increase in other short-term borrowings	—			1,384			—			—			—			1,384
Decrease in income tax-related note payable to Oncor	—			—			(20		)	—			—			(20		)
Settlement of reimbursement agreements with Oncor	—			—			(159		)	—			—			(159		)
Contributions from parent	—			—			—			300			(300		)	—
Contributions from noncontrolling interests	—			—			—			7			—			7
Debt amendment, exchange and issuance costs	—			—			—			(5		)	—			(5		)
Sale/leaseback of equipment	—			—			15			—			—			15
Other, net	—			—			1			—			—			1
Cash provided by (used in) financing activities	3			2,292			(192		)	280			(1,222		)	1,161
Cash flows – investing activities:
Capital expenditures	—			—			(622		)	(9		)	—			(631		)
Nuclear fuel purchases	—			—			(213		)	—			—			(213		)
Notes/loans due from affiliates	—			—			4			—			922			926
Investment in subsidiary	—			(300		)	—			—			300			—
Purchase of right to use certain computer-related assets from parent	—			—			(38		)	—			—			(38		)
Proceeds from sales of assets	—			—			2			—			—			2
Changes in restricted cash	—			—			129			—			—			129
Purchases of environmental allowances and credits	—			—			(25		)	—			—			(25		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			—			106			—			—			106
Investments in nuclear decommissioning trust fund securities	—			—			(122		)	—			—			(122		)
Cash provided by (used in) investing activities	—			(300		)	(779		)	(9		)	1,222			134
Net change in cash and cash equivalents	—			1,028			(8		)	35			—			1,055
Cash and cash equivalents – beginning balance	—			87			23			10			—			120
Cash and cash equivalents – ending balance	$	—		$	1,115		$	15		$	45		$	—		$	1,175

168

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES

Consolidating Statements of Cash Flows

Year Ended December 31, 2011

(millions of dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(4	)	$	(1,572	)	$	2,827		$	(15	)	$	—		$	1,236
Cash flows – financing activities:
Notes due to affiliates	12			2,370			—			7			(2,389		)	—
Issuances of long-term debt	—			1,750			—			—			—			1,750
Repayments/repurchases of long-term debt	(8		)	(1,372		)	(28		)	—			—			(1,408		)
Net short-term borrowings under accounts receivable securitization program	—			—			—			8			—			8
Decrease in other short-term borrowings	—			(455		)	—			—			—			(455		)
Decrease in income tax-related note payable to Oncor	—			—			(39		)	—			—			(39		)
Contributions from noncontrolling interests	—			—			—			16			—			16
Debt amendment, exchange and issuance costs	—			(843		)	—			—			—			(843		)
Other, net	—			(2		)	—			—			—			(2		)
Cash provided by (used in) financing activities	4			1,448			(67		)	31			(2,389		)	(973		)
Cash flows – investing activities:
Capital expenditures	—			—			(515		)	(15		)	—			(530		)
Nuclear fuel purchases	—			—			(132		)	—			—			(132		)
Notes/loans due from affiliates	—			—			(2,043		)	—			2,389			346
Proceeds from sales of assets	—			—			49			—			—			49
Reduction of restricted cash related to TCEH letter of credit facility	—			188			—			—			—			188
Other changes in restricted cash	—			—			(96		)	—			—			(96		)
Proceeds from sales of environmental allowances and credits	—			—			10			—			—			10
Purchases of environmental allowances and credits	—			—			(17		)	—			—			(17		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			—			2,419			—			—			2,419
Investments in nuclear decommissioning trust fund securities	—			—			(2,436		)	—			—			(2,436		)
Other, net	—			—			9			—			—			9
Cash provided by (used in) investing activities	—			188			(2,752		)	(15		)	2,389			(190		)
Net change in cash and cash equivalents	—			64			8			1			—			73
Cash and cash equivalents – beginning balance	—			23			15			9			—			47
Cash and cash equivalents – ending balance	$	—		$	87		$	23		$	10		$	—		$	120

169

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES Consolidating Balance Sheets December 31, 2013 (millions of dollars)
	Parent Guarantor			Issuer		Other Guarantors		Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	725	$	16	$	5	$	—		$	746
Restricted cash	—			945		—		—		—			945
Advances to affiliates	5			—		191		—		(196		)	—
Trade accounts receivable – net	—			—		710		—		—			710
Income taxes receivable	—			—		240		—		(240		)	—
Accounts receivable from affiliates	—			8		—		—		(8		)	—
Inventories	—			—		399		—		—			399
Commodity and other derivative contractual assets	—			551		233		—		—			784
Accumulated deferred income taxes	—			117		28		—		(24		)	121
Margin deposits related to commodity positions	—			—		93		—		—			93
Other current assets	—			4		46		—		—			50
Total current assets	5			2,350		1,956		5		(468		)	3,848
Investments	(11,983		)	23,638		853		8		(11,678		)	838
Property, plant and equipment – net	—			—		17,646		3		—			17,649
Advances to affiliates	—			—		9,396		—		(9,396		)	—
Goodwill	—			3,952		—		—		—			3,952
Identifiable intangible assets – net	—			—		1,717		—		—			1,717
Commodity and other derivative contractual assets	—			—		4		—		—			4
Accumulated deferred income taxes	—			201		—		14		(215		)	—
Other noncurrent assets, principally unamortized amendment/issuance costs	—			776		787		—		(773		)	790
Total assets	$	(11,978	)	$	30,917	$	32,359	$	30	$	(22,530	)	$	28,798
LIABILITIES AND EQUITY
Current liabilities:
Borrowings under credit and other facilities	$	—		$	2,054	$	2,054	$	—	$	(2,054	)	$	2,054
Notes/advances from affiliates	—			9,592		—		—		(9,592		)	—
Debt held by affiliates	—			382		—		—		—			382
Notes, loans and other debt	96			29,612		28,750		—		(28,658		)	29,800
Trade accounts payable	—			3		378		—		—			381
Trade accounts and other payables to affiliates	—			—		169		3		(8		)	164
Notes payable to parent	103			—		—		—		—			103
Commodity and other derivative contractual liabilities	—			1,012		263		—		—			1,275

170

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES Condensed Consolidating Balance Sheets December 31, 2013 (millions of dollars)
	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors		Eliminations			Consolidated
Margin deposits related to commodity positions	—			299			3			—		—			302
Accumulated deferred income taxes	24			—			—			—		(24		)	—
Accrued income taxes payable to parent	2			259			—			—		(240		)	21
Accrued taxes other than income	—			—			120			—		—			120
Accrued interest	1			416			312			—		(310		)	419
Other current liabilities	—			—			272			—		—			272
Total current liabilities	226			43,629			32,321			3		(40,886		)	35,293
Accumulated deferred income taxes	62			—			2,748			—		772			3,582
Notes or other liabilities due affiliates	—			—			2			—		—			2
Liability to EFH Corp. under the Federal and State Income Tax Allocation Agreement	(5		)	(754		)	1,294			—		—			535
Other noncurrent liabilities and deferred credits	8			25			1,620			—		1			1,654
Total liabilities	291			42,900			37,985			3		(40,113		)	41,066
EFCH membership interests	(12,269		)	(11,983		)	(5,626		)	26		17,583			(12,269		)
Noncontrolling interests	—			—			—			1		—			1
Total membership interests	(12,269		)	(11,983		)	(5,626		)	27		17,583			(12,268		)
Total liabilities and membership interests	$	(11,978	)	$	30,917		$	32,359		$	30	$	(22,530	)	$	28,798

171

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES 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	80			—		1		—		—			81
Commodity and other derivative contractual liabilities	—			610		284		—		—			894

172

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC AND SUBSIDIARIES 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	—			—			—			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

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A.   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 December 31, 2013. 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.

There has been no change in our internal control over financial reporting during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

173

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC

MANAGEMENT'S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Energy Future Competitive Holdings Company LLC is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Energy Future Competitive Holdings Company LLC's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.

The management of Energy Future Competitive Holdings Company LLC performed an evaluation as of December 31, 2013 of the effectiveness of the company's internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission's (COSO's) Internal Control - Integrated Framework (1992). Based on the review performed, management believes that as of December 31, 2013 Energy Future Competitive Holdings Company LLC's internal control over financial reporting was effective.

The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Energy Future Competitive Holdings Company LLC has issued an attestation report on Energy Future Competitive Holdings Company LLC's internal control over financial reporting.

/s/ JOHN F. YOUNG             /s/ PAUL M. KEGLEVIC

    _____________________________________________        

John F. Young, Chair, President and Paul M. Keglevic, Executive Vice President,

Chief Executive                    Chief Financial Officer and Co-Chief Restructuring Officer

April 29, 2014

174

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of Energy Future Competitive Holdings Company LLC

Dallas, Texas

We have audited the internal control over financial reporting of Energy Future Competitive Holdings Company LLC (formerly Energy Future Competitive Holdings Company) (a subsidiary of Energy Future Holdings Corp.) and subsidiaries (“EFCH”) as of December 31, 2013 based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. EFCH's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on EFCH's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, EFCH maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements at and for the year ended December 31, 2013 of EFCH and our report dated April 29, 2014 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding substantial doubt about EFCH’s ability to continue as a going concern as EFCH is in default of certain covenants contained in its debt agreements and does not expect to be able to settle all its obligations coming due within the next twelve months and on April 29, 2014, Energy Future Holdings Corp. and the substantial majority of its subsidiaries (including Energy Future Competitive Holdings Company LLC), excluding Oncor Electric Delivery Holdings Company LLC and its subsidiaries, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code.

/s/ Deloitte & Touche LLP

Dallas, Texas

April 29, 2014

175

Item 9b. OTHER INFORMATION

Bankruptcy Filing

On April 29, 2014, EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, (the Debtors) filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). During the pendency of the Bankruptcy Filing (the Chapter 11 Cases), the Debtors will operate their businesses as "debtors-in-possession" (DIP) under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. See Note 2 to Financial Statements for a more detailed description of the Bankruptcy Filing, which information is incorporated herein by reference.

In anticipation of the Bankruptcy Filing, on April 29, 2014, the Debtors, Texas Holdings and its general partner, Texas Energy Future Capital Holdings LLC (TEF and, together with Texas Holdings, the Consenting Interest Holders) and parties including certain holders of secured and/or unsecured claims of EFH Corp., EFIH, EFCH and TCEH entered into the Restructuring Support and Lock-Up Agreement in order to effect an agreed upon restructuring of the Debtors through the Restructuring Plan. Pursuant to the Restructuring Support and Lock-Up Agreement, the Consenting Interest Holders and Consenting Creditors agreed, subject to the terms and conditions contained in the Restructuring Support and Lock-Up Agreement, to support the Debtors’ proposed financial restructuring (the Restructuring Transactions), and further agreed to limit certain transfers of any ownership (including any beneficial ownership) in the equity interests of or claims held against the Debtors, including any such interests acquired after executing the Restructuring and Lock-Up Agreement. See Items 1 and 2 Business and Properties - Filing under Chapter 11 of the United States Bankruptcy Code and - Restructuring Support and Lock-Up Agreement, which information is incorporated herein by reference.

In connection with the Bankruptcy Filing, TCEH has received a binding commitment, subject to certain customary conditions, for DIP Facilities, and intend to file a motion with the Bankruptcy Court for approval of its DIP Facilities. See Note 10 to the Financial Statements for a more detailed description of the proposed DIP Facility, which information is incorporated herein by reference.

See Exhibit 10.oo filed with the EFH Corp. Form 10-K for the TCEH Commitment Letter and Term Sheet, which is incorporated herein by reference.

176

PART III.

Item 10. MANAGERS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Managers

The names of EFCH's managers and information about them, as furnished by the managers themselves, are set forth below:

Name	Age	Served As Manager Since	Business Experience
Arcilia C. Acosta	48	2012	Arcilia C. Acosta has served as a Manager of EFCH since April 2012. Ms. Acosta is the founder, President and CEO of CARCON Industries & Construction, L.L.C. (CARCON) and its subsidiaries. She is also the founder, President and CEO of Southwestern Testing Laboratories, L.L.C. (STL). CARCON's principal business is commercial, institutional and transportation, design and build construction. STL's principal business is geotechnical engineering, construction materials testing and environmental consulting services. Ms. Acosta serves on the Board of Directors of EFH Corp., TCEH, the Dallas Citizens Council, U.T. Southwestern Board of Visitors, and The Texas Tech National Alumni Association. She also serves on the Board of Viewpoint Bank, National Association, where she serves on the Audit Committee and Risk Committee.
Paul M. Keglevic	60	2010	Paul M. Keglevic has served as a Manager of EFCH since July 2010. He was elected Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer of EFH Corp., EFIH and EFCH in October 2013, having previously served as Executive Vice President and Chief Financial Officer of EFH Corp., EFIH and EFCH from July 2008 to October 2013. Before joining EFH Corp., he was an audit partner at PricewaterhouseCoopers. Mr. Keglevic was PricewaterhouseCoopers' Utility Sector Leader from 2002 to 2008 and Clients and Sector Assurance Leader from 2007 to 2008. He serves on the boards of EFIH, TCEH and Stellus Capital Corporation.
Scott Lebovitz	38	2007	Scott Lebovitz has served as a Manager of EFCH since October 2007. He has been a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area since 2007 having joined Goldman, Sachs & Co. in 1997. Mr. Lebovitz serves on the boards of both public and private companies, including Associated Asphalt Partners, LLC, EdgeMarc Energy Holdings, LLC, EF Energy Holdings, LLC, EW Energy Holdings, LLC, EFH Corp. and TCEH. During the past five years, Mr. Lebovitz also served on the boards of Cobalt International Energy, Inc. and CVR Energy, Inc.
Michael MacDougall	43	2007	Michael MacDougall has served as a Manager of EFCH since October 2007. He is a partner of TPG. Mr. MacDougall leads the firm's global energy and natural resources investing efforts. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall is a director of both public and private companies, including Amber Holdings, Inc., Graphic Packaging Holding Company, Harvester Holdings, LLC and its two subsidiaries, Petro Harvester Oil and Gas, LLC and 2CO Energy Limited, Maverick American Natural Gas, LLC, EFH Corp., and TCEH and is a director of the general partner of Valerus Compression Services, L.P. During the past five years, he also served on the boards of Aleris International, Copano Energy, L.L.C., Kraton Performance Polymers Inc., Nexeo Solutions Holdings, LLC and Northern Tier Energy, LLC. Mr. MacDougall is also a member of the boards of directors of Islesboro Affordable Property, The Opportunity Network and the University of Texas Development Board.
Jason Ridloff	42	2013	Jason Ridloff has served as a Manager of EFCH since October 2013. He has been with KKR since 2008, where he is a Director and has been involved in several of the firm's investments. Prior to KKR, he was with Credit Suisse/Donaldson, Lufkin & Jenrette. Mr. Ridloff is also a member of the board of TCEH.

177

Hugh E. Sawyer	59	2013	Hugh E. Sawyer has served as a Manager of EFCH since October 2013. As a Managing Director for Huron Consulting Group he leads the Operational Improvement Service Line for the Business Advisory Practice where he provides strategic services to clients facing corporate turnarounds and restructurings in complex environments. He also currently serves as the interim President of Euramax Holdings, Inc. He has more than 35 years of experience leading turnarounds, bankruptcies, operational improvement and mergers and acquisitions for both public and private companies across a diverse group of industries. He has served as the President or Chief Executive Officer of eight companies, including:  Wells Fargo Armored Service Corporation, The Cunningham Group, Inc., National Linen Service, Inc., Aegis Communications Group, Inc., Allied Holdings, Inc., Legendary Holdings, Inc. and JHT Holdings, Inc. Mr. Sawyer also served as Chief Administrative Officer and Chief Restructuring Officer of Fisker Automotive, Inc. He has extensive governance experience and has served in numerous board member roles both in and out of bankruptcy, including, during the past five years, Edison Mission Energy, Inc., JHT Holdings, Inc., Hines Horticulture, Inc., Neff Equipment Rental, Inc. and Paradise Island Holdings, Inc.
Jonathan D. Smidt	41	2012	Jonathan D. Smidt has served as a Manager of EFCH since June 2012. He has been with KKR since 2000, where he is a partner and senior member of the firm's Energy and Infrastructure team and leads KKR Natural Resources, the firm's platform to acquire and operate oil and natural gas assets. Currently, he is a director of Laureate Education Inc., Samson Resources Corporation, Westbrick Energy LTD, EFH Corp. and TCEH.
John F. Young	57	2010	John F. Young has served as a Manager of EFCH since July 2010. He was elected President and Chief Executive Officer of EFH Corp. in January 2008. He also has served as Chair, President and Chief Executive of EFIH and EFCH since July 2010, having previously served as President and Chief Executive of EFIH from July 2008 to July 2010 and EFCH from April 2008 to July 2010. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008 including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon Corporation, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. Mr. Young is also a director of EFH Corp., EFIH, TCEH, USAA and Nuclear Electric Insurance Limited.

There is no family relationship between any of the above-named managers.

Manager Qualifications

In October 2007, Scott Lebovitz and Michael MacDougall were elected to EFCH’s Board of Managers. Paul M. Keglevic and John F. Young joined the board in July 2010. Arcilia C. Acosta joined the board in April 2012. Jonathan D. Smidt joined the board in June 2012. Jason Ridloff and Hugh E. Sawyer joined the board in October 2013. Messrs. Lebovitz, MacDougall, Ridloff and Smidt are collectively referred to as the "Sponsor Managers." Ms. Acosta and Messrs. Keglevic, Sawyer, and Young are collectively referred to as the "Non-Sponsor Managers."

178

When considering whether the Board's managers and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of EFCH's business and structure, the Board focused primarily on the qualifications summarized in each of the Board member's biographical information set forth above. In addition, EFCH believes that each of its managers possesses high ethical standards, acts with integrity, and exercises careful judgment. Each is committed to employing his/her skills and abilities in the long-term interests of EFCH and its stakeholders. Finally, our managers are knowledgeable and experienced in business, governmental, and civic endeavors, further qualifying them for service as members of the Board.

The Sponsor Managers possess experience in owning and managing privately held enterprises and are familiar with corporate finance and strategic business planning activities of highly-leveraged companies such as EFCH. Collectively, the Sponsor Managers possess substantial expertise in advising and managing companies in segments of the energy industry, including, among others, power generation, oil and gas, and energy infrastructure and transportation.

Before joining EFH Corp. as President and Chief Executive Officer, Mr. Young held various senior management positions at other companies in the energy industry over twenty years, including, most recently, his role as Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation.

Ms. Acosta manages the operations of a large commercial construction company in Texas and has significant experience within the local Hispanic business community, having served as the chair of the Greater Dallas Hispanic Chamber of Commerce and the Texas Association of Mexican American Chambers of Commerce. Mr. Keglevic has considerable financial and accounting knowledge and expertise. Before joining EFH Corp. as Executive Vice President and Chief Financial Officer, he held various senior management positions at PricewaterhouseCoopers, including, most recently, his roles as Utility Sector Leader and Clients and Sector Assurance Leader. Mr. Sawyer has more than 30 years experience leading turnarounds, bankruptcies, operation improvement and mergers and acquisitions for both public and private companies across a diverse group of industries. He has served as President or Chief Executive Officer of seven companies, in particular, Legendary, Inc. and Allied Holdings, Inc. through and emerging from restructuring. He has also previously served on numerous boards of directors.

179

Executive Officers

The names and information regarding EFCH's executive officers are set forth below:

Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
John F. Young	57	President and Chief Executive Officer of EFH Corp. and Chair, President and Chief Executive of EFIH and EFCH	January 2008	John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. He also has served as Chair, President and Chief Executive of EFIH and EFCH since July 2010, having previously served as President and Chief Executive of EFIH from July 2008 to July 2010 and EFCH from April 2008 to July 2010. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008, including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon Corporation, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation.
Stacey H. Doré	41	Executive Vice President, General Counsel and Co-Chief Restructuring Officer of EFH Corp., EFIH  and EFCH	October 2013	Stacey H. Doré was elected Executive Vice President, General Counsel and Co-Chief Restructuring Officer of EFH Corp. and EFCH in October 2013 and EFIH in February 2014, having previously served as Senior Vice President, General Counsel and Co-Chief Restructuring Officer of EFIH from October 2013 to February 2014, Executive Vice President and General Counsel of EFH Corp. from February 2013 to October 2013 and EFCH from April 2013 to October 2013, and Senior Vice President and General Counsel of EFH Corp. from April 2012 to February 2013, and EFIH and EFCH from April 2012 to October 2013. Ms. Doré was Vice President and General Counsel of Luminant from November 2011 to March 2012, and Vice President and Associate General Counsel of EFH Corp. from July 2008 to November 2011. Prior to joining EFH Corp., she was an attorney at Vinson & Elkins LLP, where she engaged in a business litigation practice.
Paul M. Keglevic	60	Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer of EFH Corp., EFIH and EFCH	October 2013	Paul M. Keglevic was elected Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer of EFH Corp., EFIH and EFCH in October 2013 having previously served as Executive Vice President and Chief Financial Officer of EFH Corp., EFIH and EFCH from July 2008 to October 2013. Before joining EFH Corp., he was an audit partner at PricewaterhouseCoopers. Mr. Keglevic was PricewaterhouseCoopers' Utility Sector Leader from 2002 to 2008 and Clients and Sector Assurance Leader from 2007 to 2008.

There is no family relationship between any of the above-named executive officers.

Procedures for Nominating Managers

The Limited Liability Company Agreement of EFCH requires that vacancies on the Board be filled by the remaining managers, or, if there be none, by the sole member, EFH Corp.

180

Item 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We do not have any employees and are managed by certain executive officers of our parent company, EFH Corp. The executive officers of EFH Corp. are compensated solely and directly by EFH Corp., with no amounts allocated to EFCH, and all decisions as to the compensation of its executive officers are made by the EFH Corp. Organization and Compensation Committee. The Board of Managers of EFCH does not have a compensation committee. For a full discussion of the compensation awarded to John F. Young, EFCH’s Chair, President and Chief Executive, Paul M. Keglevic, EFCH’s Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer, and Stacey H. Doré, EFCH’s Executive Vice President, General Counsel, and Co-Chief Restructuring Officer, collectively our named executive officers (“Named Executive Officers”) for the fiscal year ending December 31, 2013, please see our parent EFH Corp.’s Form 10-K on file at www.sec.gov and on EFH Corp.’s website at www.energyfutureholdings.com under the “Investor Relations” tab.

Compensation Committee Report

EFCH does not have a compensation committee. Therefore, its full Board of Managers reviewed and discussed the Compensation Discussion and Analysis with EFCH’s management. Based on such review and discussions, it recommended that the Compensation Discussion and Analysis be included in EFCH’s Annual Report on Form 10-K.

Board of Managers

Arcilia C. Acosta

Paul M. Keglevic

Scott Lebovitz

Michael MacDougall

Jason Ridloff

Hugh E. Sawyer

Jonathan D. Smidt

John F. Young

Summary Compensation Table

Pursuant to the SEC's executive compensation disclosure rules, a required table may be omitted if there has been no compensation awarded to, earned by or paid to any named executive officer that is required to be reported in that table. Therefore, we have not included a Summary Compensation Table or any other table regarding compensation paid to our Named Executive Officers.

181

Director Compensation

The table below sets forth information regarding the aggregate compensation paid to the members of the Board during the year ended December 31, 2013. Managers who are members of the EFH Corp. Board and are not members of the Sponsor Group (or their respective affiliates) receive compensation for their service as members of the EFH Corp. Board and do not receive additional compensation for service on this Board. Officers of EFCH or members of the Sponsor Group (or their respective affiliates) do not receive any fees for service as a manager.

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	Total ($)
Arcilia C. Acosta (1)	—	—	—
Paul M. Keglevic (2)	—	—	—
Scott Lebovitz (3)	—	—	—
Michael MacDougall (3)	—	—	—
Jason Ridloff (3)(4)	—	—	—
Hugh E. Sawyer (4)(5)	$50,000	—	$50,000
Jonathan D. Smidt (3)	—	—	—
John F. Young (2)	—	—	—

(1)See the Directors Compensation Table in the EFH Corp. Form 10-K for compensation paid to Ms. Acosta for her service as an EFH Corp. director.

(2)Officer of EFCH

(3)Member of the Sponsor Group (or their respective affiliates)

(4)Messrs. Ridloff and Sawyer were appointed to the EFCH Board in October 2013.

(5)Mr. Sawyer’s $50,000 compensation was paid by TCEH for his services on the boards of EFCH and TCEH.

182

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

EFCH is a wholly owned subsidiary of EFH Corp. and as a result, does not have compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance.

Beneficial Ownership of Membership Interests of Energy Future Competitive Holdings Company LLC

We are a wholly owned subsidiary of EFH Corp. As such, EFH Corp. is the beneficial owner of 100% of our membership interests and neither our directors nor the executive officers of our parent, EFH Corp., beneficially owned any membership interests of EFCH as of April 1, 2014. The following table lists the percentage of limited liability company interests of EFCH beneficially owned by each manager and certain executive officers of EFCH and the holders of more than 5% of EFCH’s limited liability company interests as of April 1, 2014.

The amounts and percentages of membership interests of EFCH beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power or investment power, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest.

Name	Percentage Ownership
Energy Future Holdings Corp.	100.00%
Arcilia C. Acosta	0.00%
Stacey H. Doré	0.00%
Paul M. Keglevic	0.00%
Scott Lebovitz	0.00%
Michael MacDougall	0.00%
Jason Ridloff	0.00%
Hugh E. Sawyer	0.00%
Jonathan D. Smidt	0.00%
John F. Young	0.00%
All owners, managers and current executive officers as a group (10 persons)	100.00%

183

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE

Policies and Procedures Relating to Related Party Transactions

The Board of Directors (the “Board”) of EFH Corp., EFCH’s parent company, has adopted a related person transactions policy. Under this policy, a related person transaction shall be consummated or shall continue only if:

1. the Audit Committee of the Board approves or ratifies such transaction in accordance with the policy and determines that the transaction is on terms comparable to those that could be obtained in arm's length dealings with an unrelated third party;

2. the transaction is approved by the disinterested members of the Board or the Executive Committee of the Board; or

3. the transaction involves compensation approved by the Organization and Compensation Committee of the Board.

For purposes of this policy, the term "related person" includes EFH Corp.'s directors, executive officers, 5% shareholders and their immediate family members. "Immediate family members" means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.

A "related person transaction" is a transaction between EFH Corp. or its subsidiaries and a related person, other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:

1. any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act;

2. any transaction with another company at which a related person's only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company's ownership interests;

3. any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person's only relationship is as an employee (other than an executive officer) or director;

4. transactions where the related person's interest arises solely from the ownership of EFH Corp.'s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis;

5. transactions involving a related party where the rates or charges involved are determined by competitive bids;

6. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority;

7. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service;

8. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable);

9. transactions involving less than $100,000 when aggregated with all similar transactions;

10. transactions between EFH Corp. and its subsidiaries or between subsidiaries of EFH Corp.;

11. transactions not required to be disclosed under Item 404 of Regulation S-K under the Securities Act of 1933, and

12. open market purchases of EFH Corp.'s or its subsidiaries' debt or equity securities and interest payments on such debt.

The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify related person transactions. Accordingly, at least annually, management reviews related person transactions to be entered into, or previously entered into, by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the Board approves, ratifies or disapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such related person transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed as soon as reasonably practicable by the Audit Committee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. makes all reasonable efforts to cancel or otherwise terminate the affected transactions.

The related person transactions described below were approved prior to the Board's adoption of this policy, but were approved by either the Board or its Executive Committee. Transactions described below under "Related Person Transactions - Transactions with Sponsor Affiliates" are not related person transactions under the EFH Corp. policy because they are not with a director, executive officer, 5% shareholder or any of their immediate family members, but are described in the interest of greater disclosure.

184

Related Person Transactions

Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership; Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC

The Sponsor Group and certain investors who agreed to co-invest with the Sponsor Group or through a vehicle jointly controlled by the Sponsor Group to provide equity financing for the Merger (Co-Investors) entered into (i) a limited partnership agreement (LP Agreement) in respect of EFCH’s indirect parent company, Texas Holdings and (ii) the LLC Agreement in respect of Texas Holdings' sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or execute consents with respect to any shares of EFH Corp.'s common stock owned by Texas Holdings. The LLC Agreement and LP Agreement contain agreements among the parties with respect to the election of EFH Corp.'s directors, restrictions on the issuance or transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions (including the right to approve various corporate actions).

The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managers of Texas Capital are also members of EFH Corp.'s Board. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. and affiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, has the right to designate three managers of Texas Capital. These rights are subject to maintenance of certain investment levels in Texas Holdings.

Registration Rights Agreement

The Sponsor Group and the Co-Investors entered into a registration rights agreement with EFCH’s parent company, EFH Corp., upon completion of the Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.'s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the Sponsor Group and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.'s common stock under the Securities Act that it may undertake. Ms. Acosta, who is a member of the EFCH Board of Managers; Messrs. Young and Keglevic, each of whom are executive officers of EFCH and EFH Corp.; and Messrs. Burke and McFarland, each of whom are executive officers of EFH Corp. are parties to this agreement.

Management Services Agreement

In October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFCH’s parent company, EFH Corp. (Management Agreement), pursuant to which affiliates of the Sponsor Group provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount increases 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Under terms of the Management Agreement, EFH Corp. paid $29 million, inclusive of expenses, to the Sponsor Group during 2013. Beginning with the quarterly management fee due December 31, 2013, the Sponsor Group, while reserving the right to receive the fees, directed EFH Corp. to suspend payments of the management fees for an indefinite period.

Indemnification Agreement

Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFCH’s parent company, EFH Corp., entered into an indemnification agreement (Indemnification Agreement), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, Company Group), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.

185

Sale Participation Agreement

Ms. Acosta, who is a member of the EFCH and EFH Corp. Boards, Mr. Young who is a member of the Boards and an executive officer of EFCH and EFH Corp. and Mr. Keglevic, who is a member of the Board of EFCH and an executive officer of EFCH and EFH Corp., and Ms. Doré who is an executive officer of EFCH and EFH Corp., entered into sale participation agreements with EFCH’s parent company, EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.'s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.'s common stock held by the Sponsor Group. Mr. Sawyer does not own shares of EFH Corp.’s common stock and has not entered into a sale participation agreement with EFH Corp.

Management Stockholders' Agreement

Subject to a management stockholders' agreement, certain EFCH managers, its executive officers, and other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The management stockholders' agreement creates certain rights and restrictions on these shares of common stock, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances. Mr. Sawyer does not own shares of EFH Corp.’s common stock and has not entered into the management stockholders’ agreement.

Director Stockholders' Agreement

Certain members of the EFCH Board have entered into a stockholders' agreement with EFCH’s parent company, EFH Corp. These stockholders' agreements create certain rights and restrictions on the equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances. Mr. Sawyer does not own shares of EFH Corp.’s common stock and has not entered into a stockholders agreement with EFH Corp.

Transactions with Sponsor Affiliates

TCEH has entered into the TCEH Senior Secured Facilities, and Oncor has entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners.

Affiliates of GS Capital Partners have from time to time engaged in commercial and investment banking and financial advisory transactions with EFCH in the normal course of business.

From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.

EFH Corp. has entered into, and may continue to enter into, arrangements with members of the Sponsor Group and/or their respective affiliates to use their products and services in the ordinary course of their business, which often result in revenues to members of the Sponsor Group or their respective affiliates in excess of $120,000 annually.

Manager Independence

Though not formally considered by the Board because EFH Corp.'s common stock is not currently registered under the Securities Exchange Act of 1934, as amended, with the SEC or traded on any national securities exchange, based upon the listing standards for issuers of equity securities on the New York Stock Exchange (NYSE), the national securities exchange upon which EFH Corp.'s common stock was traded prior to the Merger, only Ms. Acosta and Mr. Sawyer would be considered independent. Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other managers would be considered independent under the NYSE listing standards for issuers of equity securities. See "Certain Relationships and Related Party Transactions" and Item 11, "Executive Compensation - Manager Compensation."

186

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Deloitte & Touche LLP has been the independent auditor for EFH Corp. and for its Predecessor (TXU Corp.) since its organization in 1996.

The Audit Committee of the EFH Corp. Board of Directors has adopted a policy relating to the engagement of EFH Corp.'s independent auditor that applies to EFH Corp. and its consolidated subsidiaries, including EFCH. The policy provides that in addition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessary to complete SEC filings, EFH Corp.'s independent auditor may be engaged to provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditor must be authorized by the Audit Committee in accordance with preapproval procedures which are defined in the policy. The preapproval procedures require:

1. The annual review and preapproval by the Audit Committee of all anticipated audit and non-audit services; and

2. The quarterly preapproval by the Audit Committee of services, if any, not previously approved and the review of the status of previously approved services.

The Audit Committee may also approve certain ongoing non-audit services not previously approved in the limited circumstances provided for in the SEC rules. All services performed by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates ("Deloitte & Touche") for EFH Corp. in 2013 were preapproved by the Audit Committee.

The policy defines those non-audit services which EFH Corp.'s independent auditor may also be engaged to provide as follows:

1. Audit related services, including:

a. due diligence accounting consultations and audits related to mergers, acquisitions and divestitures;

b. employee benefit plan audits;

c. accounting and financial reporting standards consultation;

d. internal control reviews, and

e. attest services, including agreed-upon procedures reports that are not required by statute or regulation.

2. Tax related services, including:

a. tax compliance;

b. general tax consultation and planning;

c. tax advice related to mergers, acquisitions, and divestitures, and

d. communications with and request for rulings from tax authorities.

3. Other services, including:

a. process improvement, review and assurance;

b. litigation and rate case assistance;

c. forensic and investigative services, and

d. training services.

The policy prohibits EFCH from engaging its independent auditor to provide:

1. Bookkeeping or other services related to EFCH's accounting records or financial statements;

2. Financial information systems design and implementation services;

3. Appraisal or valuation services, fairness opinions, or contribution-in-kind reports;

4. Actuarial services;

5. Internal audit outsourcing services;

6. Management or human resource functions;

7. Broker-dealer, investment advisor, or investment banking services;

8. Legal and expert services unrelated to the audit, and

9. Any other service that the Public Company Accounting Oversight Board determines, by regulation, to be impermissible.

In addition, the policy prohibits EFCH's independent auditor from providing tax or financial planning advice to any officer of EFCH.

Compliance with the Audit Committee's policy relating to the engagement of Deloitte & Touche is monitored on behalf of the Audit Committee by EFH Corp.'s chief accounting officer. Reports describing the services provided by Deloitte & Touche and fees for such services are provided to the Audit Committee no less often than quarterly.

187

For the years ended December 31, 2013 and 2012, fees billed (in US dollars) to EFCH by Deloitte & Touche were as follows:

	2013		2012
Audit Fees. Fees for services necessary to perform the annual audit, review SEC filings, fulfill statutory and other service requirements, provide comfort letters and consents	$	5,634,000	$	5,642,000
Audit-Related Fees. Fees for services including due diligence related to mergers, acquisitions and divestitures, accounting consultations and audits in connection with acquisitions, internal control reviews, attest services that are not required by statute or regulation, and consultation concerning financial accounting and reporting standards	203,000		506,000
Tax Fees. Fees for tax compliance, tax planning, and tax advice related to mergers and acquisitions, divestitures, and communications with and requests for rulings from taxing authorities	—		—
All Other Fees. Fees for services including process improvement reviews, forensic accounting reviews, litigation assistance, and training services	8,000		256,000
Total	$	5,845,000	$	6,404,000

188

PART IV.

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(b) Exhibits:

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
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)	—	Certificate of Formation of Energy Future Competitive Holdings Company LLC
(4)	Instruments Defining the Rights of Security Holders, Including Indentures**
	Energy Future Holdings Corp. (Merger-related push down debt)
4(a)	1-12833 Form 8-K (filed October 31, 2007)	4.1	—	Indenture, dated October 31, 2007, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon, as trustee, relating to Senior Notes due 2017 and Senior Toggle Notes due 2017.
4(b)	1-12833 Form 10-K (2009) (filed February 19, 2010)	4(f)	—	Supplemental Indenture, dated July 8, 2008, to the Indenture, dated October 31, 2007.
4(c)	1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009)	4(a)	—	Second Supplemental Indenture, dated August 3, 2009, to the Indenture, dated October 31, 2007.
4(d)	1-12833 Form 8-K (filed July 30, 2010)	99.1	—	Third Supplemental Indenture, dated July 29, 2010, to the Indenture, dated October 31, 2007.
4(e)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	4(b)	—	Fourth Supplemental Indenture, dated October 18, 2011, to the Indenture dated October 31, 2007.
4(f)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(a)	—	Fifth Supplemental Indenture, dated April 15, 2013, to the Indenture, dated October 31, 2007, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to Senior Notes due 2017 and Senior Toggle Notes due 2017.
4(g)	1-12833 Form 8-K (filed November 20, 2009)	4.1	—	Indenture, dated November 16, 2009, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.

189

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
4(h)	1-12833 Form 8-K (filed January 30, 2013)	4.1	—	Supplemental Indenture, dated January 25, 2013, to the Indenture, dated November 16, 2009, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.
4(i)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(c)	—	Second Supplemental Indenture, dated April 15, 2013, to the Indenture, dated November 16, 2009, among Energy Future Holdings Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.
4(j)	333-171253 Form S-4 (filed January 24, 2011)	4(k)	—	Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(k)	333-165860 Form S-3 (filed April 1, 2010)	4(j)	—	First Supplemental Indenture, dated March 16, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(l)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(a)	—	Second Supplemental Indenture, dated April 13, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(m)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(b)	—	Third Supplemental Indenture, dated April 14, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(n)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(c)	—	Fourth Supplemental Indenture, dated May 21, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(o)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(d)	—	Fifth Supplemental Indenture, dated July 2, 2010, to the Indenture, January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(p)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(e)	—	Sixth Supplemental Indenture, dated July 6, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(q)	333-171253 Form S-4 (filed January 24, 2011)	4(r)	—	Seventh Supplemental Indenture, dated July 7, 2010, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10,000% Senior Secured Notes due 2020.

190

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
4(r)	1-12833 Form 8-K (filed January 30, 2013)	4.2	—	Eighth Supplemental Indenture, dated January 25, 2013, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(s)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(e)	—	Ninth Supplemental Indenture, dated April 15, 2013, to the Indenture, dated January 12, 2010, among Energy Future Holdings Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
Texas Competitive Electric Holdings Company LLC
4(t)	333-108876 Form 8-K (filed October 31, 2007)	4.2	—	Indenture, dated October 31, 2007, among Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., the guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.25% Senior Notes due 2015.
4(u)	1-12833 Form 8-K (filed December 12, 2007)	4.1	—	First Supplemental Indenture, dated December 6, 2007, to the Indenture, dated October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016.
4(v)	1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009)	4(b)	—	Second Supplemental Indenture, dated August 3, 2009, to the Indenture, dated October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016.
4(w)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(i)	—	Third Supplemental Indenture, dated January 11, 2013, to the Indenture dated October 31, 2007, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.25% Senior Notes due 2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016.
4(x)	1-12833 (Form 10-K) (filed April 30, 2014)	4(ccc)	—	Fourth Supplemental Indenture, dated February 24, 2014, to the Indenture dated October 31, 2007, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.25% Senior Notes due 2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016.
4(y)	1-12833 Form 8-K (filed October 8, 2010)	4.1	—	Indenture, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., the guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 15% Senior Secured Second Lien Notes due 2021.
4(z)	1-12833 Form 8-K (filed October 26, 2010)	4.1	—	First Supplemental Indenture, dated October 20, 2010, to the Indenture, dated October 6, 2010.

191

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
4(aa)	1-12833 Form 8-K (filed November 17, 2010)	4.1	—	Second Supplemental Indenture, dated November 15, 2010, to the Indenture, dated October 6, 2010.
4(bb)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	4(a)	—	Third Supplemental Indenture, dated as of September 26, 2011, to the Indenture, dated October 6, 2010.
4(cc)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(k)	—	Fourth Supplemental Indenture, dated January 11, 2013, to the Indenture dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 15% Senior Secured Second Lien Notes due 2021 and 15% Senior Secured Second Lien Notes due 2021, Series B.
4(dd)	1-12833 (Form 10-K) (filed April 30, 2014)	4(iii)	—	Fifth Supplemental Indenture, dated February 24, 2014, to the Indenture dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 15% Senior Secured Second Lien Notes due 2021 and 15% Senior Secured Second Lien Notes due 2021, Series B.
4(ee)	1-12833 Form 8-K (filed October 8, 2010)	4.3	—	Second Lien Pledge Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as collateral agent for the benefit of the second lien secured parties.
4(ff)	1-12833 Form 8-K (filed October 8, 2010)	4.4	—	Second Lien Security Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein and The Bank Of New York Mellon Trust Company, N.A., as collateral agent and as the initial second priority representative for the benefit of the second lien secured parties.
4(gg)	1-12833 Form 8-K (filed October 8, 2010)	4.5	—	Second Lien Intercreditor Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein, Citibank, N.A., as collateral agent for the senior collateral agent and the administrative agent, The Bank of New York Mellon Trust Company, N.A., as the initial second priority representative.
4(hh)	1-12833 Form 10-K (filed February 18, 2011)	4(aaa)	—	Form of Second Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of The Bank of New York Mellon Trust Company, N.A., as Collateral Agent and Initial Second Priority Representative for the benefit of the Second Lien Secured Parties, as Beneficiary.
4(ii)	1-12833 Form 8-K (filed April 20, 2011)	4.1	—	Indenture, dated as of April 19, 2011, among Texas Competitive Electric Holdings Company LLC, TCEH Finance Inc., the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.5% Senior Secured Notes due 2020.

192

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
4(jj)	1-12833 Form 10-Q (Quarter ended March 31, 2013) (filed May 2, 2013)	4(j)	—	Supplemental Indenture, dated January 11, 2013, to the Indenture dated April 19, 2011, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.5% Senior Secured Notes due 2020.
4(kk)	1-12833 (Form 10-K) (filed April 30, 2014)	4(ppp)	—	Second Supplemental Indenture, dated February 24, 2014, to the Indenture dated April 19, 2011, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11.5% Senior Secured Notes due 2020.
4(ll)	1-12833 Form 8-K (filed April 20, 2011)	4.2	—	Form of Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Collateral Agent for the benefit of the Holders of the 11.5% Senior Secured Notes due 2020, as Beneficiary.
4(mm)	1-12833 Form 8-K (filed April 20, 2011)	4.3	—	Form of Deed of Trust and Security Agreement to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Collateral Agent for the benefit of the Holders of the 11.5% Senior Secured Notes due 2020, as Beneficiary.
4(nn)	1-12833 Form 8-K (filed April 20, 2011)	4.4	—	Form of Subordination and Priority Agreement, among Citibank, N.A., as beneficiary under the First Lien Credit Deed of Trust, The Bank of New York Mellon Trust Company, N.A., as beneficiary under the Second Lien Indenture Deed of Trust, Citibank, N.A., as beneficiary under the First Lien Indenture Deed of Trust, Texas Competitive Electric Holdings Company LLC and the subsidiary guarantors party thereto.
(10)	Material Contracts
	Management Contracts; Compensatory Plans, Contracts and Arrangements
10(a)	1-34543 (Form 10-K) (filed April 30, 2014)		—	Energy Future Competitive Holdings Company LLC Non-Employee Manager Compensation Arrangements.
	Credit Agreements and Related Agreements
10(b)	1-12833 (Form 10-K) (filed April 30, 2014)	10(oo)	—	Commitment Letter, dated April 28, 2014, by and among Texas Competitive Electric Holdings Company LLC, certain of its subsidiaries and the Commitment Parties thereto.

193

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
10(c)	333-171253 Post-Effective Amendment #1 to Form S-4 (filed February 7, 2011)	10(rr)	—	$24,500,000,000 Credit Agreement, dated October 10, 2007, among Energy Future Competitive Holdings Company; Texas Competitive Electric Holdings Company LLC, as the borrower; the several lenders from time to time parties thereto; Citibank, N.A., as administrative agent, collateral agent, swingline lender, revolving letter of credit issuer and deposit letter of credit issuer; Goldman Sachs Credit Partners L.P., as posting agent, posting syndication agent and posting documentation agent; JPMorgan Chase Bank, N.A., as syndication agent and revolving letter of credit issuer; Citigroup Global Markets Inc., J.P. Morgan Securities Inc., Goldman Sachs Credit Partners L.P., Lehman Brothers Inc., Morgan Stanley Senior Funding, Inc. and Credit Suisse Securities (USA) LLC, as joint lead arrangers and bookrunners; Goldman Sachs Credit Partners L.P., as posting lead arranger and bookrunner; Credit Suisse, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc., Morgan Stanley Senior Funding, Inc., as co-documentation agents; and J. Aron & Company, as posting calculation agent.
10(d)	1-12833 Form 8-K (filed August 10, 2009)	10.1	—	Amendment No. 1, dated August 7, 2009, to the $24,500,000,000 Credit Agreement.
10(e)	1-12833 Form 8-K (filed April 20, 2011)	10.1	—	Amendment No. 2, dated April 7, 2011, to the $24,500,000,000 Credit Agreement
10(f)	1-12833 Form 8-K (filed January 7, 2013)	10.1	—	December 2012 Extension Amendment, dated January 4, 2013, to the $24,500,000,000 Credit Agreement.
10(g)	1-12833 Form 8-K (filed January 7, 2013)	10.2	—	Incremental Amendment No. 1, dated January 4, 2013, to the $24,500,000,000 Credit Agreement.
10(h)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ss)	—	Guarantee, dated October 10, 2007, by the guarantors party thereto in favor of Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007.
10(i)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(vv)	—	Form of Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as beneficiary.
10(j)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	10(b)	—	Form of First Amendment to Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Beneficiary.
10(k)	1-12833 Form 8-K (filed August 10, 2009)	10.2	—	Amended and Restated Collateral Agency and Intercreditor Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company; Texas Competitive Electric Holdings Company LLC; the subsidiary guarantors party thereto; Citibank, N.A., as administrative agent and collateral agent; Credit Suisse Energy LLC, J. Aron & Company, Morgan Stanley Capital Group Inc., Citigroup Energy Inc., each as a secured hedge counterparty; and any other person that becomes a secured party pursuant thereto.

194

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
10(l)	1-12833 Form 8-K (filed August 10, 2009)	10.3	—	Amended and Restated Security Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Texas Competitive Electric Holdings Company LLC, the subsidiary grantors party thereto, and Citibank, N.A., as collateral agent for the benefit of the first lien secured parties, including the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007.
10(m)	1-12833 Form 8-K (filed August 10, 2009)	10.4	—	Amended and Restated Pledge Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary pledgors party thereto, and Citibank, N.A., as collateral agent for the benefit first lien secured parties, including the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007.
	Other Material Contracts
10(n)	1-12833 Form 10-K (2003) (filed March 15, 2004)	10(qq)	—	Lease Agreement, dated February 14, 2002, between State Street Bank and Trust Company of Connecticut, National Association, an owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as lessor and EFH Properties Company, as Lessee (Energy Plaza Property).
10(o)	1-12833 Form 10-Q (Quarter ended June 30, 2007) (filed August 9, 2007)	10.1	—	First Amendment, dated June 1, 2007, to Lease Agreement, dated February 14, 2002.
10(p)	1-12833 Form 10-K (2006) (filed March 2, 2007)	10(iii)	—	Amended and Restated Transaction Confirmation by Generation Development Company LLC, dated February 2007 (subsequently assigned to Texas Competitive Electric Holdings Company LLC on October 10, 2007) (confidential treatment has been requested for portions of this exhibit).
10(q)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(sss)	—	ISDA Master Agreement, dated October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(r)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ttt)	—	Schedule to the ISDA Master Agreement, dated October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(s)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(uuu)	—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(t)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(vvv)	—	ISDA Master Agreement, dated October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International.
10(u)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(www)	—	Schedule to the ISDA Master Agreement, dated October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International.
10(v)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(xxx)	—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Credit Suisse International.

195

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
10(w)	1-12833 Form 8-K (filed December 6, 2012)	10.1	—	First Lien Trade Receivables Financing Agreement, dated as of November 30, 2012, among TXU Energy Receivables Company LLC, as Borrower, TXU Energy Retail Company LLC, as Collection Agent, certain Investors, CitiBank, N.A., as the Initial Bank, and CitiBank, N.A., as Administrative Agent and as a Group Managing Agent.
10(x)	1-12833 Form 8-K (filed December 6, 2012)	10.2	—	Trade Receivables Sale Agreement, dated as of November 30, 2012, among TXU Energy Retail Company LLC, as Originator, as Collection Agent and as Originator Agent and TXU Energy Receivables Company LLC, as Buyer, and Energy Future Holdings Corp.
10(y)	1-12833 Form 10-Q (Quarter ended September 30, 2012) (filed October 30, 2012)	10(b)	—	Federal and State Income Tax Allocation Agreement, effective January 1, 2010, by and among members of the Energy Future Holdings Corp. consolidated group.
(12)	Statement Regarding Computation of Ratios
12(a)			—	Computation of Ratio of Earnings to Fixed Charges
(21)	Subsidiaries of the Registrant
21(a)			—	Subsidiaries of Energy Future Competitive Holdings Company LLC
(31)	Rule 13a - 14(a)/15d - 14(a) Certifications
31(a)			—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
32(a)			—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(95)	Mine Safety Disclosures
95(a)			—	Mine Safety Disclosures
(99)	Additional Exhibits
99(a)	33-55408 Post-Effective Amendment No. 1 to Form S-3 (filed July, 1993)	99(b)	—	Amended Agreement dated January 30, 1990, between Energy Future Competitive Holdings Company and Tex-La Electric Cooperative of Texas, Inc.

196

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December31, 2013
99(b)		—	Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2013 and 2012.
99(c)		—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 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
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

** Certain instruments defining the rights of holders of debt of the Company’s subsidiaries included in the financial statements filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10 percent of the total assets of the Company and its subsidiaries on a consolidated basis. The Company hereby agrees, upon request of the SEC, to furnish a copy of any such omitted instrument.

197

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Energy Future Competitive Holdings Company LLC has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY LLC
Date:	April 29, 2014	By	/S/    JOHN F. YOUNG
			(John F. Young, Chair, President and Chief Executive)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Energy Future Competitive Holdings Company LLC and in the capacities and on the date indicated.

Signature	Title	Date
/s/ JOHN F. YOUNG	Principal Executive Officer and Manager	April 29, 2014
(John F. Young, Chair, President and Chief Executive)
/s/ PAUL M. KEGLEVIC	Principal Financial Officer and Manager	April 29, 2014
(Paul M. Keglevic, Executive Vice President, Chief Financial Officer and Co-Chief Restructuring Officer)
/s/ STANLEY J. SZLAUDERBACH	Principal Accounting Officer	April 29, 2014
(Stanley J. Szlauderbach, Senior Vice President and Controller)
/s/ ARCILIA C. ACOSTA	Manager	April 29, 2014
(Arcilia C. Acosta)
/s/ SCOTT LEBOVITZ	Manager	April 29, 2014
(Scott Lebovitz)
/s/ MICHAEL MACDOUGALL	Manager	April 29, 2014
(Michael MacDougall)
/s/ JASON RIDLOFF	Manager	April 29, 2014
(Jason Ridloff)
/s/ HUGH E. SAWYER	Manager	April 29, 2014
(Hugh E. Sawyer)
/s/ JONATHAN D. SMIDT	Manager	April 29, 2014
(Jonathan D. Smidt)

198