Filed Pursuant to Rule 424(b)(3)

Registration Nos. 333-157057, 333-157057-01 to 333-157057-44

TEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY LLC

TCEH FINANCE, INC.

SUPPLEMENT NO. 10 TO

MARKET MAKING PROSPECTUS DATED APRIL 4, 2012

THE DATE OF THIS SUPPLEMENT IS FEBRUARY 20, 2013

On February 19, 2013, the registrant parent guarantor, Energy Future Competitive Holdings Company, filed the attached Current Report on Form 10-K with the Securities and Exchange Commission.

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, 2012

— 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

(Exact name of registrant as specified in its charter)

Texas	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

Common Stock Outstanding as of February 19, 2013: 2,062,768 Class A shares, without par value and 39,192,594 Class B shares, without par value.

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

________________________________________ 

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

Glossary		ii
PART I
Items 1. and 2.	BUSINESS AND PROPERTIES	1
Item 1A.	RISK FACTORS	15
Item 1B.	UNRESOLVED STAFF COMMENTS	33
Item 3.	LEGAL PROCEEDINGS	33
Item 4.	MINE SAFETY DISCLOSURES	34
PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	35
Item 6.	SELECTED FINANCIAL DATA	36
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	38
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	73
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	80
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	159
Item 9A.	CONTROLS AND PROCEDURES	159
Item 9B.	OTHER INFORMATION	162
PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	162
Item 11.	EXECUTIVE COMPENSATION	162
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	162
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	162
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	163
PART IV
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	164

Energy Future Competitive Holdings Company's (EFCH) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the Energy Future Holdings Corp. (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 EFH Corp., EFCH (or "we," "our," "us" or "the company"), TCEH, TXU Energy or Luminant when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the relevant parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

i

GLOSSARY

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

2011 Form 10-K	EFCH's Annual Report on Form 10-K for the year ended December 31, 2011
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.
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.
CSAPR	the final Cross-State Air Pollution Rule issued by the EPA in July 2011 and vacated by the US Court of Appeals for the District of Columbia Circuit in August 2012 (see Note 3 to Financial Statements)
DOE	US Department of Energy
EBITDA	earnings (net income) before interest expense, income taxes, depreciation and amortization
EFCH	Energy Future Competitive Holdings Company, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context
EFH Corp.	Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context, whose major subsidiaries include TCEH and Oncor
EFH Corp. Senior Notes	Refers, collectively, to EFH Corp.'s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.'s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).
EFH Corp. Senior Secured Notes	Refers, collectively, to EFH Corp.'s 9.75% Senior Secured Notes due October 15, 2019 (EFH Corp. 9.75% Notes) and EFH Corp.'s 10.000% Senior Secured Notes due January 15, 2020 (EFH Corp. 10% Notes).
EFIH	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

ii

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
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GWh	gigawatt-hours
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 finalized by the EPA in December 2011 and published in February 2012
Merger	The transaction referred to in the Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which was completed on October 10, 2007.
MMBtu	million British thermal units
Moody's	Moody's Investors Services, Inc. (a credit rating agency)
MW	megawatts
MWh	megawatt-hours
NERC	North American Electric Reliability Corporation
NOx	nitrogen oxides
NRC	US Nuclear Regulatory Commission
NYMEX	the New York Mercantile Exchange, a physical commodity futures exchange
Oncor	Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities
Oncor Holdings	Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context

iii

OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
purchase accounting	The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or "purchase price" of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
REP	retail electric provider
RRC	Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
S&P	Standard & Poor's Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)
SEC	US Securities and Exchange Commission
SG&A	selling, general and administrative
SO2	sulfur dioxide
Sponsor Group	Refers, collectively, to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GS Capital Partners, an affiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Holdings.
TCEH	Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities, and whose major subsidiaries include Luminant and TXU Energy
TCEH Demand Notes	Refers to certain loans from TCEH to EFH Corp. in the form of demand notes to finance EFH Corp. debt principal and interest payments and, until April 2011, other general corporate purposes of EFH Corp., that are guaranteed on a senior unsecured basis by EFCH and EFIH.
TCEH Finance	TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities
TCEH Senior Notes	Refers, collectively, to TCEH's and TCEH Finance's 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015, Series B (collectively, TCEH 10.25% Notes) and TCEH's and TCEH Finance's 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).
TCEH Senior Secured Facilities	Refers, collectively, to the TCEH Term Loan Facilities, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and, until it expired on December 31, 2012, TCEH Commodity Collateral Posting Facility. See Note 8 to Financial Statements for details of these facilities.
TCEH Senior Secured Notes	TCEH's and TCEH Finance's 11.5% Senior Secured Notes due October 1, 2020
TCEH Senior Secured Second Lien Notes	Refers, collectively, to TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes due April 1, 2021 and TCEH's and TCEH Finance's 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.
TCEQ	Texas Commission on Environmental Quality
Texas Holdings	Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group, that owns substantially all of the common stock of EFH Corp.
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

iv

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

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. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently, there are no reportable business segments.

TCEH owns or leases 15,427 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. 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 1.75 million retail electricity customers in Texas.

At December 31, 2012, we had approximately 5,200 full-time employees, including approximately 2,050 employees under collective bargaining agreements.

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 (ISO) of the interconnected transmission grid for those systems. ERCOT's membership consists of approximately 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. The ERCOT ISO 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. The ERCOT ISO also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

Significant changes in the operations of the wholesale electricity market resulted from the change from a zonal to a nodal market implemented by ERCOT in December 2010. The nodal market design resulted in a substantial increase in the number of settlement price points for participants and established a new "day-ahead market," operated by ERCOT, in which participants can enter into forward sales and purchases of electricity. The nodal market also established hub trading prices, which represent the average of node prices within geographic regions, at which participants can hedge and trade power through bilateral transactions and established congestion revenue rights, which are financial instruments auctioned by ERCOT that allow participants to hedge price differences between settlement points. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance – Wholesale Market Design – Nodal Market" for additional discussion of the ERCOT nodal market.

1

The following data is derived from information published by ERCOT:

Installed generation capacity in the ERCOT market for the year 2012 totaled approximately 84,500 MW, including approximately 2,900 MW mothballed (idled) capacity and more than 10,000 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 2012, ERCOT's hourly demand peaked at 66,548 MW, which was less than the record peak demand of 68,305 MW in 2011. 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. In November 2010, ERCOT changed its minimum reserve margin planning criterion to 13.75% from 12.5%. In December 2012, ERCOT projected the reserve margin for the summer peak load period to be 13.2% in 2013, 10.9% in 2014, and 10.5% in 2015. Reserve margin represents the percentage by which system generation capacity exceeds anticipated peak load. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Key Risks and Challenges – Declining Reserve Margins and Weather Extremes."

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.

Natural gas-fueled generation is the predominant electricity capacity resource (approximately 59%) in the ERCOT market and accounted for approximately 45% of the electricity produced in the ERCOT market in 2012. 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 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.

2

• 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 encourage 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 a portion of our exposure to variability of wholesale electricity prices through a natural gas price hedging program. Under this program, TCEH has entered into market transactions involving natural gas-related financial instruments, and at December 31, 2012, has effectively sold forward approximately 360 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 42,000 GWh at an assumed 8.5 market heat rate) for the period January 1, 2013 through December 31, 2014 at weighted average annual hedge prices ranging from $6.89 per MMBtu to $7.80 per MMBtu. Taking together forward wholesale and retail electricity sales with the natural gas positions in the hedging program, we have effectively hedged an estimated 96% and 41% of the price exposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2013 and 2014, respectively (assuming an 8.5 market heat rate). For additional discussion of the natural gas price hedging program, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," specifically sections entitled "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Price Hedging Program and Other Hedging Activities," "Key Risks and Challenges – Natural Gas Price and Market Heat Rate Exposure" and "Financial Condition – Liquidity and Capital Resources – Liquidity Effects of Commodity Hedging and Trading Activities."

• Strengthen our balance sheet through a liability management program. In 2009, EFH Corp. implemented a liability management program focused on improving EFH Corp.'s and its competitive subsidiaries' (including our) balance sheets. Accordingly, we and EFH Corp. expect to opportunistically look for ways to reduce the amount and extend the maturity of our outstanding debt. Since inception, the program has resulted in our capture of $700 million of debt discount, the extension of $2.05 billion of commitments under the TCEH Revolving Credit Facility to 2016 and the extension of $19.6 billion of debt maturities to 2017-2021. For EFH Corp., the program has resulted in the capture of $2.5 billion of debt discount (including the acquisition of $363 million principal amount of TCEH Senior Notes and $19 million principal amount of borrowings under the TCEH Senior Secured Facilities that are held as an investment by EFH Corp. or EFIH) and the extension of approximately $25.7 billion of debt maturities to 2017-2021. Activities to date have included debt exchanges, issuances and repurchases as well as amendments to, and extensions under, the Credit Agreement governing the TCEH Senior Secured Facilities. As a result of these and other activities, we expect TCEH will have sufficient liquidity to meets its obligations until October 2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures. TCEH's ability to satisfy this obligation is dependent upon the implementation of one or more of the actions described below. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance – Liability Management Program" and Notes 1and 8 to Financial Statements for additional discussion of these transactions.

3

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

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

• 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: the environment, 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 management activities, including commodity price risk management and 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 operational accountability and market identity, the operations of TCEH have been grouped into 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 generation fleet consists of 14 plants in Texas 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 (a)
Nuclear	2,300	1	2
Lignite/coal (b)	8,017	5	12
Natural gas (c)	5,110	8	26
Total	15,427	14	40

___________

(a) Leased units consist of six natural gas-fueled combustion turbine units totaling 390 MW of capacity. All other units are owned.

(b) Includes 1,130 MW representing two units at our Monticello facility for which operations have been suspended until summer 2013 due to low wholesale power prices in ERCOT and other market conditions.

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

4

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. 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 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 25 days. The Comanche Peak facility operated at a capacity factor of 98.5%, 95.7% and 100% in 2012, 2011 and 2010, respectively.

Luminant has contracts in place for all of its uranium and nuclear fuel conversion, enrichment and fabrication services for 2013. For the period of 2014 through 2019, Luminant has contracts in place for the acquisition of approximately 71% of its uranium requirements and 87% of its nuclear fuel conversion services requirements. In addition, Luminant has contracts in place for all of its nuclear fuel enrichment services through 2014, 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 is developing 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 15 to Financial Statements for discussion of the decommissioning trust fund.)

Nuclear insurance provisions are discussed in Note 9 to Financial Statements.

Nuclear Generation Development— In 2008, a subsidiary of TCEH filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at its 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 (CPNPC), to further the development of the two new nuclear generation units using MHI's US–Advanced Pressurized Water Reactor technology. The TCEH subsidiary owns an 88% interest in CPNPC, and a MHI subsidiary owns a 12% interest.

Based on the NRC's license application review schedule, we expect the NRC will complete its review in summer 2014 and that a license could be issued by year-end 2014. We have filed a loan guarantee application with the DOE for financing the proposed units prior to commencement of construction.

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 (last two years include three recently constructed units discussed immediately below). Luminant's lignite/coal-fueled generation fleet operated at a capacity factor of 70.0% in 2012, 83.5% in 2011 and 82.2% in 2010. This performance reflects increased economic backdown of the units as described above and the suspension of operations until summer 2013 of two units at Monticello as reflected in the footnotes to the generating capacity table above.

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In 2009 and 2010, Luminant completed the construction of three lignite-fueled generation units with a total capacity of 2,180 MW. The three units consist of one unit at a leased site that is adjacent to an existing lignite-fueled generation unit (Sandow) and two units at an owned site (Oak Grove). The Sandow unit and the first Oak Grove unit achieved substantial completion (as defined in the engineering, procurement and construction (EPC) agreements for the respective units) in the fourth quarter 2009. The second Oak Grove unit achieved substantial completion (as defined in the EPC agreement for the unit) in the second quarter 2010.

Approximately 71% of the fuel used at Luminant's lignite/coal-fueled generation units in 2012 was supplied from surface-minable lignite reserves dedicated to the Big Brown, Monticello, Martin Lake and Oak Grove plant sites, which are located adjacent to the reserves. Luminant owns or has under lease an estimated 735 million tons of lignite reserves dedicated to these sites, and has an undivided interest in 200 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 2012, Luminant recovered approximately 31 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 2012, Luminant reclaimed more than 3,700 acres of land. In addition, Luminant planted 1.7 million trees in 2012, the majority of which were part of the reclamation effort.

Luminant meets its fuel requirements at Big Brown, Monticello and Martin Lake 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 through 2013 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 or leases a fleet of 26 natural gas-fueled generation units totaling 5,110 MW of capacity, which includes 3,455 MW of currently available capacity and 1,655 MW of capacity representing four units 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.

In December 2012, Luminant filed a permit application with the TCEQ to build two natural gas combustion turbines totaling 420 MW at its existing DeCordova generation facility. While we believe the current market conditions do not provide adequate economic returns for the development or construction of new generation, we believe additional generation resources will be needed to support continued electricity demand growth 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 actions by the PUCT and ERCOT to encourage development of new generation resources.

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

Our electricity price exposure is managed across the complementary generation, wholesale and retail operations on a 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 more than 900 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.

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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. Part of these hedging activities are achieved through a natural gas price hedging program, 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.

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 through a centrally managed real-time operational staff that optimizes operational activities across the fleet and interfaces with various wholesale market channels. In addition, the wholesale operations manage the fuel procurement requirements for Luminant's fossil fuel 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 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 1.75 million residential and commercial retail electricity customers in Texas. Approximately 67% of our reported retail revenues in 2012 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. 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 State of Texas. Based upon data published by the PUCT, at June 30, 2012, approximately 59% of residential customers and 68% 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 $100 million in energy efficiency initiatives over a five-year period through 2012 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. Luminant also holds a power marketer license from the FERC and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and any other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. In addition, Luminant is subject to the jurisdiction of the RRC's oversight of its lignite mining and reclamation operations.

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Luminant is also subject to the jurisdiction of the PUCT's oversight of the competitive ERCOT wholesale electricity market. PUCT rules establish robust oversight, certain limits and a framework for wholesale power pricing and market behavior. Luminant is also subject to the requirements of the ERCOT Protocols, including Nodal Protocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC, including NERC critical infrastructure protection (CIP) standards. Luminant is also subject to the expanding 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 Protocols, including Nodal Protocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC, including NERC CIP standards.

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 57 million short tons of CO₂in 2012. 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, several bills have been introduced in the US Congress or advocated by the Obama Administration that were intended to address climate change using different approaches, including most prominently 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 supported the development of an integrated package of recommendations for the federal government to address the global climate change issue through federal legislation at various times in the past few years. When GHG legislation involving a cap-and-trade program was being debated, we expressed a view that any such program should be mandatory, economy-wide, consistent with expected technology development timelines and designed in a way to limit potential harm to the economy or grid reliability and protect consumers. We have held that any mechanism for allocation of GHG emission allowances should include substantial allocation of allowances to offset the cost of GHG regulation, including the cost to electricity consumers. In addition, we have participated in a voluntary electric utility industry sector climate change initiative in partnership with the DOE through the Edison Electric Institute (EEI). Our strategies are generally consistent with the "EEI Global Climate Change Points of Agreement" published by the EEI in January 2009 and "The Carbon Principles" announced in February 2008 by three major financial institutions. 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 who represent the following interests, among others: 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.

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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 ultimately 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 power 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. 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. Parties will have approximately 90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeal will be filed.

In March 2012, the EPA released a proposal for a performance standard for greenhouse gas emissions from new electric generation units (EGUs). The proposed standard, which is currently limited to new sources, is based on the carbon dioxide emission rate from a natural gas-fueled combined cycle EGU. None of our existing generation units would be considered a new source under the proposed rule. While we do not believe the proposed rule, as released, affects our existing generation units, we continue to monitor the rule.

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 Inc. appealed the court's ruling and the appeal has been fully briefed and submitted to the appellate court for decision on the briefs. We are not a party to this litigation, but we are continuing to monitor the case.

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 United States and China are not participants in the Kyoto Protocol extension. 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 included in wholesale electricity prices.

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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 — Over the last five years, we invested $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, an online tool showing residential customers how and when they use electricity; 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 PowerSmart^SM and TXU Energy Free Nights^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 more than 900 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;

• Evaluating the Development of a New Nuclear Generation Facility — As discussed under "Nuclear Generation Development" above, we have filed applications with the NRC for combined construction and operating licenses for two new 1,700 MW nuclear power plants (3,400 MW total) of new nuclear generation capacity (the lowest GHG emission source of baseload generation currently available) at our Comanche Peak nuclear generation facility. In addition, we have (i) filed a loan guarantee application with the DOE for financing of the proposed units and (ii) formed a joint venture with Mitsubishi Heavy Industries Ltd. (MHI) to further develop the units using MHI's US-Advanced Pressurized Water Reactor technology, 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 1.7 million trees in 2012. 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 180,000 trees since its inception in 2002.

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Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions

Cross-State Air Pollution Rule— In 2005, the EPA issued a final rule (the Clean Air Interstate Rule or CAIR) intended to implement the provisions of the Clean Air Act Section 110(a)(2)(D)(i)(I) (CAA Section 110) requiring states to reduce emissions of sulfur dioxide (SO₂) and nitrogen 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 US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) invalidated CAIR, but allowed the rule to continue until the EPA issued a final replacement rule.

In July 2011, the EPA issued the final replacement rule for CAIR (as finally issued, the Cross-State Air Pollution Rule (CSAPR)). The CSAPR included Texas in its annual SO₂ and NO_X emissions reduction programs, as well as the seasonal NO_X emissions reduction program. These programs would have required significant additional reductions of SO₂ and NO_X emissions from fossil-fueled generation units in covered states (including Texas) and instituted a limited "cap and trade" system as an additional compliance tool to achieve reductions the EPA contends are necessary to implement CAA Section 110. In September 2011, we filed a petition for review in the D.C. Circuit Court challenging the CSAPR as it applies to Texas.

In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including emissions budgets for the State of Texas. In June 2012, the EPA finalized the proposed rule (Second Revised Rule). In total, the emissions budgets established by the Final Revisions along with the Second Revised Rule would require our fossil-fueled generation units to reduce (i) their annual SO₂ and NO_X emissions by approximately 120,600 tons (56 percent) and 9,000 tons (22 percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NO_X emissions by approximately 3,300 tons (18 percent) compared to 2010 levels. We could comply with these emissions limits either through physical reductions or through the purchase of emissions credits from third parties, but the volume of SO₂ credits that may be purchased from sources outside of Texas would be subject to limitations starting in 2014. 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 these proceedings have agreed that the case should be held in abeyance pending the conclusion of the CSAPR rehearing proceeding discussed immediately below. Since the CSAPR rehearing proceeding has concluded, the parties will confer regarding how the case should proceed, if at all.

In August 2012, a three judge panel of 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 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. The EPA and the other parties to the proceedings have approximately 90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeals will be filed.

Given the uncertainty regarding the CSAPR's (including the Final Revisions, the Second Revised Rule or any replacement rules) requirements and the timing of its implementation, we are unable to predict its effects on our results of operations, liquidity or financial condition. See Note 3 to Financial Statements for discussion of accounting actions taken as a result of the CSAPR.

Mercury and Air Toxics Standard — In December 2011, the EPA finalized a rule called the Mercury and Air Toxics Standard (MATS). MATS 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 MATS 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 MATS in the D.C. Circuit Court. Certain states and industry participants have also filed petitions for review in the D.C. Circuit Court. We cannot predict the timing or outcome of these petitions. In November 2012, the EPA proposed revised standards for new coal-fired generation units and other minor changes to MATS, including changes to the work practice standards affecting all units. We cannot predict the outcome of the final rule.

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Regional Haze — SO₂ and NO_X reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions are required either on a unit-by-unit basis or by state participation in an EPA-approved regional trading program such as the CAIR. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze to the EPA, which we believe would not have a material impact on our generation facilities. In December 2011, the EPA proposed a limited disapproval of the SIP due to its reliance on the CAIR and a Federal Implementation Plan for Texas providing that the inclusion in the CSAPR programs meets the regional haze requirements for SO₂ and NO_X reductions. In June 2012, the EPA finalized the limited disapproval of the Texas regional haze SIP, but did not finalize a Federal Implementation Plan for Texas. We cannot predict whether or when the EPA will finalize a Federal Implementation Plan for Texas regarding regional haze or its impact on our results of operations, liquidity or financial condition. In August 2012, we filed a petition for review in the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the EPA's limited disapproval of the Texas regional haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court's decision in the CSAPR litigation. In September 2012, we filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of Federal Implementation Plans regarding regional haze. The parties to these cases have mutually agreed that the cases should be held in abeyance pending completion of the CSAPR rehearing proceeding described above. Because the CSAPR rehearing proceeding is completed, we anticipate that these cases will no longer be held in abeyance. We cannot predict when or how the Fifth Circuit Court or the D.C. Circuit Court will rule on these petitions.

State Implementation Plan — 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. Since the EPA has not designated nonattainment areas and projects that 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 NO_X National Ambient Air Quality standard 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 had indicated that it will not make final area designations until June 2013. 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 State Implementation Plan 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. 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 Clean Air Act. In March 2012, the Fifth Circuit Court vacated the EPA's disapproval of the Texas standard permit for pollution control projects and remanded the matter to the EPA for reconsideration. We cannot predict the timing or outcome of the EPA's reconsideration.

In November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacing that exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generation facility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicability of the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and received the generation facility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issued is consistent with the 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 original opinion and issued a new 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 new expanded opinion. Other parties to the proceedings also filed a petition with the Fifth Circuit Court asking the panel to reconsider its decision. We cannot predict the timing or outcome of this matter.

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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.

In 2010, we obtained a renewed and amended permit for discharge of waste water from our Oak Grove generation facility. Opponents to that permit renewal have initiated a challenge in Travis County, Texas District Court. We and the State of Texas defended the issuance of the permit. In October 2012, the Texas District Court ruled in favor of the issuance of the permit. Opponents have filed an appeal directed at the State of Texas. If the permit is ultimately rejected by the courts, and we are required to undertake additional permitting activity and install additional temperature-control equipment, we could incur material capital expenditures, which could result in material effects on our results of operations, liquidity and financial condition. (See Note 9 to Financial Statements.)

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 must adopt the final regulations by June 2013. 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. Compliance with this rule would be required beginning eight years following promulgation. We cannot predict the substance of the final regulations or the impact they may have on our results of operations, liquidity or financial condition.

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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 expect to ship 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.)

The nuclear industry is developing 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. 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 $270 million in 2012 and are expected to total approximately $100 million in 2013 for environmental control equipment to comply with regulatory requirements. Based on analysis and testing of options to comply with the MATS rule, as well as estimates related to other EPA regulations, including expenditures previously incurred related to the CSAPR, between 2011 and the end of the decade we estimate that we will incur more than $1 billion in capital expenditures for environmental control equipment, though the ultimate total will depend on the evolution of pending or future regulatory requirements. Based on regulations currently in effect, we estimate that we will incur approximately $500 million of environmental capital expenditures between 2013 and 2017, including amounts required to maintain installed environmental control equipment. 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.

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Item 1A. RISK FACTORS

Some 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, include:

Risks Related to Substantial Indebtedness

Our substantial leverage could adversely affect our ability to fund our operations, limit our ability to react to changes in the economy or our industry (including changes to environmental regulations), limit our ability to raise additional capital and adversely impact our ability to meet obligations under our various debt agreements.

We are highly leveraged. At December 31, 2012, our consolidated principal amount of debt (short-term borrowings and long-term debt, including amounts due currently and amounts held by affiliates) totaled $32.7 billion (see Note 8 to Financial Statements). Our substantial indebtedness has, or could have, important consequences, including:

• making it more difficult for us to make payments on our debt, including our maturities of $3.8 billion of the TCEH Term Loan Facilities in October 2014;

• requiring a substantial portion of our cash flow to be dedicated to the payment of principal and interest on our debt, thereby limiting our liquidity and reducing our ability to use our cash flow to fund operations, capital expenditures, future business opportunities and execution of our growth strategy;

• increasing our vulnerability to adverse economic, industry or competitive conditions or developments, including changes to environmental regulations;

• limiting our ability to make strategic acquisitions or causing us to make non-strategic divestitures;

• limiting our ability to develop new (or maintain our current) generation facilities;

• limiting our ability to obtain additional financing for working capital (including collateral posting), capital expenditures, project development, debt service requirements, acquisitions and general corporate or other purposes, or to refinance existing debt, and increasing the costs of any such financing or refinancing;

• limiting our ability to find counterparties for our hedging and asset management activities in the wholesale commodity market, and

• limiting our ability to adjust to changing market and industry conditions (including changes to environmental regulations) and placing us at a disadvantage compared to competitors who are less leveraged and who, therefore, may be able to operate at a lower overall cost (including debt service) and take advantage of opportunities that we cannot.

We may not be able to repay or refinance our debt as or before it becomes due, or obtain additional financing, particularly if wholesale electricity prices in ERCOT do not significantly increase and/or if environmental regulations are adopted that result in significant capital requirements, and the costs of any refinancing may be significant.

We may not be able to repay or refinance our debt as or before it becomes due, including our maturities of $3.8 billion of the TCEH Term Loan Facilities in October 2014, or we may only be able to refinance such amounts on terms that will increase our cost of borrowing or on terms that may be more onerous. Our ability to successfully implement any future refinancing of our debt will depend on, among other things, our financial condition and operating performance, which is subject to prevailing economic and competitive conditions, and to certain financial, business and other factors beyond our control, including, without limitation, wholesale electricity prices in ERCOT (which are primarily driven by the price of natural gas and ERCOT market heat rates), environmental regulations and general conditions in the credit markets. Refinancing may also be difficult because of general economic conditions, including the slow economic recovery, the possibility of rising interest rates and uncertainty with respect to US fiscal policy. Because our credit ratings are significantly below investment grade, we may be more heavily exposed to these refinancing risks than other borrowers. In addition, the timing of additional financings may require us to pursue such financings at inopportune times, and we may be able to incur new financing only at significant cost.

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At December 31, 2012, a substantial amount of our long-term debt matures in the next few years, including approximately $80 million, $3.9 billion and $3.7 billion principal amount of debt maturing in 2013, 2014 and 2015, respectively. A substantial amount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities. In April 2011 and January 2013, we secured extensions of a significant portion of the commitments and loans under the TCEH Senior Secured Facilities. However, even after taking these extensions into account, we still have $3.8 billion principal amount of loans under the TCEH Term Loan Facilities that were not extended and will mature in October 2014. In addition, notwithstanding the extensions, the commitments and loans could mature earlier as described in the next paragraph. Moreover, while we were able to extend a significant portion of the commitments and loans under the TCEH Senior Secured Facilities, the extensions were only for three years and the cost of these extensions was significant. As a result, we have a substantial principal amount of debt that matures in 2016 (approximately $1.9 billion) and 2017 (approximately $16.1 billion, including $947 million under the TCEH Letter of Credit Facility that is held in restricted cash).

The extended commitments and loans under the TCEH Senior Secured Facilities include a "springing maturity" provision pursuant to which in the event that (a) more than $500 million aggregate principal amount of the TCEH 10.25% Notes or more than $150 million aggregate principal amount of the TCEH Toggle Notes (in each case, other than notes held by EFH Corp. or its controlled affiliates at March 31, 2011 to the extent held at the determination date), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (b) TCEH's consolidated total debt to consolidated EBITDA ratio (as defined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at such applicable determination date, then the maturity date of the extended commitments and loans will automatically change to 90 days prior to the maturity date of the applicable notes. As a result of this "springing maturity" provision, we may lose the benefit of the extension of the commitments and loans under the TCEH Senior Secured Facilities if we are unable to refinance the requisite portion of the TCEH 10.25% Notes and TCEH Toggle Notes (collectively, the TCEH Senior Notes) by the applicable deadline. The TCEH 10.25% Notes mature on November 1, 2015, and the TCEH Toggle Notes mature on November 1, 2016. If holders of the TCEH Senior Notes are unwilling to extend the maturities of their notes, then, to avoid the "springing maturity" of the extended commitments and loans, we may be required to repay a substantial portion of the TCEH Senior Notes at prices above market or at par. There is no assurance that we will be able to make such payments, whether through cash on hand or additional financings. At December 31, 2012, $3.125 billion and $1.749 billion aggregate principal amount of the TCEH 10.25% Notes and the TCEH Toggle Notes, respectively, were outstanding, excluding amounts held by affiliates.

Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas. Accordingly, the contribution to earnings and the value of our nuclear and lignite/coal-fueled generation assets 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 $4.03 per MMBtu at December 31, 2012 for calendar year 2014). In recent years, natural gas supply has outpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic downturn. 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. These market conditions are challenging to our liquidity and the long-term profitability of our businesses. Specifically, low natural gas prices and their effect in ERCOT on wholesale electricity prices could have a material impact on TCEH's overall profitability for periods in which TCEH does not have significant hedge positions. At December 31, 2012, we have hedged approximately 96% and 41% of our wholesale natural gas price exposure related to expected generation output for 2013 and 2014, respectively, based on currently governing CAIR regulation, and we do not have any significant amounts of hedges in place for periods after 2014. Consequently, a continuation, or further decline, of current forward natural gas prices could result in further declines in the values of TCEH's nuclear and lignite/coal-fueled generation assets and limit or hinder TCEH's ability to hedge its wholesale electricity revenues at sufficient price levels to support its significant interest payments and debt maturities, which could adversely impact its ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt.

Aspects of our current financial condition may also be challenging to our efforts to obtain additional financing (or refinance or extend our existing financing) in the future. For example, our liabilities exceed our assets as shown on our balance sheet prepared in accordance with US GAAP at December 31, 2012. Our reported assets include $4.952 billion of goodwill at December 31, 2012. In 2012 and 2010, we recorded $1.2 billion and $4.1 billion, respectively, noncash goodwill impairment charges reflecting the estimated effect of lower wholesale electricity prices on the enterprise value of TCEH, driven by the sustained decline in forward natural gas prices, as indicated by our cash flow projections and declines in market values of securities of comparable companies. The enterprise value of TCEH will continue to depend on, among other things, wholesale electricity prices in the ERCOT market. Further, third party analyses of TCEH's business performed in connection with goodwill impairment testing in accordance with US GAAP, which have indicated that the principal amount of TCEH's outstanding debt exceeds its enterprise value, may make it more difficult for us to successfully access the capital markets to obtain liquidity and/or implement any refinancing or extensions of our debt or obtain additional financing. Our ability to obtain future financing is also limited by the value of our unencumbered assets. Substantially all of our assets are encumbered (in most cases by both first and second liens), and we have no material assets that could be used as additional collateral in future financing transactions.

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EFCH's (or any applicable subsidiary's) credit ratings and any actual or perceived changes in their creditworthiness could negatively affect EFCH's (or the subsidiary's) ability to access capital and could require EFCH or its subsidiaries to post collateral or repay certain indebtedness.

EFCH's (or any applicable subsidiary's) credit ratings could be lowered, suspended or withdrawn entirely at any time by the rating agencies, if in each rating agency's judgment, circumstances warrant. Downgrades in EFCH's or any of its subsidiaries' long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and could trigger liquidity demands pursuant to the terms of new commodity contracts, leases or other agreements. Future transactions by EFCH or any of its subsidiaries, including the issuance of additional debt or the consummation of additional transactions under our liability management program, could result in temporary or permanent downgrades of EFCH's or its subsidiaries' credit ratings.

Most of EFCH's large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions. Because of EFCH's (and its applicable subsidiary's) existing credit ratings, the cost to operate its businesses is likely higher because counterparties in some instances could require the posting of collateral in the form of cash or cash-related instruments. If our creditworthiness or perceptions of our creditworthiness deteriorate further, counterparties could decline to do business with EFCH (or its applicable subsidiary).

Despite our current high debt level, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial debt.

We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on the incurrence of additional debt, these restrictions are subject to a number of significant qualifications and exceptions. Under certain circumstances, the amount of debt, including secured debt, that could be incurred in the future in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we and holders of our existing debt now face could intensify.

EFCH and its subsidiaries may pursue various transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements.

Future transactions and initiatives that we may pursue may have significant effects on our business, capital structure, ownership, liquidity, credit ratings and/or results of operations. For example, in addition to the exchanges, repurchases and extensions of our debt beginning in 2009 reflected in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance – Liability Management Program," EFH Corp., EFCH and TCEH continue to consider and evaluate possible transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and may from time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives. These transactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debt of EFCH and TCEH into equity of EFH Corp., EFCH, TCEH and/or any of their subsidiaries, and could have significant effects on the business, capital structure, ownership, liquidity, credit ratings and/or results of operations of EFCH and TCEH, including significantly deleveraging TCEH. There can be no guarantee that any of such transactions or initiatives would be successful or produce the desired outcome, which could ultimately affect us or our debtholders in a material manner, including debtholders not recovering the full principal amount of TCEH debt.

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Our debt agreements contain covenants and restrictions that limit flexibility in operating our businesses, and a breach of any of these covenants or restrictions could result in an event of default under one or more of our debt agreements at different entities within our capital structure, including as a result of cross acceleration or default provisions.

Our debt agreements contain various covenants and other restrictions that, among other things, limit flexibility in operating our businesses. A breach of any of these covenants or restrictions could result in a significant portion of our debt becoming due and payable. Our ability to comply with certain of our covenants and restrictions can be affected by events beyond our control. These covenants and other restrictions limit our ability to, among other things:

• incur additional debt or issue preferred shares;

• pay dividends on, repurchase or make distributions in respect of capital stock or make other restricted payments;

• make investments;

• sell or transfer assets;

• create liens on assets to secure debt;

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

• enter into transactions with affiliates;

• designate subsidiaries as unrestricted subsidiaries, and

• repay, repurchase or modify certain subordinated and other material debt.

There are a number of important limitations and exceptions to these covenants and other restrictions. See Note 8 to Financial Statements for a description of these covenants and other restrictions.

Under the TCEH Senior Secured Facilities, TCEH is required to maintain a consolidated secured debt to consolidated EBITDA ratio below specified levels. TCEH's ability to maintain the consolidated secured debt to consolidated EBITDA ratio below such levels can be affected by events beyond its control, including, without limitation, wholesale electricity prices (which are primarily derived by the price of natural gas and ERCOT market heat rates) and environmental regulations, and there can be no assurance that TCEH will comply with this ratio. At December 31, 2012, TCEH's consolidated secured debt to consolidated EBITDA ratio was 5.9 to 1.00, which compares to the maximum consolidated secured debt to consolidated EBITDA ratio of 8.00 to 1.00 currently permitted under the TCEH Senior Secured Facilities. The secured debt portion of the ratio excludes (a) up to $1.5 billion of debt ($906 million excluded at December 31, 2012) secured by a first-priority lien (including the TCEH Senior Secured Notes) if the proceeds of such debt are used to repay term loans or deposit letter of credit loans under the TCEH Senior Secured Facilities and (b) debt secured by a lien ranking junior to the TCEH Senior Secured Facilities, including the TCEH Senior Secured Second Lien Notes. In addition, under the TCEH Senior Secured Facilities, TCEH is required to timely deliver to the lenders audited annual financial statements that are not qualified as to the status of TCEH and its consolidated subsidiaries as a going concern. See Note 1 to Financial Statements for discussion of TCEH's liquidity and the $3.8 billion of TCEH Term Loan Facilities that matures in October 2014.

A breach of any of these covenants or restrictions could result in an event of default under one or more of our debt agreements at different entities within our capital structure, including as a result of cross acceleration or default provisions. Upon the occurrence of an event of default under one of these debt agreements, our lenders or noteholders could elect to declare all amounts outstanding under that debt agreement to be immediately due and payable and/or terminate all commitments to extend further credit. Such actions by those lenders or noteholders could cause cross defaults or accelerations under our other debt. If we were unable to repay those amounts, the lenders or noteholders could proceed against any collateral granted to them to secure such debt. In the case of a default under debt that is guaranteed, holders of such debt could also seek to enforce the guarantees. If lenders or noteholders accelerate the repayment of all borrowings, we would likely not have sufficient assets and funds to repay those borrowings. Such occurrence could result in EFCH and/or its applicable subsidiary going into bankruptcy, liquidation or insolvency.

In addition, EFH Corp. and Oncor have implemented a number of "ring-fencing" measures to enhance the credit quality of Oncor Holdings and its subsidiaries, including Oncor. Those measures include Oncor not guaranteeing or pledging any of its assets to secure the debt of Texas Holdings and its other subsidiaries. Accordingly, Oncor's assets will not be available to repay any of our debt.

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

Lenders or holders of our debt have in the past alleged, and might allege in the future, that we are not operating in compliance with the covenants in our debt agreements, that a default under our debt agreements has occurred or that our or our subsidiaries' boards of directors or similar bodies or officers are not properly discharging their fiduciary duties, or make other allegations regarding our business, including for the purpose, and potentially having the effect, of causing a default under our debt or other agreements, accelerating the maturity of such debt, protecting claims of debt issued at a certain entity or entities in our capital structure at the expense of debt claims elsewhere in our capital structure and/or obtaining economic benefits from us. These claims have included, and may include in the future, among other things, claims that the TCEH Demand Notes were fraudulent transfers and should be repaid to TCEH, that authorization of the TCEH Demand Notes violated the fiduciary duties of EFCH's and TCEH's boards of directors, that the TCEH Demand Notes were in violation of the terms of our debt agreements or that the interest rate on the TCEH Demand Notes was too low.

Further, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the past claimed, and may claim in the future, that a credit event has occurred under such credit derivative securities based on our financial condition. Even if these claims are without merit, they could nevertheless cause the trading price of our debt to decline and adversely affect our ability to raise additional capital and/or refinance our existing debt.

We may not be able to generate sufficient cash to service our debt and may be forced to take other actions to satisfy the obligations under our debt agreements, which may not be successful.

Our ability to make scheduled payments on our debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control, including, without limitation, wholesale electricity prices (which are primarily driven by the price of natural gas and ERCOT market heat rates) and environmental regulations. We may not be able to maintain a level of cash flows sufficient to pay the principal, premium, if any, and interest on our debt, including the $3.8 billion principal amount of TCEH Term Loan Facilities maturing in October 2014.

If cash flows and capital resources are insufficient to fund our debt obligations, we could face substantial liquidity problems and might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additional capital or restructure or refinance debt. These alternative measures may not be successful, may not be completed on economically attractive terms or may not be adequate for us to meet our debt obligations when due. Additionally, our debt agreements limit the use of the proceeds from many dispositions of assets or operations. As a result, we may not be permitted to use the proceeds from these dispositions to satisfy our debt obligations.

Further, if we suffer or appear to suffer, from a lack of available liquidity, the evaluation of our creditworthiness by counterparties and rating agencies and the willingness of third parties to do business with us could be adversely impacted. In particular, such concerns by existing and potential counterparties could significantly limit TCEH's wholesale market activities, including its natural gas price hedging program.

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) 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 or applicable law.

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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. has in the past relied significantly on loans from TCEH to meet its obligations, and if EFH Corp. does not receive distributions from Oncor in the future it may need to borrow funds from TCEH.

EFH Corp. is a holding company and substantially all of its reported consolidated assets are held by its subsidiaries. At December 31, 2012, TCEH and its subsidiaries held approximately 79% of EFH Corp.'s reported consolidated assets, and for the year ended December 31, 2012, TCEH and its subsidiaries represented all of EFH Corp.'s reported consolidated revenues. Accordingly, TCEH and its subsidiaries in the past constituted an important funding source for EFH Corp. to satisfy its obligations, which are significant. The terms of the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities permit TCEH to make loans and/or dividends (to the extent permitted by applicable state law) to cover certain of EFH Corp.'s obligations, particularly principal and interest payments. At December 31, 2012, TCEH had notes receivable from EFH Corp. (TCEH Demand Notes) totaling $698 million (see Note 15 to Financial Statements) that were repaid in January 2013, but TCEH may if necessary make additional loans to EFH Corp. in the future.

The TCEH Senior Secured Facilities contain provisions related to the TCEH Demand Notes, which are payable to TCEH on demand and and are guaranteed by EFCH and EFIH on a senior unsecured basis. These provisions include:

• TCEH may only make loans to EFH Corp. for debt principal and interest payments;

• borrowings outstanding under the TCEH Demand Notes will not exceed $2 billion in the aggregate at any time; and

• the sum of (a) the outstanding senior secured indebtedness (including guarantees) issued by EFH Corp. or any subsidiary of EFH Corp. (including EFIH) secured by a second-priority lien on the equity interests that EFIH owns in Oncor Holdings (EFIH Second-Priority Debt) and (b) the aggregate outstanding amount of the TCEH Demand Notes will not exceed, at any time, the maximum amount of EFIH Second-Priority Debt permitted by the indenture governing the EFH Corp. Senior Secured Notes as in effect on April 7, 2011.

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 into 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.

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Risks Related to Our Businesses

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 and the value of our nuclear and lignite/coal-fueled generation assets, which provided a substantial portion of our supply volumes in 2012, 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 $4.03 per MMBtu at December 31, 2012 for calendar year 2014). In recent years natural gas supply has outpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic downturn. 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.

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 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.

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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.

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. 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.

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 RRC, 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, and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. 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 current legislative session began in January 2013); 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.

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The PUCT and the RRC are subject to a “Sunset” review by the Texas Sunset Advisory Commission during the 2013 session of the Texas Legislature. The powers of the PUCT and the RRC may be materially changed, or the agencies may be abolished, by the Texas Legislature following such review. If the PUCT or the RRC are not renewed or are changed materially by the Texas Legislature pursuant to Sunset review, it could have a material effect on our businesses.

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 RRC are subject to review by the Sunset Commission in 2013. In 2011, the Texas Legislature extended the authority of the RRC and the PUCT until 2013. In 2013, the RRC will undergo a full sunset review, and the PUCT will undergo a limited sunset review. These agencies, for the most part, govern and operate the electricity and mining markets in Texas upon which our business model is based. If the Texas Legislature materially changes or fails to renew either of these agencies, it could have a material impact on our business. There can be no assurance that future action of the Sunset Commission will not result in legislation during the 2013 Legislative Session that could have a material effect on 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 9 to Financial Statements).

Over the past couple of years, the EPA has 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.

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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, several bills addressing climate change have been introduced 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 March 2012, the EPA released a proposal for a performance standard for greenhouse gas emissions from new electric generation units (EGUs). The proposal, which is currently limited to new sources, is based on the carbon dioxide emission rate from a natural gas-fueled combined cycle EGU. None of our existing generation units would be considered a new source under the proposed rule. While we do not believe the proposed rule, as released, affects our existing generation units, it could affect our ability to cost-effectively develop new generation facilities. If limits or guidelines become applicable to our generation facilities and require us to install new control equipment or substantially alter our operations, it could have a material effect on our results of operations, liquidity and financial condition.

We produce GHG emissions from the combustion of fossil fuels at our generation facilities. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our results of operations, liquidity and financial condition could be materially 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.

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If we are required to comply with the EPA's revised Cross-State Air Pollution Rule (CSAPR), or a similar replacement, and 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 emissions budgets for the State of Texas 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 total, the emissions budgets established by the Final Revisions along with the Second Revised Rule would require our fossil-fueled generation units to reduce (i) their annual SO₂ and NO_X emissions by approximately 120,600 tons (56 percent) and 9,000 tons (22 percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NO_X emissions by approximately 3,300 tons (18 percent), compared to 2010 levels. We could comply with these emissions limits either through physical reductions or through the purchase of emissions credits from third parties, but the volume of SO₂ credits that may be purchased from sources outside of Texas is subject to limitations starting in 2014. Because the CSAPR was vacated and remanded to the EPA in August 2012 by a three judge panel of the D.C. Circuit Court, the CSAPR, the Final Revisions and the Second Revised Rule do not impose any immediate legal or compliance requirements on us, the State of Texas, or other affected parties. In October 2012, the EPA and certain other parties that supported the CSAPR filed petitions seeking review by the full court of the D.C. Circuit Court's ruling. In January 2013, the D.C. Circuit Court denied the request for rehearing. The EPA and the other parties to these proceedings have approximately 90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predict whether, when, or in what form the CSAPR, the Final Revisions, the Second Revised Rule or any replacements will take effect.

Material capital expenditures would be required to comply with the CSAPR, as revised in June 2012, as well as with other pending and expected environmental regulations, including the MATS, for which we and certain states and industry participants have filed petitions for review in the D.C. Circuit Court. We cannot predict the outcome of these petitions.

Prior to the publication of the final MATS rule and the vacatur and remand of the CSAPR, we estimated that expenditures of more than $1.5 billion before the end of the decade in environmental control equipment would be required to comply with regulatory requirements, including the CSAPR and MATS. We have revised our estimates of capital expenditures for environmental control equipment to comply with regulatory requirements, based on analysis and testing of options to comply with the MATS rule, as well as estimates related to other EPA regulations, including expenditures previously incurred related to the CSAPR. Between 2011 and the end of the decade, we estimate that we will incur more than $1 billion in capital expenditures for environmental control equipment, though the ultimate total will depend on the evolution of pending or future regulatory requirements. Based on regulations currently in effect, we estimate that we will incur approximately $500 million of environmental capital expenditures between 2013 and 2017, including amounts required to maintain installed environmental control equipment.

We cannot predict whether the EPA or any other party will appeal the D.C. Circuit Court's decision with respect to the CSAPR to the US Supreme Court or, if such appeal is granted, how the US Supreme Court will rule on any such appeal of the CSAPR. 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.

Luminant's mining permits are subject to RRC review.

The RRC reviews on an ongoing basis whether Luminant is compliant with RRC rules and regulations and whether it has met all of the requirements of its mining permits. 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.

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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.

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 - Regulatory 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, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act) was enacted. 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. The legislation mandates significant compliance requirements for any entity that is determined to be a Swap Dealer or Major Swap Participant and additional reporting and recordkeeping requirements for all entities that participate in the derivative markets. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Key Risks and Challenges - Financial Services Reform Legislation."

The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateral requirements are unclear as to whether an end-user or its counterparty (e.g., swap dealer) is required to post cash collateral, there is risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. The final rule for margin requirements has not been issued. However, the legislative history of the Financial Reform Act suggests that it was not Congress' intent to require end-users to post cash collateral with respect to swaps. If we were required to post cash collateral on our swap transactions with swap dealers, our liquidity would likely be materially impacted, and our ability to enter into derivatives to hedge our commodity and interest rate risks would be significantly limited.

We cannot predict the outcome of the final rulemakings to implement the OTC derivative market provisions of the Financial Reform Act. Based on our assessment and published guidance from the CFTC, we are not a Swap Dealer or Major Swap Participant and we will be able to take advantage of the End-User Exemption for Swaps that hedge or mitigate commercial risk; however, the remaining rulemakings related to how Swap Dealers and other market participants administer margin requirements could negatively affect our ability to hedge our commodity and interest rate risks. The inability to hedge these risks would likely have a material effect on our results of operations, liquidity and financial condition.

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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, cybersecurity 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 cybersecurity 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. 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 cybersecurity 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.

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

Our results of operations may be 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.

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

Our retail operations face competition for customers. Competitors may offer lower prices and other incentives, 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 21% decline in customers (based on meters) served over the last four 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.

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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.

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

The PUCT may at any time initiate an investigation into whether our retail operations comply with PUCT Substantive Rules and whether we have met all of the requirements for REP certification, including financial requirements. 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.

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

Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. It is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with our traditional generation facilities. Consequently, where we have facilities, the profitability and market value of our generation assets could be significantly reduced. Changes in technology could also alter the channels through which retail customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be materially reduced.

Electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise 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. Furthermore, we may incur increased capital expenditures if we are required to increase investment in conservation measures.

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.

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.

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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.

Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of our hedging program, any significant increase in the price of natural gas could result in us being required to provide cash or letter of credit collateral in substantial amounts. Any perceived reduction in our creditworthiness could result in clearing agents or other counterparties requesting additional collateral. An event of default by one or more of our hedge counterparties could result in termination-related settlement payments that reduce available liquidity if we owe amounts related to commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. These events could have a material negative impact on our results of operations, liquidity and financial condition.

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.

In the event our credit facilities are being used largely to support the hedging program as a result of a significant increase in the price of natural gas or significant reduction in creditworthiness, we may have to forego certain capital expenditures or other investments in our businesses or other business opportunities.

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.

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 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 EFH Corp.'s 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.

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The values of the investments that fund EFH Corp.'s 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 plan 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 13 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.

As discussed in Note 3 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, we could be required in the future to write off some or all of this goodwill and other intangible assets, such as the goodwill impairments of $1.2 billion and $4.1 billion recorded in 2012 and 2010, respectively, 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.

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.

The Sponsor Group in the aggregate controls and may have conflicts of interest with us in the future.

The Sponsor Group in the aggregate indirectly owns approximately 60% of EFH Corp.'s capital stock on a fully-diluted basis through its investment in Texas Holdings. As a result of this ownership and the Sponsor Group's aggregate ownership in interests of the general partner of Texas Holdings, the Sponsor Group taken as a whole has control over decisions regarding our operations, plans, strategies, finances and structure, including whether to enter into any corporate transaction, and will have the ability to prevent any transaction that requires the approval of EFH Corp.'s shareholders. The Sponsor Group is comprised of Kohlberg Kravis Roberts & Co. L.P., TPG and GS Capital Partners, each of which acts independently of the others with respect to its investment in EFH Corp. and Texas Holdings.

The interests of these entities may differ in material respects from the interests of holders of EFCH and its subsidiaries' debt. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of the Sponsor Group, as equity holders or as members of the board of directors of EFH Corp., might conflict with our noteholders' and other creditors' interests. The Sponsor Group may also have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in their judgment, could enhance their equity investments, even though such transactions might involve risks to our noteholders and other creditors. Additionally, the agreements governing the terms of our debt permits us to distribute cash to EFH Corp. to pay advisory fees, dividends or make other restricted payments under certain circumstances, and the Sponsor Group may have an interest in our doing so.

Each member of the Sponsor Group is in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Members of the Sponsor Group may also pursue acquisition opportunities that may be complementary to our businesses and, as a result, those acquisition opportunities may not be available to us. So long as the members of the Sponsor Group, or other funds controlled by or associated with the members of the Sponsor Group, continue to indirectly own, in the aggregate, a significant amount of the outstanding shares of EFH Corp.'s common stock, even if such amount is less than 50%, the Sponsor Group will continue to be able to strongly influence or effectively control our decisions.

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Item 1B. UNRESOLVED STAFF COMMENTS

None.

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 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. Oral argument was held in this administrative appeal on October 23, 2012, and the 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. While we cannot predict the timing or outcome of this proceeding, we believe the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.

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

Regulatory Reviews

In June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of the CAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. 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. While we cannot predict whether the EPA will initiate enforcement proceedings under the notice of violation, we believe that we have complied with all requirements of the CAA at all of our generation facilities. We cannot predict the outcome of any resulting enforcement proceedings or estimate the penalties that might be assessed in connection with any such proceedings. In September 2012, we filed a petition for review in the United States Court of Appeals for 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, if any, is held. We cannot predict the outcome of these proceedings.

Other Matters

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

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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 RRC 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.

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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 common stock is owned by EFH Corp.

See Note 10 to Financial Statements for a description of the restrictions on EFCH's ability to pay dividends.

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Item 6. SELECTED FINANCIAL DATA

EFCH AND SUBSIDIARIES

SELECTED CONSOLIDATED FINANCIAL DATA

(millions of dollars, except ratios)

	Year Ended December 31,
	2012			2011			2010			2009			2008
Operating revenues	$	5,636		$	7,040		$	8,235		$	7,911		$	9,787
Impairment of goodwill	$	(1,200	)	$	—		$	(4,100	)	$	(70	)	$	(8,000	)
Net income (loss)	$	(3,008	)	$	(1,802	)	$	(3,530	)	$	515		$	(9,039	)
Ratio of earnings to fixed charges (a)	—			—			—			1.36			—
Cash provided by (used in) operating activities	$	(240	)	$	1,236		$	1,257		$	1,384		$	1,657
Cash provided by (used in) financing activities	$	1,161		$	(973	)	$	27		$	279		$	1,289
Cash provided by (used in) investing activities	$	134		$	(190	)	$	(1,338	)	$	(2,048	)	$	(2,682	)
Capital expenditures, including nuclear fuel	$	(844	)	$	(662	)	$	(902	)	$	(1,521	)	$	(2,074	)
	At December 31,
	2012			2011			2010			2009			2008
Total assets	$	32,973		$	37,340		$	39,144		$	43,245		$	43,000
Property, plant & equipment — net	$	18,556		$	19,218		$	20,155		$	20,980		$	20,902
Goodwill and intangible assets	$	6,733		$	7,978		$	8,523		$	12,845		$	13,096
Capitalization
Long-term debt, less amounts due currently	$	30,310		$	30,458		$	29,474		$	32,121		$	31,556
EFCH shareholder's equity	(10,506		)	(7,819		)	(6,236		)	(4,266		)	(5,002		)
Noncontrolling interests in subsidiaries	112			103			87			48			—
Total	$	19,916		$	22,742		$	23,325		$	27,903		$	26,554
Capitalization ratios
Long-term debt, less amounts due currently	152.2		%	133.9		%	126.4		%	115.1		%	118.8		%
EFCH shareholder's equity	(52.8		)%	(34.4		)%	(26.7		)%	(15.3		)%	(18.8		)%
Noncontrolling interests in subsidiaries	0.6		%	0.5		%	0.3		%	0.2		%	—		%
Total	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%
Short-term borrowings	$	2,136		$	774		$	1,221		$	953		$	900
Long-term debt due currently	$	96		$	39		$	658		$	302		$	269

___________

(a) Fixed charges exceeded earnings (see Exhibit 12(a)) by $3.932 billion, $2.745 billion, $3.212 billion and $9.543 billion for the years ended December 31, 2012, 2011, 2010 and 2008, respectively.

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Note: See Note 1 to Financial Statements "Basis of Presentation." Results 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 now reported as short-term borrowings as discussed in Note 7 to Financial Statements. Results for 2012 were significantly impacted by a goodwill impairment charge as discussed in Note 3 to Financial Statements. Results for 2011 were significantly impacted by an impairment charge related to emissions allowance intangible assets as discussed in Note 3 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 3 to Financial Statements and debt extinguishment gains as discussed in Note 6 to Financial Statements. Results for 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities.

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)
2012:
Operating revenues	$	1,222		$	1,385		$	1,752		$	1,278
Net loss	$	(253	)	$	(661	)	$	(385	)	$	(1,710	)

	First Quarter			Second Quarter			Third Quarter (b)			Fourth Quarter
2011:
Operating revenues	$	1,672		$	1,679		$	2,321		$	1,368
Net loss	$	(315	)	$	(667	)	$	(724	)	$	(96	)

___________

(a) Net loss includes the effect of a goodwill impairment charge (see Note 3 to Financial Statements).

(b) Net loss includes the effect of an impairment charge related to emissions allowance intangible assets (see Note 3 to Financial Statements).

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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, 2012, 2011 and 2010 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. 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

Natural Gas Price Hedging Program and Other Hedging Activities — Because wholesale electricity prices in ERCOT have generally moved with natural gas prices, TCEH has a natural gas price hedging program designed to mitigate the effect of natural gas price changes on future electricity revenues. Under the program, we have entered into market transactions involving natural gas-related financial instruments, and at December 31, 2012, have effectively sold forward approximately 360 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 42,000 GWh at an assumed 8.5 market heat rate) at weighted average annual hedge prices as shown in the table below. Volumes and hedge values associated with the natural gas price hedging program are inclusive of offsetting purchases entered into to take into account new wholesale and retail electricity sales contracts and avoid over-hedging. This activity results in both commodity contract asset and liability balances pending the maturity and settlement of the offsetting transactions.

Taking together forward wholesale and retail electricity sales with the natural gas positions in the hedging program, we have effectively hedged an estimated 96% and 41% of the price exposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2013 and 2014, respectively (assuming an 8.5 market heat rate). The natural gas positions were entered into with the continuing expectation that wholesale electricity prices in ERCOT will generally move with prices of natural gas, which we expect to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOT market. If the relationship changes in the future, the cash flows targeted under the natural gas price hedging program may not be achieved.

The company has entered into related put and call transactions (referred to as collars), primarily for 2014, that effectively hedge natural gas prices within a range. These transactions represented 42% of the positions in the natural gas price hedging program at December 31, 2012, 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.

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The following table summarizes the natural gas positions in the hedging program at December 31, 2012:

	Measure	2013	2014	Total
Natural gas hedge volumes (a)	mm MMBtu	~211	~146	~357
Weighted average hedge price (b)	$/MMBtu	~6.89	~7.80	—
Average market price (c)	$/MMBtu	~3.54	~4.03	—
Realization of hedge gains (d)	$ billions	~$1.0	~$0.6	~$1.6

___________

(a) Where collars are reflected, the volumes are based on the notional position of the derivatives to represent protection against downward price movements. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 146 million MMBtu in 2014.

(b) Weighted average hedge prices are based on prices of positions in the natural gas price hedging program (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.

(d) Based on cumulative unrealized mark-to-market gain at December 31, 2012.

Changes in the fair value of the instruments in the natural gas price hedging program are recorded as unrealized gains and losses in net gain 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 price hedging program at December 31, 2012, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $360 million in pretax unrealized mark-to-market gains or losses.

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

	Year Ended December 31,
	2012			2011			2010
Realized net gain	$	1,833		$	1,265		$	1,151
Unrealized net gain (loss) including reversals of previously recorded amounts related to positions settled	(1,540		)	(19		)	1,165
Total	$	293		$	1,246		$	2,316

The cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging program totaled $1.584 billion and $3.124 billion at December 31, 2012 and 2011, respectively. The decline was driven by settlement of maturing positions.

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

The significant cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging program 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 price hedging program is designed to mitigate the effect on earnings of low wholesale electricity prices, depressed forward natural gas prices are challenging to our liquidity and the long-term profitability of our business. Specifically, low natural gas prices and their effect in ERCOT on wholesale electricity prices could have a material impact on our liquidity and TCEH's overall profitability for periods in which TCEH does not have significant hedge positions. See Note 1 to Financial Statements.

Also see Note 3 to Financial Statements for discussion regarding goodwill impairment charges recorded in 2012 and 2010.

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TCEHInterest Rate Swap Transactions — TCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at December 31, 2012, 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%	February 2013 through October 2014		$	18.46	billion (a)
6.8	%	-	9.0%	October 2015 through October 2017		$	12.60	billion (b)

___________

(a) Swaps related to an aggregate $2.6 billion principal amount of debt expired in 2012. Per the terms of the transactions, the notional amount of swaps entered into in 2011 grew by $2.405 billion, substantially offsetting the expired swaps.

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

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

TCEH has also entered into interest rate basis swap transactions that further reduce the fixed borrowing costs achieved through the interest rate swaps. Basis swaps in effect at December 31, 2012 totaled $11.967 billion notional amount, a decrease of $5.783 billion from December 31, 2011 reflecting both new and expired swaps. The basis swaps relate to debt outstanding through 2014.

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

	Year Ended December 31,
	2012			2011			2010
Realized net loss	$	(670	)	$	(684	)	$	(673	)
Unrealized net gain (loss)	166			(812		)	(207		)
Total	$	(504	)	$	(1,496	)	$	(880	)

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.065 billion and $2.231 billion at December 31, 2012 and 2011, respectively, of which $65 million and $76 million (both pretax), respectively, were reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. For example, at December 31, 2012, a one percent change in interest rates would result in an increase or decrease of approximately $675 million in our cumulative unrealized mark-to-market net liability.

First-Lien Security for Natural Gas Hedging Program and Interest Rate Swaps — Approximately 85% of the positions in the natural gas price hedging program and all of the TCEH interest rate swaps are secured by a first-lien interest in the assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities. Certain entities are counterparties to both our natural gas hedge program positions and our interest rate swaps and have entered into master agreements that provide for netting and setoff of amounts related to these positions. At December 31, 2012, our net liability positions related to these counterparties together with liability positions related to entities that are counterparties to only our interest rate swaps totaled approximately $1.2 billion. This amount is not expected to change materially through 2013 assuming market values do not change significantly.

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Pension Plan Actions — In August 2012, EFH Corp. approved certain amendments to its pension plan (see Note 13 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);

• splitting off assets and liabilities under the plan associated with active employees of EFH Corp.'s competitive businesses, other than collective bargaining unit (union) employees, to a Terminating Plan, freezing benefits and vesting all accrued plan benefits for these participants;

• the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities under the Terminating Plan, and

• maintaining assets and liabilities under the plan associated with union employees of EFH Corp.'s competitive businesses under the current plan.

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

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 are being 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 2012 and expects to settle the remaining $50 million with EFH Corp. in the first quarter 2013.

Impairment of Goodwill— In 2012 and 2010, we recorded $1.2 billion and $4.1 billion, respectively, noncash goodwill impairment charges (which were not deductible for income tax purposes). The write-offs reflected the estimated effect of lower wholesale power prices on TCEH's enterprise value, driven by the sustained decline in forward natural gas prices as discussed above. Recorded goodwill totaled $4.95 billion at December 31, 2012.

The noncash impairment charge 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 3 to Financial Statements and "Application of Critical Accounting Policies" below for more information on goodwill impairment testing and charges.

Liability Management Program — At December 31, 2012, we had $30.5 billion principal amount of long-term debt outstanding, including $450 million pushed down from EFH Corp. We and EFH Corp. have implemented a liability management program designed to reduce debt, capture debt discount and extend debt maturities through debt exchanges, repurchases and extensions.

Amendments to the TCEH Senior Secured Facilities completed in April 2011 and January 2013 resulted in the extension of $16.4 billion in loan maturities under the TCEH Term Loan Facilities and the TCEH Letter of Credit Facility from October 2014 to October 2017 and $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016.

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

Security (except where noted, debt amounts are principal amounts)	Debt Acquired		Debt Issued/Cash Paid
TCEH 10.25% Notes due 2015	$	1,513	$	—
TCEH Toggle Notes due 2016	758		—
TCEH Senior Secured Facilities due 2013 and 2014	1,604		—
TCEH 15% Notes due 2021	—		1,221
TCEH 11.5% Notes due 2020 (a)	—		1,604
Cash paid, including use of proceeds from debt issuances in 2010 (b)	—		343
Total	$	3,875	$	3,168

____________

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

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

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

As the result of EFH Corp. and EFIH liability management transactions in December 2012 and early 2013, substantially all EFH Corp. debt guaranteed by EFCH was cancelled or amended to remove EFCH's guarantee, such that EFCH now guarantees only $60 million principal amount of EFH Corp. debt (see Note 8 to Financial Statements).

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

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

Also see "Key Risks and Challenges – Substantial Leverage, Uncertain Financial Markets and Liquidity Risk" and Notes 1 and 8 to Financial Statements.

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.

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

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

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

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

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

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

ERCOT previously had a zonal wholesale market structure consisting of four geographic zones. The new location-based congestion-management market is referred to as a "nodal" market because wholesale pricing differs across the various nodes on the transmission grid instead of across the geographic zones. There are over 550 nodes in the ERCOT market. The nodal market design was implemented in conjunction with transmission improvements designed to reduce current congestion. We are certified to participate in both the "day-ahead" and "real-time markets." Additionally, all of our operational generation assets and our qualified scheduling entities are certified and operate in the nodal market. Since the opening of the nodal market, the amount of letters of credit posted with ERCOT to support our market participation has fluctuated between $110 million and $420 million based upon weekly settlement activity, and at December 31, 2012, totaled $190 million.

As discussed above, the nodal market design includes the establishment of a "day-ahead market" and hub trading prices to facilitate hedging and trading of electricity by participants. Under the previous zonal market, volumes under our nontrading bilateral purchase and sales contracts, including contracts intended as hedges, were scheduled as physical power with ERCOT and, therefore, reported gross as wholesale revenues or purchased power costs. In conjunction with the transition to the nodal market, unless the volumes represent physical deliveries to retail and wholesale customers or purchases from counterparties, these contracts are reported on a net basis in the income statement in net gain from commodity hedging and trading activities. As a result of these changes, reported wholesale revenues and purchased power costs (and the associated volumes) in 2012 and 2011 were materially less than amounts reported in prior periods.

Recent PUCT/ERCOT Actions — In response to ERCOT's publication of reports (known as the Capacity, Demand, and Reserves report and the Seasonal Assessment of Resource Adequacy report) showing declining reserve margins in the ERCOT market, the PUCT and the ERCOT Board of Directors took action to implement or approve in 2012 several changes to ERCOT protocols designed to establish minimum offer floors for wholesale power offers during deployment of certain reliability-related services, including non-spinning reserve, responsive reserve, reliability unit commitment, and other services. In addition, in June and October 2012 the PUCT approved rules that, among other things, increased the 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 1, 2012, and increased the cap to $5,000, $7,000, and $9,000 per MWh in the summers of 2013, 2014, and 2015, respectively, for the stated purpose of sending appropriate price signals to encourage development of generation resources in ERCOT. Also in June 2012, the Brattle Group, an independent consultant engaged by ERCOT to assess the incentives for generation investment in the ERCOT market, issued a report on potential next steps for addressing generation resource adequacy. The Brattle report discusses a range of potential solutions that could promote resource adequacy in the ERCOT market, ranging from enhancing the current energy-only structure in the ERCOT market to creating a capacity market structure, whereby generators receive capacity payments to ensure available generation in the market and provide a return on the generator's investment, similar to those used in certain other competitive markets in the US. The Brattle report concluded that, even if the wholesale energy offer cap were increased to $9,000 per MWh, the expected corresponding reserve margin that would be obtained in the current energy-only market design would be approximately 10%. ERCOT's current target reserve margin is 13.75%. Discussions are ongoing among ERCOT, the PUCT, market participants and other stakeholders regarding the range of solutions presented in the Brattle report and the actions necessary to continue providing reliable electricity supply in ERCOT.

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Seasonal Suspension of Certain Generation Operations — In October 2012, ERCOT approved our filing of notice of intent to suspend operations at two of the three generation units at our Monticello generation facility due to low wholesale power prices and other market conditions. Beginning December 1, 2012, we suspended operations for approximately six months, with both units expected to return to service during the peak demand months in the summer of 2013. Our mines that support the Monticello generation facility will continue year round operations. Based on cash flow projections and related analysis, no asset impairment was recorded as a result of the suspension. At current wholesale market prices of electricity, we do not expect the suspension of operations to significantly impact our results of operations, liquidity or financial condition.

Natural Gas-Fueled Generation Development — In December 2012, Luminant filed a permit application with the TCEQ to build two natural gas combustion turbines totaling 420 MW at its existing DeCordova generation facility. While current market conditions do not provide adequate economic returns for the development or construction of new generation, we believe additional generation resources will be needed to support continued electricity demand growth and reliability in the ERCOT market. See "Recent PUCT/ERCOT Actions" above for discussion of actions by the PUCT and ERCOT to encourage development of new generation resources.

Settlement of Make-Whole Agreements with Oncor—See Note 15 to Financial Statements for discussion of the settlement in the third quarter 2012 of our interest and tax-related reimbursement agreements with Oncor associated with Oncor's bankruptcy-remote financing subsidiary's securitization bonds.

Sunset Review — 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 RRC are subject to review by the Sunset Commission in 2013. In 2011, the Texas Legislature extended the authority of the RRC and the PUCT until 2013. In 2013, the RRC will undergo a full sunset review, and the PUCT will undergo a limited sunset review. We cannot predict the outcome of the sunset review process.

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

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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."

Substantial Leverage, Uncertain Financial Markets and Liquidity Risk

Our substantial leverage, resulting in large part from debt incurred to finance the Merger, and the covenants contained in our debt agreements require significant cash flows to be dedicated to interest and principal payments and could adversely affect our ability to raise additional capital to fund operations and limit our ability to react to changes in the economy, our industry (including environmental regulations) or our business. Principal amounts of short-term borrowings and long-term debt, including amounts due currently, totaled $32.7 billion at December 31, 2012, and cash interest payments in 2012 totaled $2.6 billion.

Significant amounts of our long-term debt mature in the next few years, including approximate principal amounts of $80 million in 2013, $3.9 billion in 2014 and $3.7 billion in 2015. A substantial amount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities. In April 2011, we secured an extension of the maturity date of approximately $16.4 billion principal amount of debt under these facilities to 2017, and in April 2011 and January 2013, we secured the extension of the entire $2.05 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016. Notwithstanding the extension, the maturity could be reset to an earlier date under a "springing maturity" provision if, as of a defined date, certain amounts of TCEH unsecured debt maturing prior to 2017 are not refinanced and TCEH's debt to Adjusted EBITDA ratio exceeds 6.00 to 1.00. In addition, the agreement covering the TCEH Senior Secured Facilities includes a secured debt to Adjusted EBITDA financial maintenance covenant and a covenant requiring TCEH to timely deliver to the lenders audited annual financial statements that are not qualified as to the status of TCEH and its consolidated subsidiaries as a going concern (see "Financial Condition – Liquidity and Capital Resources – Financial Covenants, Credit Rating Provisions and Cross Default Provisions" and Notes 1 and 8 to Financial Statements).

In consideration of our substantial leverage, there can be no assurance that counterparties to our credit facility and hedging arrangements will perform as expected and meet their obligations to us. Failure of such counterparties to meet their obligations or substantial changes in financial markets, the economy, regulatory requirements, our industry or our operations could result in constraints in our liquidity. While traditional counterparties with physical assets to hedge, as well as financial institutions and other parties, continue to participate in the markets, low natural gas and wholesale electricity prices, continued market and regulatory uncertainty and our liquidity and upcoming debt maturities have limited our hedging and trading activities, particularly for longer-dated transactions, which could impact our ability to hedge our commodity price and interest rate exposure to desired levels at reasonable costs. See discussion of credit risk in Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," discussion of available liquidity and liquidity effects of the natural gas price hedging program in "Financial Condition – Liquidity and Capital Resources" and discussion of potential impacts of legislative rulemakings on the OTC derivatives market below in "Financial Services Reform Legislation."

In addition, because our operations are capital intensive, we expect to rely over the long-term upon access to financial markets as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our available credit facilities. Our ability to economically access the capital or credit markets could be restricted at a time when we would like, or need, to access those markets. Lack of such access could have an impact on our flexibility to react to changing economic and business conditions.

Further, a continuation, or further decline, of current forward natural gas prices could result in further declines in the values of TCEH's nuclear and lignite/coal-fueled generation assets and limit or hinder TCEH's ability to hedge its wholesale electricity revenues at sufficient price levels to support its significant interest payments and debt maturities, which could adversely impact TCEH's ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt. See discussion above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Price Hedging Program and Other Hedging Activities."

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At December 31, 2012, TCEH had $1.2 billion of cash and cash equivalents and $183 million of available capacity under its letter of credit facility. In January 2013, TCEH's liquidity increased by approximately $700 million as a result of the settlement of the TCEH Demand Notes by EFH Corp. Based on the current forecast of cash from operating activities, which reflects current forward market electricity prices, projected capital expenditures and other cash flows, we expect that TCEH will have sufficient liquidity to meets its obligations until October 2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures. TCEH's ability to satisfy this obligation is dependent upon the implementation of one or more of the actions described immediately below.

EFH Corp., EFCH and TCEH continue to consider and evaluate possible transactions and initiatives to address their highly leveraged balance sheets and significant cash interest requirements and may from time to time enter into discussions with their lenders and bondholders with respect to such transactions and initiatives. Progress to date includes the debt extensions, exchanges, issuances and repurchases completed in 2010 and 2011, which resulted in the capture of $700 million of debt discount and the extension of approximately $19.6 billion of debt maturities to 2017-2021. Future transactions and initiatives may include, among others, debt for debt exchanges, recapitalizations, amendments to and extensions of debt obligations and debt for equity exchanges or conversions, including exchanges or conversions of debt of EFCH and TCEH into equity of EFH Corp., EFCH, TCEH and/or any of their subsidiaries. These actions could result in holders of TCEH debt instruments not recovering the full principal amount of those obligations. We have also hedged a substantial portion of variable rate debt exposure through 2017 using interest rate swaps. See "Significant Activities and Events and Items Influencing Future Performance - Liability Management Program" and Note 8 to Financial Statements.

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 trended downward in recent years, reflecting discovery and increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic downturn.

	Forward Market Prices for Calendar Year ($/MMBtu) (a)
Date	2013		2014		2015		2016
December 31, 2008	$	7.15	$	7.15	$	7.21	$	7.30
March 31, 2009	$	7.11	$	7.18	$	7.25	$	7.33
June 30, 2009	$	7.30	$	7.43	$	7.57	$	7.71
September 30, 2009	$	7.06	$	7.17	$	7.31	$	7.43
December 31, 2009	$	6.67	$	6.84	$	7.05	$	7.24
March 31, 2010	$	6.07	$	6.36	$	6.68	$	7.00
June 30, 2010	$	5.89	$	6.10	$	6.37	$	6.68
September 30, 2010	$	5.29	$	5.42	$	5.60	$	5.76
December 31, 2010	$	5.33	$	5.49	$	5.64	$	5.79
March 31, 2011	$	5.41	$	5.73	$	6.08	$	6.41
June 30, 2011	$	5.16	$	5.42	$	5.70	$	5.98
September 30, 2011	$	4.80	$	5.13	$	5.39	$	5.61
December 31, 2011	$	3.94	$	4.34	$	4.60	$	4.85
March 31, 2012	$	3.47	$	3.96	$	4.26	$	4.51
June 30, 2012	$	3.58	$	3.95	$	4.13	$	4.29
September 30, 2012	$	3.84	$	4.18	$	4.37	$	4.55
December 31, 2012	$	3.54	$	4.03	$	4.23	$	4.42

___________

(a) Based on NYMEX Henry Hub prices.

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. All other factors being equal, these nuclear and lignite/coal-fueled generation assets, which provided the substantial majority of supply volumes in 2012, 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.

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The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate movements also affect wholesale electricity prices. 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, increased wind generation capacity could result in lower market heat rates. 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.

As discussed above in "Significant Activities and Events and Items Influencing Future Performance," we have implemented a natural gas price hedging program 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, 2012, we have no significant 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 and certain other commodity prices and market heat rates on realized pretax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH's unhedged position and forward prices at December 31, 2012, which for natural gas reflects estimates of electricity generation less amounts hedged through the natural gas price hedging program and amounts under existing wholesale and retail sales contracts. On a rolling basis, generally twelve-months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

	Balance 2013 (a)	2014	2015
$1.00/MMBtu change in natural gas price (b)	$ ~18	$ ~270	$ ~480
0.1/MMBtu/MWh change in market heat rate (c)	$ ~5	$ ~25	$ ~35
$1.00/gallon change in diesel fuel price	$ ~13	$ ~45	$ ~50

___________

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

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

(c) Based on Houston Ship Channel natural gas prices at December 31, 2012.

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 (which is also subject to volatility resulting from customer churn, weather, economic and other factors) in our businesses. 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.

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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 rules 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 9 to Financial Statements for discussion of "Litigation Related to Generation Facilities," "Regulatory 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."

Competitive Retail Markets and Customer Retention

Competitive retail activity in Texas has resulted in retail customer churn. Our total retail customer counts declined 4% in 2012, 9% in 2011 and 6% in 2010. Based upon 2012 results discussed below in "Results of Operations," a 1% decline in residential customers would result in a decline in annual revenues of approximately $29 million. In responding to the competitive landscape in the ERCOT marketplace, we are focusing on the following key initiatives:

• Maintaining competitive pricing initiatives on residential service plans;

• Profitably growing the retail customer base by actively competing for new and existing customers in areas in Texas open to competition. 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. Over the past five years, TXU Energy has invested $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.

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

In May 2012, the US Commodity Futures Trading Commission (CFTC) published its final rule defining the terms Swap Dealer and Major Swap Participant. Additionally, in July 2012, the CFTC approved the final rules defining the term Swap and the end-user clearing exemption. The definition of the term Swap and the Swap Dealer/Major Swap Participant rule became effective in October 2012. Accordingly, we are required to assess our activity to determine if we will be required to register as a Swap Dealer or Major Swap Participant. Based on our assessment, we are not a Swap Dealer or Major Swap Participant. In October 2012, the CFTC issued various no-action letters granting temporary relief from enforcement from certain aspects of the definition of Swap and the Swap Dealer/Major Swap Participant rule.

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

The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateral requirements are unclear as to whether an end-user or its counterparty (e.g., swap dealer) is required to post cash collateral, there is a risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. The final rule for margin requirements has not been issued. However, the legislative history of the Financial Reform Act suggests that it was not Congress' intent to require end-users to post cash collateral with respect to swaps. If we were required to post cash collateral on our swap transactions with swap dealers, 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.

We cannot predict the outcome of the final rulemakings to implement the OTC derivative market provisions of the Financial Reform Act. Based on our assessment and published guidance from the CFTC, we believe our historical practices related to our use of Swaps does not qualify us as a Swap Dealer or Major Swap Participant, and we believe we will be able to take advantage of the End-User Exemption for Swaps that hedge or mitigate commercial risk; however, the remaining rulemakings related to how Swap Dealers and other market participants administer margin requirements could negatively affect our ability to hedge our commodity and interest rate risks. Accordingly, we (and other market participants) continue to closely monitor the rulemakings and any other potential legislative and regulatory changes and work with regulators and legislators. We have provided them information on our operations, the types of transactions in which we engage, our concerns regarding potential regulatory impacts, market characteristics and related matters.

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 2013 at December 31, 2012) to be approximately $1.5 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 9 to Financial Statements.

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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.

Declining Reserve Margins in ERCOT

Planning reserve margin represents the percentage by which estimated system generation capacity exceeds anticipated peak load. As reflected in the table below, ERCOT is projecting reserve margins in the ERCOT market in 2013 will be below ERCOT's minimum reserve planning criterion of 13.75% and will continue to decline. Weather extremes, unplanned generation facility outages and variability in wind generation all exacerbate the risks of inadequate reserve margins.

	2013		2014		2015		2016
Firm load forecast (MW)	65,952		67,592		69,679		71,613
Resources forecast (MW)	74,633		74,943		76,974		77,703
Reserve margin (a)	13.2	%	10.9	%	10.5	%	8.5	%

___________

(a) Source: ERCOT's "Report on the Capacity, Demand, and Reserves in the ERCOT Region - December 2012." Reserve margin (planning) = (Resources forecast - Firm load forecast) / Firm load forecast.

We and the ERCOT market broadly experienced the effects of weather extremes and reduced generation availability in 2011. Severe cold weather in North Texas 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 inadequate 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, while supporting demand side management and utilization of smart grid and advanced meter technology to implement ERCOT mandated rotating outages to noncritical customers. 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 new generation to meet growing demand in the ERCOT market. See "Significant Activities and Events and Items Influencing Future Performance – Recent PUCT/ERCOT Actions."

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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. We also apply the knowledge gained by continuing to invest in technology, processes and services to detect, mitigate and protect our cyber assets. These investments include upgrades to network architecture, regular intrusion detection monitoring and compliance with emerging industry regulation.

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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 our financial statements. Merger-related debt of EFH Corp. held by its subsidiaries is not subject to push down. The amount reflected in our 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., we record the settlement of such amounts as noncash capital contributions from EFH Corp. As a result of transactions completed by EFIH and EFH Corp. in January 2013, only $60 million principal amount of debt remains subject to push down. See Note 8 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 plants 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.

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.

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.

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Since the Merger, we have recorded goodwill impairment charges totaling $13.370 billion, including $1.2 billion recorded in 2012, $4.1 billion recorded in 2010 and $8.070 billion recorded largely in 2008. The total impairment charges represented approximately 75% of the goodwill balance resulting from purchase accounting for the Merger. The impairments in 2012 and 2010 reflected the estimated effect of lower wholesale power prices in ERCOT on the enterprise value of TCEH, 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 3 to Financial Statements for additional discussion.

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 11 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.

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, 2012, we do not have any derivatives designated as cash flow or fair value hedges, we continually assess potential hedge elections and could designate positions as cash flow hedges in the future. In March 2007, the instruments making up a significant portion of the natural gas price hedging program that were previously designated as cash flow hedges were dedesignated as allowed under accounting standards related to derivative instruments and hedging activities, and subsequent changes in their fair value have been marked-to-market in net income. In addition, in August 2008, interest rate swap transactions in effect at that time were dedesignated as cash flow hedges in accordance with accounting standards, and subsequent changes in their fair value have been marked-to-market in net income. See further discussion of the natural gas price hedging program and interest rate swap transactions under "Significant Activities and Events and Items Influencing Future Performance."

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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,
	2012			2011			2010
Amounts recognized in net income (loss) (after-tax):
Unrealized net gains on positions marked-to-market in net income	$	287		$	205		$	1,257
Unrealized net losses representing reversals of previously recognized fair values of positions settled in the period	(1,162		)	(696		)	(606		)
Unrealized gain on termination of a long-term power sales contract	—			—			75
Reclassifications of net losses on cash flow hedge positions from other comprehensive income	(7		)	(19		)	(59		)
Total net gain (loss) recognized	$	(882	)	$	(510	)	$	667
Amounts recognized in other comprehensive income (loss) (after-tax):
Reclassifications of net losses on cash flow hedge positions to net income	$	7		$	19		$	59

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

	December 31,
	2012			2011
Commodity contract assets	$	2,047		$	4,435
Commodity contract liabilities	$	(383	)	$	(1,245	)
Interest rate swap assets	$	2		$	—
Interest rate swap liabilities	$	(2,067	)	$	(2,231	)
Net accumulated other comprehensive loss included in shareholders' equity (amounts after tax)	$	(42	)	$	(49	)

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 12 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. These techniques include, but are not limited to, the use of broker quotes and statistical relationships between different price curves and are intended to maximize the use of observable inputs and minimize the use of unobservable inputs. In applying the market approach, we use a mid-market valuation convention (the mid-point between bid and ask prices) as a practical expedient.

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 long-term 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. Level 2 inputs include:

• quoted prices for similar assets or liabilities in active markets;

• quoted prices for identical or similar assets or liabilities in markets that are not active;

• 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

• inputs that are derived principally from or corroborated by observable market data by correlation or other means.

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Examples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assets or liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example, certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets; however, an active market might exist for such derivatives for a different time period at the same location. We utilize correlation techniques to compare prices for inputs at both time periods to provide a basis to value those derivatives that do not have active markets. (See Note 11 to Financial Statements for additional discussion of how broker quotes are utilized.)

Our Level 3 valuations generally apply to 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. We use the most meaningful information available from the market, combined with our own internally developed valuation methodologies, to develop our best estimate of fair value. The determination of fair value for Level 3 assets and liabilities requires significant management judgment and estimation.

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. 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.

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 rating 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.

Level 3 assets totaled $83 million and $124 million at December 31, 2012 and 2011, respectively, and represented approximately 3% and 2%, respectively, of the assets measured at fair value, or less than 1% of total assets in both years. Level 3 liabilities totaled $54 million and $71 million at December 31, 2012 and 2011, respectively, and represented approximately 2% of the liabilities measured at fair value, or less than 1% of total liabilities in both years.

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, 2012 and 2011, a 10% change in electricity price (per MWh) assumptions across unobservable inputs would cause an approximate $8 million and $5 million change, respectively, in net Level 3 assets. A 10% change in coal price assumptions across unobservable inputs would cause an approximate $8 million and $21 million change, respectively, in net Level 3 assets. See Note 11 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, 2012, 2011 and 2010.

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 2 to Financial Statements for information regarding our consolidated variable interest entities.

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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 $260 million, $269 million and $297 million at December 31, 2012, 2011 and 2010, 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 $26 million, $56 million and $108 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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, 2012. See Note 9 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 bound by 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. See Notes 1, 4 and 5 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. 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 20 to 57 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 3 to Financial Statements for additional information.

56

RESULTS OF OPERATIONS

Effects of Change in Wholesale Electricity Market

As discussed above under "Significant Activities and Events and Items Influencing Future Performance," the nodal wholesale market design implemented by ERCOT in December 2010 resulted in operational changes that facilitate hedging and trading of power. As part of ERCOT's transition to a nodal wholesale market, volumes under nontrading bilateral purchase and sales contracts are no longer scheduled as physical power with ERCOT. As a result of these changes in market operations, reported wholesale revenues and purchased power costs in 2012 and 2011 were materially less than amounts reported in prior periods. Effective with the nodal market implementation, if volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues. Conversely, if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record additional purchased power costs. The resulting additional wholesale revenues or purchased power costs are offset in net gain from commodity hedging and trading activities.

Sales Volume and Customer Count Data

	Year Ended December 31,						2012		2011
	2012		2011		2010		% Change		% Change
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential	23,283		27,337		28,208		(14.8	)	(3.1	)
Small business (a)	5,914		7,059		8,042		(16.2	)	(12.2	)
Large business and other customers	10,373		12,828		15,339		(19.1	)	(16.4	)
Total retail electricity	39,570		47,224		51,589		(16.2	)	(8.5	)
Wholesale electricity sales volumes (b)	34,524		34,496		51,359		0.1		(32.8	)
Total sales volumes	74,094		81,720		102,948		(9.3	)	(20.6	)
Average volume (kWh) per residential customer (c)	14,617		16,100		15,532		(9.2	)	3.7
Weather (North Texas average) – percent of normal (d):
Cooling degree days	114.7	%	132.7	%	108.9	%	(13.6	)	21.9
Heating degree days	82.0	%	109.7	%	116.6	%	(25.3	)	(5.9	)
Customer counts:
Retail electricity customers (end of period and in thousands) (e):
Residential	1,560		1,625		1,771		(4.0	)	(8.2	)
Small business (a)	176		185		217		(4.9	)	(14.7	)
Large business and other customers	17		19		20		(10.5	)	(5.0	)
Total retail electricity customers	1,753		1,829		2,008		(4.2	)	(8.9	)

___________

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

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

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

(d) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over 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.

57

Revenue and Commodity Hedging and Trading Activities

	Year Ended December 31,							2012		2011
	2012			2011		2010		% Change		% Change
Operating revenues:
Retail electricity revenues:
Residential	$	2,918		$	3,377	$	3,663	(13.6	)	(7.8	)
Small business (a)	738			896		1,052		(17.6	)	(14.8	)
Large business and other customers	717			997		1,211		(28.1	)	(17.7	)
Total retail electricity revenues	4,373			5,270		5,926		(17.0	)	(11.1	)
Wholesale electricity revenues (b)(c)	1,005			1,482		2,005		(32.2	)	(26.1	)
Amortization of intangibles (d)	21			18		16		16.7		12.5
Other operating revenues	237			270		288		(12.2	)	(6.3	)
Total operating revenues	$	5,636		$	7,040	$	8,235	(19.9	)	(14.5	)
Net gain from commodity hedging and trading activities:
Realized net gains on settled positions	$	1,953		$	971	$	1,008	101.1		(3.7	)
Unrealized net gains (losses)	(1,564		)	40		1,153		—		—
Total	$	389		$	1,011	$	2,161	(61.5	)	(53.2	)

___________

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

(b) Upon settlement of physical derivative commodity contracts, such as certain electricity sales and purchase agreements and coal purchase contracts, that we mark-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which we deem "unrealized." (The offsetting differences between contract and market prices are reported in net gain from commodity hedging and trading activities.) These amounts are as follows:

	Year Ended December 31,
	2012			2011		2010
Reported in revenues	$	(1	)	$	—	$	(28	)
Reported in fuel and purchased power costs	39			18		96
Net gain	$	38		$	18	$	68

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

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

58

Production, Purchased Power and Delivery Cost Data

	Year Ended December 31,									2012		2011
	2012			2011			2010			% Change		% Change
Fuel, purchased power costs and delivery fees ($ millions):
Fuel for nuclear facilities	$	175		$	160		$	159		9.4		0.6
Fuel for lignite/coal facilities (a)	816			992			915			(17.7	)	8.4
Total nuclear and lignite/coal facilities (a)	991			1,152			1,074			(14.0	)	7.3
Fuel for natural gas facilities and purchased power costs (a) (b)	323			426			1,497			(24.2	)	(71.5	)
Amortization of intangibles (c)	48			111			161			(56.8	)	(31.1	)
Other costs	194			309			187			(37.2	)	65.2
Fuel and purchased power costs	1,556			1,998			2,919			(22.1	)	(31.6	)
Delivery fees	1,260			1,398			1,452			(9.9	)	(3.7	)
Total	$	2,816		$	3,396		$	4,371		(17.1	)	(22.3	)
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
Nuclear facilities	$	8.78		$	8.30		$	7.89		5.8		5.2
Lignite/coal facilities (a) (d)	$	20.54		$	19.79		$	19.28		3.8		2.6
Natural gas facilities and purchased power (a) (e)	$	45.06		$	53.26		$	43.81		(15.4	)	21.6
Delivery fees per MWh	$	31.75		$	29.52		$	28.06		7.6		5.2
Production and purchased power volumes (GWh):
Nuclear facilities	19,897			19,283			20,208			3.2		(4.6	)
Lignite/coal facilities (f)	49,298			58,165			54,775			(15.2	)	6.2
Total nuclear- and lignite/coal facilities	69,195			77,448			74,983			(10.7	)	3.3
Natural gas-facilities	1,295			1,233			1,648			5.0		(25.2	)
Purchased power (g)	3,604			3,039			26,317			18.6		(88.5	)
Total energy supply volumes	74,094			81,720			102,948			(9.3	)	(20.6	)
Capacity factors:
Nuclear facilities	98.5		%	95.7		%	100.3		%	2.9		(4.6	)
Lignite/coal facilities (f)	70.0		%	83.5		%	82.2		%	(16.2	)	1.6
Total	76.4		%	86.2		%	86.6		%	(11.4	)	(0.5	)

___________

(a) 2011 and 2010 reflect 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 3 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 (c) immediately above.

(f) Includes the estimated effects of economic backdown of lignite/coal-fueled units totaling 9,550 GWh, 4,290 GWh and 3,536 GWh in 2012, 2011 and 2010, respectively.

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

59

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 due to lower sales volumes and $43 million in lower average prices. Sales volumes fell 16% reflecting declines in both the residential and business markets. Residential market 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 activity. 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 production was driven by increased economic backdown and generation unit planned and unplanned outages, while nuclear-fueled production increased 3% reflecting one refueling outage in 2012 and two in 2011.

Following is an analysis of amounts reported as net gain 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 is largely reflective of the natural gas price hedging program discussed above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Price Hedging Program and Other Hedging Activities":

	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).

60

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.

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 3 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 6 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 13 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 6 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 a 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. The effective rate was 33.8% in 2012, excluding the $1.2 billion nondeductible goodwill impairment charge, and 34.4% in 2011. 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.

After-tax 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.

61

Financial Results – Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Operating revenues decreased $1.195 billion, or 15%, to $7.040 billion in 2011.

Retail electricity revenues decreased $656 million, or 11%, to $5.270 billion and reflected the following:

• An 8% decrease in sales volumes reduced revenues by $501 million and was driven by declines in the large and small business and residential markets. Business market volumes decreased 15% reflecting reduced contract signings driven by competitive activity. Residential market volumes decreased 3% reflecting an 8% decline in customer count driven by competitive activity, partially offset by a 4% increase in average consumption driven by warmer summer weather.

• Lower average pricing reduced revenues by $155 million reflecting declining prices in all customer segments. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

Wholesale electricity revenues decreased $523 million, or 26%, to $1.482 billion in 2011. The decrease is primarily attributable to the nodal market change described above, partially offset by higher production from the new lignite-fueled generation units and lower retail sales volumes.

Fuel, purchased power costs and delivery fees decreased $975 million, or 22%, to $3.396 billion in 2011. Purchased power costs decreased $1.029 billion driven by the effect of the nodal market described above. Delivery fees declined $54 million reflecting lower retail sales volumes, partially offset by higher rates. Amortization of intangible assets decreased $50 million reflecting expiration of contracts fair-valued at the Merger date under purchase accounting. These decreases were partially offset by $77 million in higher coal/lignite costs driven by higher costs related to purchased coal and increased generation.

A 6% increase in lignite/coal-fueled production was driven by increased production from the newly constructed generation facilities, while nuclear-fueled production decreased 5% primarily due to planned outages in 2011.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities, which totaled $1.011 billion and $2.161 billion in net gains for the years ended December 31, 2011 and 2010, respectively, which reflected the natural gas price hedging program discussed above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Price Hedging Program and Other Hedging Activities":

	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

	Year Ended December 31, 2010
	Net Realized Gains		Net Unrealized Gains (Losses)			Total
Hedging positions	$	961	$	1,157		$	2,118
Trading positions	47		(4		)	43
Total	$	1,008	$	1,153		$	2,161

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 $18 million in net gains in 2011 and $68 million in net gains in 2010.

62

Operating costs increased $87 million, or 10%, to $924 million in 2011. The increase reflected $48 million in higher nuclear generation maintenance costs reflecting two planned refueling outages in 2011 as compared to one planned refueling outage in 2010 and $27 million in higher costs at legacy lignite/coal-fueled generation units reflecting spending for environmental control systems including the CSAPR, and supply chain technology and equipment reliability process improvements. The increase also reflected $20 million in incremental expense related to a new generation unit placed in service in May 2010. The operating cost increases were partially offset by $9 million in lower maintenance costs at natural gas-fueled generation facilities reflecting the retirement of nine units in 2010.

Depreciation and amortization increased $90 million, or 7%, to $1.470 billion in 2011. The increase reflected $44 million of accelerated depreciation in 2011 resulting from the revised estimated useful lives for mine assets due to the then planned mine closures needed to comply with the CSAPR (see Note 3 to Financial Statements for discussion of the effects of the CSAPR), $37 million in increased depreciation primarily related to lignite/coal-fueled generation facilities reflecting equipment additions and replacements and $36 million in incremental depreciation related to the new lignite-fueled generation unit discussed above. These increases were partially offset by $24 million in decreased amortization of intangible assets largely related to the retail customer relationship and reflecting expected customer attrition (see Note 3 to Financial Statements).

SG&A expenses increased $6 million, or 1%, to $728 million in 2011. The increase was driven by $39 million in higher employee compensation and benefit costs and $16 million in higher information technology and other services costs, partially offset by $52 million in lower retail bad debt expense due to improved collection initiatives and customer mix.

In 2010, a $4.1 billion impairment of goodwill was recorded as discussed in Note 3 to Financial Statements.

Other income totaled $48 million in 2011 and $903 million in 2010. Other income in 2011 included $21 million related to the settlement of bankruptcy claims against a counterparty, $7 million for a property damage claim and $6 million from a franchise tax refund related to prior years. Other income in 2010 included debt extinguishment gains of $687 million, a $116 million gain on termination of a power sales contract, a $44 million gain on the sale of land and related water rights and a $37 million gain associated with the sale of interests in a natural gas gathering pipeline business. See Note 6 to Financial Statements.

Other deductions totaled $524 million in 2011 and $18 million in 2010. Other deductions in 2011 resulting from the issuance of the CSAPR included a $418 million impairment charge for excess SO₂ emissions allowances due to emissions allowance limitations under the CSAPR and a $9 million impairment of mining assets. Other deductions in 2011 also included $86 million in third party fees related to the amendment and extension of the TCEH Senior Secured Facilities. See Notes 3, 6 and 8 to Financial Statements.

Interest expense and related charges increased $725 million, or 24%, to $3.792 billion in 2011. Interest paid/accrued increased $141 million to $2.618 billion driven by higher average rates reflecting debt exchanges and amendments. The balance of the increase reflected $605 million in higher unrealized mark-to-market net losses related to interest rate swaps, $61 million in higher amortization of debt issuance and amendment costs and discounts and $29 million in lower capitalized interest, partially offset by $60 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting and a $51 million decrease in interest accrued or paid with additional toggle notes due to debt exchanges and repurchases.

Income tax benefit totaled $943 million on a pretax loss in 2011 compared to income tax expense totaling $318 million on a pretax gain in 2010, before the nondeductible goodwill impairment charge. The effective rate was 34.4% and 35.8% in 2011 and 2010, respectively, excluding the goodwill impairment charge. The decrease in the rate was driven by lower state taxes due to lower taxable margins, partially offset by the effect of ongoing tax deductions (principally lignite depletion) on a pretax loss in 2011 compared to pretax income in 2010.

After-tax loss decreased $1.728 billion to $1.802 billion in 2011 reflecting the $4.1 billion goodwill impairment charge in 2010, partially offset in 2011 by lower gains from commodity hedging and trading activities, higher interest expense driven by unrealized mark-to-market net losses related to interest rate swaps, charges and expenses resulting from the issuance of the CSAPR and debt extinguishment gains in 2010.

63

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, 2012, 2011 and 2010. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.521 billion in unrealized net losses in 2012 and $58 million and $1.219 billion in unrealized net gains in 2011 and 2010, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. The portfolio consists primarily of economic hedges but also includes trading positions.

	Year Ended December 31,
	2012			2011			2010
Commodity contract net asset at beginning of period	$	3,190		$	3,097		$	1,718
Settlements of positions (a)	(1,800		)	(1,081		)	(943		)
Changes in fair value of positions in the portfolio (b)	279			1,139			2,162
Other activity (c)	(5		)	35			160
Commodity contract net asset at end of period	$	1,664		$	3,190		$	3,097

____________

(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 recognized, reflecting net gains related to positions in the natural gas price hedging program (see discussion above under "Significant Activities and Events and Items Influencing Future Performance – Natural Gas Price Hedging Program and Other Hedging Activities"), partially offset by net losses related to 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. The 2010 amount includes a $116 million noncash gain on termination of a long-term power sales contract.

Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values at December 31, 2012, 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, 2012
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(25	)	$	(3	)	$	—		$	—		$	(28	)
Prices provided by other external sources	1,089			574			—			—			1,663
Prices based on models	34			(5		)	—			—			29
Total	$	1,098		$	566		$	—		$	—		$	1,664
Percentage of total fair value	66		%	34		%	—		%	—		%	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 extend through 2014 and over-the-counter quotes for natural gas generally extend through 2016, depending upon delivery point. The "prices based on models" category reflects 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 11 to Financial Statements for fair value disclosures and discussion of fair value measurements.

64

FINANCIAL CONDITION

Liquidity and Capital Resources

Operating Cash Flows

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 — Cash used in operating activities totaled $240 million 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 program; 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 13 to Financial Statements).

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 — Cash provided by operating activities decreased $21 million to $1.236 billion in 2011. The change included the effect of amended accounting standards related to the accounts receivable securitization program (see Note 7 to Financial Statements), under which the $383 million of funding under the program at the January 1, 2010 adoption was reported as a use of operating cash flows and a source of financing cash flows. Excluding this accounting effect, cash provided by operating activities declined $404 million. This decrease reflected lower cash earnings due to the low wholesale power price environment, lower generation and higher fuel and operating costs at our legacy generation facilities and an approximately $230 million increase in cash interest payments, partially offset by the contribution from the new lignite-fueled generation units (see Results of Operations). These effects were partially offset by a $408 million increase in net margin deposits received.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $178 million, $237 million and $276 million for the years ended December 31, 2012, 2011 and 2010, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice, and amortization of intangible net assets arising from purchase accounting that is reported in various other income statement line items including operating revenues and fuel and purchased power costs and delivery fees.

Financing Cash Flows

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 8 to Financial Statements), partially offset by a $159 million payment to settle transition bond reimbursement agreements with Oncor (see Note 15 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, as discussed in Note 8 to Financial Statements.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 — Cash used in financing activities totaled $973 million in 2011 compared to cash provided by financing activities of $27 million in 2010. 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, as discussed in Note 9 to Financial Statements. Activity in 2010 reflected a $96 million source of financing cash flows, reflecting a $383 million effect of an accounting change related to the accounts receivable securitization program as discussed above, net of a $287 million reduction of borrowings under the program.

See Note 8 to Financial Statements for further detail of short-term borrowings and long-term debt.

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Investing Cash Flows

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 15 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 for 2012 are net of $19 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 2013 in accordance with a settlement agreement with the DOE.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 — Cash used in investing activities totaled $190 million and $1.338 billion in 2011 and 2010, respectively. Investing activities reflected net repayments on notes receivable from affiliates totaling $346 million in 2011 and net loans under the notes totaling $503 million in 2010. Capital expenditures decreased $266 million to $530 million in 2011 driven by a decrease in spending related to the construction of new generation facilities and timing and scope of maintenance projects. Nuclear fuel purchases increased $26 million to $132 million in 2011 reflecting the refueling of both nuclear-fueled generation units in 2011.

Capital expenditures, including nuclear fuel, in 2011 totaled $662 million and consisted of:

• $338 million for major maintenance, primarily in existing generation operations;

• $142 million for environmental expenditures related to generation units;

• $132 million for nuclear fuel purchases and

• $50 million for information technology, nuclear generation development and other corporate investments.

Cash capital expenditures in 2011 are net of $24 million of reimbursements from the DOE related to dry cask storage.

Debt Financing Activity— Activities related to short-term borrowings and long-term debt during the year ended December 31, 2012 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

	Borrowings		Repayments and Repurchases
TCEH (a)	$	196	$	(30	)
EFCH	—		(10		)
EFH Corp. (pushed down to EFCH) (b)	27		(284		)
Total long-term	223		(324		)
Total short-term – TCEH (c)	1,384		—
Total	$	1,607	$	(324	)

____________

(a) Borrowings represent $181 million of noncash principal increases of TCEH Toggle Notes issued in May and November 2012 in payment of accrued interest and $15 million of sale/leaseback and other lease transactions for mining equipment. Repayments represent $16 million of payments of principal at scheduled maturity dates and $14 million of payments of capital lease liabilities.

(b) Borrowings represent noncash principal increases of EFH Corp. Toggle Notes issued in May and November 2012 in payment of accrued interest. Repayments represent noncash retirements related to December 2012 debt exchanges.

(c) Short-term amount represents net borrowings under the TCEH Revolving Credit Facility.

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See Note 8 to Financial Statements for further detail of long-term debt and other financing arrangements.

Available Liquidity — The following table summarizes changes in available liquidity for the year ended December 31, 2012.

	Available Liquidity
	December 31, 2012		December 31, 2011		Change
Cash and cash equivalents	$	1,175	$	120	$	1,055
TCEH Revolving Credit Facility	—		1,384		(1,384		)
TCEH Letter of Credit Facility	183		169		14
Total liquidity	$	1,358	$	1,673	$	(315	)

Available liquidity decreased $315 million since December 31, 2011 reflecting cash used for both capital expenditures (including nuclear fuel purchases) and operating activities totaling $1.1 billion, partially offset by EFH Corp.'s net repayment of $894 million of TCEH Demand Notes. EFH Corp. repaid the remaining balance of $698 million of TCEH Demand Notes in January 2013.

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

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

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

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

Liquidity Needs, Including Capital Expenditures — Capital expenditures and nuclear fuel purchases for 2013 are expected to total approximately $720 million and include:

• $560 million for investments in generation facilities, including approximately:

• $460 million for major maintenance and

• $100 million for environmental expenditures related to the MATS and other regulations;

• $140 million for nuclear fuel purchases and

• $20 million for information technology, nuclear generation development and other corporate investments.

We expect cash flows from operations, cash on hand and availability under our credit facilities discussed in Note 8 to Financial Statements to provide sufficient liquidity to fund our current obligations, projected working capital requirements and capital spending for at least the next twelve months. See Note 1 to Financial Statements for further discussion of liquidity considerations.

Liquidity Effects of Commodity Hedging and Trading Activities—Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral posting obligations. At December 31, 2012, approximately 85% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral posting requirements for those hedging transactions. See Note 8 to Financial Statements for more information about the TCEH Senior Secured Facilities.

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Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. At December 31, 2012, 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 thereby reducing liquidity in the event that it was not restricted. See Note 16 to Financial Statements regarding restricted cash.

With the natural gas price hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit postings to counterparties. At December 31, 2012, approximately 65 million MMBtu of positions related to the natural gas price hedging program were not directly secured on an asset-lien basis and thus are subject to cash collateral posting requirements.

At December 31, 2012, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $69 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $50 million posted at December 31, 2011;

• $598 million in cash has been received from counterparties, net of $2 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $1.055 billion received, net of $6 million in cash posted, at December 31, 2011;

• $376 million in letters of credit have been posted with counterparties, as compared to $363 million posted at December 31, 2011, and

• $22 million in letters of credit have been received from counterparties, as compared to $103 million received at December 31, 2011.

Income Tax Payments — In the next twelve months, income tax payments to EFH Corp. related to the Texas margin tax are expected to total approximately $40 million, and we do not expect to make any payments to EFH Corp. related to federal income taxes. Net payments totaled $84 million, $123 million and $49 million for the years ended December 31, 2012, 2011 and 2010, respectively. (See Note 15 to Financial Statements.)

We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions, but expect that no material federal income tax payments related to such positions will be made in the next 12 months (see Note 4 to Financial Statements).

Interest Rate Swap Transactions — See Note 8 to Financial Statements for discussion of TCEH's interest rate swaps.

Accounts Receivable Securitization Program— TCEH participates in an accounts receivable securitization program with financial institutions. In accordance with transfers and servicing accounting standards, the trade accounts receivable amounts under the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Energy Receivables Company, a consolidated, wholly-owned, bankruptcy-remote, direct subsidiary of TCEH. TXU Energy Receivables Company borrows funds from entities established for this purpose by the participating financial institutions using the accounts receivable as collateral. All new trade receivables under the program generated by the originator are continuously purchased by TXU Energy Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program and its predecessor totaled $82 million and $104 million at December 31, 2012 and 2011, respectively. See Note 7 to Financial Statements.

Capitalization — Our capitalization ratios consisted of 152.2% and 133.9% long-term debt, less amounts due currently, and (52.2)% and (33.9)% common stock equity, at December 31, 2012 and 2011, respectively. Total debt to capitalization, including short-term debt, was 146.9% and 132.8% at December 31, 2012 and 2011, respectively.

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Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of the TCEH Senior Secured Facilities contain a maintenance covenant with respect to leverage ratio. At December 31, 2012, we were in compliance with such covenant.

Covenants and Restrictions under Financing Arrangements— The TCEH Senior Secured Facilities and the indentures governing substantially all of the debt we have issued in connection with, and subsequent to, the Merger contain covenants that could have a material impact on our liquidity and operations. In particular, the TCEH Senior Secured Facilities include a requirement to timely deliver to the lenders copies of audited annual financial statements that are not qualified as to the status of TCEH and its subsidiaries as a going concern.

Adjusted EBITDA (as used in the maintenance covenant contained in the TCEH Senior Secured Facilities) for the year ended December 31, 2012 totaled $3.574 billion for TCEH. See Exhibits 99(b) and 99(c) for a reconciliation of net loss to Adjusted EBITDA for TCEH and EFH Corp., respectively, for the years ended December 31, 2012 and 2011.

The table below summarizes TCEH's secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp. and TCEH that are applicable under certain other thresholds in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Notes, the TCEH Senior Secured Second Lien Notes and the EFH Corp. Senior Notes at December 31, 2012 and 2011. The debt incurrence and restricted payments/limitations on investments covenants thresholds described below represent levels that must be met in order for EFH Corp. or TCEH to incur certain permitted debt or make certain restricted payments and/or investments. EFCH and its consolidated subsidiaries are in compliance with their maintenance covenants. In January 2013, in accordance with amendments to the terms of the EFH Corp. Senior Secured Notes and their governing indentures, restrictive covenants to the notes were removed. Accordingly, the related coverage ratios are not reflected below (see Note 8 to Financial Statements).

	December 31, 2012	December 31, 2011	Threshold Level at December 31, 2012
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to Adjusted EBITDA ratio (a)	5.88 to 1.00	5.78 to 1.00	Must not exceed 8.00 to 1.00 (b)
Debt Incurrence Thresholds:
TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes:
TCEH fixed charge coverage ratio	1.2 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.2 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Thresholds:
EFH Corp. Senior Notes:
General restrictions (Sponsor Group payments):
EFH Corp. leverage ratio	10.1 to 1.0	9.7 to 1.0	Equal to or less than 7.0 to 1.0
TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes:
TCEH fixed charge coverage ratio	1.2 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to Adjusted EBITDA ratio	8.5 to 1.0	8.7 to 1.0	Equal to or less than 6.5 to 1.0

___________

(a) At December 31, 2012, includes actual Adjusted EBITDA for the more recently constructed Oak Grove (1 and 2) generation units and the Sandow 5 generation unit and all outstanding debt under the Delayed Draw Term Loan. At December 31, 2011, includes pro forma Adjusted EBITDA for the Oak Grove 2 unit as well as actual Adjusted EBITDA for Sandow 5 and Oak Grove 1 units and all outstanding debt under the Delayed Draw Term Loan.

(b) Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities and up to $1.5 billion ($906 million excluded at December 31, 2012) principal amount of TCEH senior secured first lien notes whose proceeds are used to prepay term loans or deposit letter of credit loans under the TCEH Senior Secured Facilities.

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Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity — As a result of TCEH's non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, at December 31, 2012, counterparties to those contracts could have required TCEH to post up to an aggregate of $20 million in additional collateral. This amount largely represents the below market terms of these contracts at December 31, 2012; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. At December 31, 2012, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $26 million, with $11 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at December 31, 2012, TCEH posted letters of credit in the amount of $71 million, which are subject to adjustments.

The RRC has rules in place to assure that parties can meet their mining reclamation obligations, including through self-bonding when appropriate. If Luminant Generation Company LLC (a subsidiary of TCEH) does not continue to meet the self-bonding requirements as applied by the RRC, TCEH may be required to post cash, letter of credit or other tangible assets as collateral support in an amount currently estimated to be approximately $850 million to $1.1 billion. The actual amount (if required) could vary depending upon numerous factors, including the amount of Luminant Generation Company LLC's self-bond accepted by the RRC and the level of mining reclamation obligations.

ERCOT has rules in place to assure adequate credit worthiness of parties that participate in the "day-ahead," "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 $190 million at December 31, 2012 (which is subject to daily adjustments based on settlement activity with ERCOT).

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

Other arrangements of EFCH and its subsidiaries, including the accounts receivable securitization program (see Note 7 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

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

A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the accounts receivable securitization program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.295 billion at December 31, 2012) under such facilities.

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

Under the terms of a TCEH rail car lease, which had $41 million in remaining lease payments at December 31, 2012 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in an aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

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Under the terms of another TCEH rail car lease, which had $44 million in remaining lease payments at December 31, 2012 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Energy Receivables Company (a direct subsidiary of TCEH) has a cross default threshold of $50,000. If any of these cross default provisions were triggered, the program could be terminated.

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

Each ofTCEH's natural gas hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities and TCEH Senior Secured Notes contain a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge or interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to result in a significant effect on liquidity.

Long-Term Contractual Obligations and Commitments— The following table summarizes our contractual cash obligations at December 31, 2012 (see Notes 8 and 9 to Financial Statements for additional disclosures regarding these long-term debt and noncancellable purchase obligations).

Contractual Cash Obligations:	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Long-term debt – principal (a)	$	84	$	7,592	$	18,034	$	4,762	$	30,472
Long-term debt – interest (b)	2,619		4,769		3,296		2,218		12,902
Operating and capital leases (c)	56		96		123		169		444
Obligations under commodity purchase and services agreements (d)	926		1,124		503		865		3,418
Total contractual cash obligations	$	3,685	$	13,581	$	21,956	$	8,014	$	47,236

___________

(a) Excludes short-term borrowings (including $2.054 billion of borrowings under the TCEH Revolving Credit Facilities that mature in 2016, capital lease obligations (shown separately), unamortized premiums and discounts and fair value premiums and discounts related to purchase accounting.

(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect at December 31, 2012.

(c) Includes short-term noncancellable leases.

(d) 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 2012 price for all periods except where contractual price adjustment or index-based prices are specified.

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The following are not included in the table above:

• arrangements between affiliated entities and intercompany debt (see Note 15 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 $1.078 billion (as well as accrued interest totaling $172 million) discussed in Note 4 to Financial Statements as the ultimate timing of payment, if any, is not known.

Guarantees — See Note 9 to Financial Statements for details of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

See Notes 2 and 9 to Financial Statements regarding VIEs and guarantees, respectively.

COMMITMENTS AND CONTINGENCIES

See Note 9 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, 2012 that are expected to materially impact our financial statements.

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

Risk Oversight

We manage the commodity price, counterparty credit and commodity-related operational risk related to the 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, 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

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

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

Natural Gas Price Hedging Program —See "Significant Activities and Events and Items Influencing Future Performance" above for a description of the program, including potential effects on reported results.

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

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

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

	Year Ended December 31,
	2012		2011
Month-end average Trading VaR:	$	7	$	4
Month-end high Trading VaR:	$	12	$	8
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,
	2012		2011
Month-end average MtM VaR:	$	132	$	195
Month-end high MtM VaR:	$	206	$	268
Month-end low MtM VaR:	$	96	$	121

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). A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.

	Year Ended December 31,
	2012		2011
Month-end average EaR:	$	109	$	170
Month-end high EaR:	$	161	$	228
Month-end low EaR:	$	77	$	121

The increase in the Trading VaR risk measure above reflected higher near-term market volatility and an increase in trading positions. The decreases in the MtM VaR and EaR risk measures above reflected a reduction of positions in the natural gas price hedging program due to maturities and lower forward natural gas prices.

74

Interest Rate Risk

The table below provides information concerning our financial instruments at December 31, 2012 and 2011 that are sensitive to changes in interest rates, which consist of debt obligations and interest rate swaps. We have entered into interest rate swaps under which we have exchanged fixed-rate and variable-rate interest amounts calculated with reference to specified notional principal amounts at dates that generally coincide with interest payments under our credit facilities. In addition, we have entered into certain interest rate basis swaps to further reduce borrowing costs as discussed in Note 8 to Financial Statements. The weighted average interest rate presented is based on the rate in effect at the reporting date. Capital leases and the effects of unamortized premiums and discounts are excluded from the table. Average interest rate and average receive rate for variable rate instruments are based on rates in effect at December 31, 2012. See Note 8 to Financial Statements for a discussion of debt obligations.

	Expected Maturity Date
	(millions of dollars, except percentages)
	2013			2014			2015			2016			2017			There- after			2012 Total Carrying Amount			2012 Total Fair Value		2011 Total Carrying Amount			2011 Total Fair Value
Long-term debt (including current maturities):
Fixed rate debt amount (a)	$	84		$	43		$	3,505		$	1,765		$	70		$	4,557		$	10,024		$	3,955	$	10,124		$	5,574
Average interest rate	7.11		%	6.36		%	10.24		%	11.23		%	10.69		%	11.72		%	11.05		%			11.04		%
Variable rate debt amount	$	—		$	3,890		$	154		$	154		$	16,045		$	205		$	20,448		$	13,903	$	20,447		$	13,166
Average interest rate	—		%	3.76		%	4.75		%	4.75		%	4.74		%	0.23		%	4.51		%			4.54		%
Total debt	$	84		$	3,933		$	3,659		$	1,919		$	16,115		$	4,762		$	30,472		$	17,858	$	30,571		$	18,740
Debt swapped to fixed:
Amount (b)	$	1,600		$	16,860		$	3,000		$	—		$	9,600		$	—							$	—
Average pay rate	8.53		%	8.24		%	6.85		%	—		%	8.95		%	—		%						—
Average receive rate	4.81		%	4.81		%	4.87		%	—		%	4.88		%	—		%						—
Variable basis swaps:
Amount	$	10,917		$	1,050		$	—		$	—		$	—		$	—		$	11,967				$	19,167
Average pay rate	0.33		%	0.32		%	—		%	—		%	—			—			0.33		%			0.39		%
Average receive rate	0.21		%	0.21		%	—		%	—		%	—			—			0.21		%			0.26		%

___________

(a) Reflects the remarketing date and not the maturity date for certain debt that is subject to mandatory tender for remarketing prior to maturity. See Note 8 to Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing.

(b) $18.46 billion notional amount outstanding that matures in 2013 through October 2014 and $12.6 billion notional amount beginning October 2014 that mature through October 2017. Notional amounts maturing in 2013 will be replaced by accretion of existing swaps maturing through October 2014.

At December 31, 2012, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $11 million, taking into account the interest rate swaps discussed in Note 8 to Financial Statements.

75

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 $1.321 billion at December 31, 2012. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at December 31, 2012 include $454 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $64 million. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

The remaining credit exposure arises from wholesale trade receivables, commodity contracts and hedging and trading activities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. At December 31, 2012, the exposure to credit risk from these counterparties totaled $867 million taking into account the netting provisions of the master agreements described above but before taking into account $612 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $255 million decreased $326 million for the year ended December 31, 2012, driven by maturities of positions in the natural gas price hedging program.

Of this $255 million net exposure, essentially all is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies' published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.

The following table presents the distribution of credit exposure at December 31, 2012 arising from wholesale trade receivables, commodity contracts and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions in the balance sheet arising from hedging and trading activities after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 12 to Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

									Gross Exposure by Maturity
	Exposure Before Credit Collateral			Credit Collateral		Net Exposure			2 years or less		Between 2-5 years		Greater than 5 years		Total
Investment grade	$	866		$	612	$	254		$	866	$	—	$	—	$	866
Noninvestment grade	1			—		1			1		—		—		1
Totals	$	867		$	612	$	255		$	867	$	—	$	—	$	867
Investment grade	99.9		%			99.6		%
Noninvestment grade	0.1		%			0.4		%

76

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 three counterparties, which represented 19%, 15% and 10% of the $255 million net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, each of which is rated as investment grade, and the importance of our business relationship with the counterparties.

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

77

FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as 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:

• prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the US Federal Energy Regulatory Commission, the NERC, the TRE, the PUCT, the RRC, the NRC, the EPA, the TCEQ, the US Mine Safety and Health Administration and the US Commodity Futures Trading Commission, with respect to, among other things:

◦ allowed prices;

◦ industry, market and rate structure;

◦ purchased power and recovery of investments;

◦ operations of nuclear generation facilities;

◦ operations of fossil-fueled generation facilities;

◦ operations of mines;

◦ acquisition and disposal of assets and facilities;

◦ development, construction and operation of facilities;

◦ decommissioning costs;

◦ present or prospective wholesale and retail competition;

◦ changes in tax laws and policies;

◦ changes in and compliance with environmental and safety laws and policies, including the CSAPR, MATS and climate change initiatives, and

◦ clearing over the counter derivatives through exchanges and posting of cash collateral therewith;

• legal and administrative proceedings and settlements;

• general industry trends;

• economic conditions, including the impact of an economic downturn;

• our ability to collect trade receivables from counterparties;

• our ability to attract and retain profitable customers;

• our ability to profitably serve our customers;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;

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

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

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

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

• population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT;

• changes in business strategy, development plans or vendor relationships;

• access to adequate transmission facilities to meet changing demands;

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

• changes in operating expenses, liquidity needs and capital expenditures;

• commercial bank market and capital market conditions and the potential impact of disruptions in US and international credit markets;

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

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

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

78

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

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

• our ability to successfully execute our liability management program or otherwise address our debt maturities;

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

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

• competition for new energy development and other business opportunities;

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

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

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

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

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

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

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

• significant changes in critical accounting policies;

• actions by credit rating agencies;

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

• our ability to effectively execute our operational strategy, and

• our ability to implement cost reduction initiatives.

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

INDUSTRY AND MARKET INFORMATION

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

79

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Competitive Holdings Company

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Energy Future Competitive Holdings Company (a subsidiary of Energy Future Holdings Corp.) and subsidiaries ("EFCH") as of December 31, 2012 and 2011, and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and equity for each of the three years in the period ended December 31, 2012. 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 and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

EFCH continues to experience net losses, has substantial indebtedness and has significant cash interest requirements. EFCH's ability to satisfy its obligations in October 2014, which include the maturities of $3.8 billion of Texas Competitive Electric Holdings Company LLC ("TCEH") Term Loan Facilities, is dependent upon the completion of one or more actions discussed in Note 1 to the consolidated financial statements. Also see Note 8 to the consolidated financial statements. Additionally, as discussed in Note 15 to the consolidated financial statements, TCEH has made loans, which are payable on demand, to its indirect parent, Energy Future Holdings Corp., with amounts outstanding as of December 31, 2012 and 2011 of $698 million (which were repaid in January 2013) and $1.592 billion, respectively.

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, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2013 expressed an unqualified opinion on EFCH's internal control over financial reporting.

/s/    DELOITTE & TOUCHE LLP

Dallas, Texas

February 19, 2013

80

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

	Year Ended December 31,
	2012			2011			2010
	(millions of dollars)
Operating revenues	$	5,636		$	7,040		$	8,235
Fuel, purchased power costs and delivery fees	(2,816		)	(3,396		)	(4,371		)
Net gain from commodity hedging and trading activities	389			1,011			2,161
Operating costs	(888		)	(924		)	(837		)
Depreciation and amortization	(1,343		)	(1,470		)	(1,380		)
Selling, general and administrative expenses	(659		)	(728		)	(722		)
Franchise and revenue-based taxes	(80		)	(96		)	(106		)
Impairment of goodwill (Note 3)	(1,200		)	—			(4,100		)
Other income (Note 6)	13			48			903
Other deductions (Note 6)	(188		)	(524		)	(18		)
Interest income	46			86			90
Interest expense and related charges (Note 16)	(2,842		)	(3,792		)	(3,067		)
Loss before income taxes	(3,932		)	(2,745		)	(3,212		)
Income tax (expense) benefit (Note 5)	924			943			(318		)
Net loss	$	(3,008	)	$	(1,802	)	$	(3,530	)

See Notes to Financial Statements.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2012			2011			2010
	(millions of dollars)
Net loss	$	(3,008	)	$	(1,802	)	$	(3,530	)
Other comprehensive income, net of tax effects – cash flow hedges derivative value net loss related to hedged transactions recognized during the period and reported in net loss (net of tax benefit of $3, $10 and $31)	7			19			59
Comprehensive loss	$	(3,001	)	$	(1,783	)	$	(3,471	)

See Notes to Financial Statements.

81

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31,
	2012			2011			2010
	(millions of dollars)
Cash flows — operating activities:
Net loss	$	(3,008	)	$	(1,802	)	$	(3,530	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation and amortization	1,521			1,707			1,656
Deferred income tax expense (benefit), net	(952		)	(1,116		)	534
Impairment of goodwill (Note 3)	1,200			—			4,100
Unrealized net (gain) loss from mark-to-market valuations of commodity positions	1,526			(58		)	(1,221		)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps (Note 8)	(166		)	812			207
Interest expense on toggle notes payable in additional principal (Notes 8 and 16)	152			166			217
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 16)	201			227			226
Interest expense related to pushed-down debt of parent (Notes 8 and 16)	75			78			211
Unsettled charges related to pension plan actions (Note 13)	50			—			—
Impairment of emissions allowances intangible assets (Note 3)	—			418			—
Other asset impairments (Note 6)	31			9			—
Third-party fees related to debt amendment and extension transactions (Note 8) (reported as financing)	—			86			—
Debt extinguishment gains (Note 6)	—			—			(687		)
Gain on termination of long-term power sales contract (Note 6)	—			—			(116		)
Bad debt expense (Note 7)	26			56			108
Accretion expense related primarily to mining reclamation obligations (Note 16)	37			48			57
Stock-based incentive compensation expense	4			5			7
Net equity loss from unconsolidated affiliate	3			4			5
Net (gain) loss on sale of assets	4			(2		)	(81		)
Other, net	1			2			13
Changes in operating assets and liabilities:
Affiliate accounts receivable/payable, net	(87		)	(4		)	5
Accounts receivable - trade	22			175			258
Impact of accounts receivable securitization program (Note 7)	—			—			(383		)
Inventories	19			(23		)	(6		)
Accounts payable - trade	(126		)	(126		)	(149		)
Commodity and other derivative contractual assets and liabilities	6			(33		)	(44		)
Margin deposits, net	(476		)	540			132
Other - net assets	(52		)	(27		)	20
Other - net liabilities	(251		)	94			(282		)
Cash provided by (used in) operating activities	(240		)	1,236			1,257
Cash flows — financing activities:
Issuances of long-term debt (Note 8)	—			1,750			353
Repayments/repurchases of long-term debt (Note 8)	(40		)	(1,408		)	(647		)
Net short-term borrowings under accounts receivable securitization program (Note 7)	(22		)	8			96
Increase (decrease) in other short-term borrowings (Note 8)	1,384			(455		)	172
Notes due to affiliates	—			—			34
Decrease in income tax-related note payable to Oncor (Note 15)	(20		)	(39		)	(37		)
Settlement of reimbursement agreements with Oncor (Note 15)	(159		)	—			—

82

	Year Ended December 31,
	2012			2011			2010
	(millions of dollars)
Contributions from noncontrolling interests	7			16			32
Sale/leaseback of equipment	15			—			—
Debt amendment, exchange and issuance costs, including third-party fees expensed	(5		)	(843		)	(13		)
Other, net	1			(2		)	37
Cash provided by (used in) financing activities	1,161			(973		)	27
Cash flows — investing activities:
Capital expenditures	(631		)	(530		)	(796		)
Nuclear fuel purchases	(213		)	(132		)	(106		)
Notes due from affiliates	926			346			(503		)
Purchase of right to use certain computer-related assets from parent (Note 3)	(38		)	—			—
Proceeds from sales of assets	2			49			141
Reduction of restricted cash related to TCEH Letter of Credit Facility (Note 8)	—			188			—
Other changes in restricted cash	129			(96		)	(33		)
Proceeds from sales of environmental allowances and credits	—			10			12
Purchases of environmental allowances and credits	(25		)	(17		)	(30		)
Proceeds from sales of nuclear decommissioning trust fund securities	106			2,419			974
Investments in nuclear decommissioning trust fund securities	(122		)	(2,436		)	(990		)
Other, net	—			9			(7		)
Cash provided by (used in) investing activities	134			(190		)	(1,338		)
Net change in cash and cash equivalents	1,055			73			(54		)
Effect of consolidation of VIE	—			—			7
Cash and cash equivalents — beginning balance	120			47			94
Cash and cash equivalents — ending balance	$	1,175		$	120		$	47

See Notes to Financial Statements.

83

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY CONSOLIDATED BALANCE SHEETS
	December 31,
	2012		2011
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	1,175	$	120
Restricted cash (Note 16)	—		129
Trade accounts receivable — net (includes $445 and $524 in pledged amounts related to a VIE (Notes 2 and 7))	710		760
Notes receivable from parent (Note 15)	698		670
Inventories (Note 16)	393		418
Commodity and other derivative contractual assets (Note 12)	1,463		2,883
Margin deposits related to commodity positions	71		56
Other current assets	120		59
Total current assets	4,630		5,095
Restricted cash (Note 16)	947		947
Notes receivable from parent (Note 15)	—		922
Investments (Note 16)	710		629
Property, plant and equipment — net (Note 16)	18,556		19,218
Goodwill (Note 3)	4,952		6,152
Identifiable intangible assets — net (Note 3)	1,781		1,826
Commodity and other derivative contractual assets (Note 12)	586		1,552
Other noncurrent assets, primarily unamortized debt amendment and issuance costs	811		999
Total assets	$	32,973	$	37,340
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (includes $82 and $104 related to a VIE (Notes 2 and 8))	$	2,136	$	774
Advances from parent	—		7
Long-term debt due currently (Note 8)	96		39
Trade accounts payable	389		553
Trade accounts and other payables to affiliates	139		209
Notes payable to parent (Note 15)	81		57
Commodity and other derivative contractual liabilities (Note 12)	894		1,784
Margin deposits related to commodity positions	600		1,061
Accumulated deferred income taxes (Note 5)	49		53
Accrued income taxes payable to parent (Note 15)	31		74
Accrued taxes other than income	17		136
Accrued interest	407		394
Other current liabilities	255		266
Total current liabilities	5,094		5,407
Accumulated deferred income taxes (Note 5)	3,759		4,712
Commodity and other derivative contractual liabilities (Note 12)	1,556		1,692
Notes or other liabilities due to affiliates (Note 15)	5		138
Long-term debt held by affiliates (Note 15)	382		382
Long-term debt, less amounts due currently (Note 8)	29,928		30,076
Other noncurrent liabilities and deferred credits (Note 16)	2,643		2,649
Total liabilities	43,367		45,056
Commitments and Contingencies (Note 9)
Equity (Note 10):

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ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY CONSOLIDATED BALANCE SHEETS
	December 31,
	2012			2011
	(millions of dollars)
Class A common stock (shares outstanding - both periods 2,062,768)	383			368
Class B common stock (shares outstanding - both periods 39,192,594)	7,282			6,983
Retained deficit	(18,129		)	(15,121		)
Accumulated other comprehensive loss	(42		)	(49		)
EFCH shareholder's equity	(10,506		)	(7,819		)
Noncontrolling interests in subsidiaries	112			103
Total equity	(10,394		)	(7,716		)
Total liabilities and equity	$	32,973		$	37,340

See Notes to Financial Statements

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ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY STATEMENTS OF CONSOLIDATED EQUITY (Millions of Dollars)
	Year Ended December 31,
	2012			2011			2010
Class A common stock without par value — authorized shares — 9,000,000:
Balance at beginning of period	368			358			283
Effects of debt push-down from EFH Corp. (Note 8)	15			10			75
Balance at end of period (shares outstanding for all periods presented — 2,062,768)	383			368			358
Class B common stock without par value — authorized shares — 171,000,000:
Balance at beginning of period	6,983			6,793			5,368
Effects of debt push-down from EFH Corp. (Note 8)	293			184			1,417
Effects of stock-based incentive compensation plans	4			6			8
Gain on settlement of reimbursement agreement with Oncor	2			—			—
Balance at end of period (shares outstanding for all periods presented — 39,192,594)	7,282			6,983			6,793
Retained deficit:
Balance at beginning of period	(15,121		)	(13,319		)	(9,790		)
Net loss attributable to EFCH	(3,008		)	(1,802		)	(3,530		)
Other	—			—			1
Balance at end of period	(18,129		)	(15,121		)	(13,319		)
Accumulated other comprehensive loss, net of tax effects (a):
Balance at beginning of period	(49		)	(68		)	(127		)
Change during the period	7			19			59
Balance at end of period	(42		)	(49		)	(68		)
EFCH shareholder's equity at end of period	(10,506		)	(7,819		)	(6,236		)
Noncontrolling interests in subsidiaries (Note 10):
Balance at beginning of period	103			87			48
Effect of consolidation of TXU Receivables Company	—			—			7
Investment in subsidiary by noncontrolling interests	7			16			32
Other	2			—			—
Noncontrolling interests in subsidiaries at end of period	112			103			87
Total equity at end of period	$	(10,394	)	$	(7,716	)	$	(6,149	)

_________________

(a) All amounts relate to cash flow hedges.

See Notes to Financial Statements.

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ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

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. We conduct our operations almost entirely through our wholly-owned subsidiary, TCEH. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities and retail electricity sales. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently, there are no reportable business segments.

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

Liquidity Considerations

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

Note 8 provides the details of EFCH's and its consolidated subsidiaries' short-term borrowings and long-term debt, including principal amounts and maturity dates, as well as details of recent debt activity, including the three-year extension of the portion of the TCEH Revolving Credit Facility that would have expired in 2013. At December 31, 2012, TCEH had $1.2 billion of cash and cash equivalents and $183 million of available capacity under its letter of credit facility. Based on the current forecast of cash from operating activities, which reflects current forward market electricity prices, projected capital expenditures and other cash flows, including the settlement of the TCEH Demand Notes by EFH Corp., we expect that TCEH will have sufficient liquidity to meets its obligations until October 2014, at which time a total of $3.8 billion of the TCEH Term Loan Facilities matures. TCEH's ability to satisfy this obligation is dependent upon the implementation of one or more of the actions described immediately below.

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

Basis of Presentation

The consolidated financial statements have been prepared in accordance with US GAAP. See Note 7 for discussion of the prospective adoption, effective January 1, 2010, of 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 reported as short-term borrowings and the prospective adoption of amended guidance that required reconsideration of consolidation conclusions for all variable interest entities (VIEs) that resulted in the consolidation, effective January 1, 2010 of TXU Receivables Company. 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.

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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.

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 11 and 12 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, 2012 and 2011, 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 8).

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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.

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. As part of ERCOT's transition to a nodal wholesale market effective December 1, 2010, volumes under nontrading bilateral purchase and sales contracts, including contracts intended as hedges, are no longer scheduled as physical power with ERCOT. Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, effective with the nodal market implementation, 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. As a result of the changes in wholesale market operations, effective with the nodal market implementation, if volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues, 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 3 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 3 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 3 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations and goodwill impairments recorded in 2012, 2010 and 2009.

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.

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Defined Benefit Pension Plans and OPEB Plans

We bear a portion of the costs of the EFH Corp. sponsored pension and OPEB plans offering pension benefits based on either a traditional defined benefit formula or a cash balance formula to eligible employees and also offering certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company. 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 13 for additional information regarding pension and OPEB plans, including a discussion of amendments to the EFH Corp. pension plan approved in August 2012.

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 14 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 federal income tax return; 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 5.

We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 4.

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 9 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, 2012, $947 million of cash was restricted to support letters of credit. See Notes 8 and 16 for more details regarding restricted cash.

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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 16.

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. The obligation is initially measured at fair value. 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 16.

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 16.

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 6 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 16 for discussion of these and other investments.

Noncontrolling Interests

See Note 10 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 and EFH Corp. Senior Secured Notes on our balance sheet 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 8).

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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.

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2. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. Accounting standards require consolidation of a VIE if we have (a) the power to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (primary beneficiary). 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.

Consolidated VIEs

See discussion in Note 7 regarding the VIE related to our accounts receivable securitization program that is consolidated under the accounting standards because TCEH owns and controls TXU Energy (the primary beneficiary of TXU Energy Receivables Company). We consolidated the previous program, which was terminated in November 2012, under the accounting standards because TCEH (as the owner of TXU Energy) was the primary beneficiary of TXU Receivables Company, which is owned and controlled by our parent, EFH Corp.

We also consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existing Comanche Peak nuclear-fueled generation facility using MHI's US-Advanced Pressurized Water Reactor technology and to obtain a combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries of TCEH and MHI that hold 88% and 12% of CPNPC's equity interests, respectively (see Note 10).

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

Assets:	December 31, 2012		December 31, 2011		Liabilities:	December 31, 2012		December 31, 2011
Cash and cash equivalents	$	43	$	10	Short-term borrowings	$	82	$	104
Accounts receivable	445		525		Trade accounts payable	1		1
Property, plant and equipment	134		132		Other current liabilities	7		9
Other assets, including $12 million and $2 million of current assets	16		6
Total assets	$	638	$	673	Total liabilities	$	90	$	114

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.

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3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides information regarding our goodwill balance. There were no changes to the goodwill balance for the year ended December 31, 2011. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges	$	18,322
Accumulated impairment charges through 2011 (a)	(12,170		)
Balance at December 31, 2011	6,152
Additional impairment charge in 2012	(1,200		)
Balance at December 31, 2012 (b)	$	4,952

___________

(a) Includes $4.1 billion recorded in 2010 and $8.070 billion largely recorded in 2008 as described below.

(b) Net of accumulated impairment charges totaling $13.370 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.

Because our analyses indicate that the carrying value of TCEH exceeds its estimated fair value (enterprise value), 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 (December 1 for annual testing) 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.

Changes in circumstances that we monitor closely include trends in natural gas prices. 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, declining natural gas prices, which we have experienced since mid-2008, negatively impact our profitability and cash flows and reduce the value of our generation assets, which consist largely of lignite/coal and nuclear-fueled facilities. While we have mitigated these effects with hedging activities, we are significantly exposed to this price risk. This market condition increases the risk of a goodwill impairment.

Key inputs into our goodwill impairment testing at December 1, 2012 were as follows.

• The carrying value (excluding debt) of TCEH exceeded its estimated enterprise value by approximately 40%.

• 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 9.25%. 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 assume rising wholesale electricity prices, though the forecasted electricity prices are 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.

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In the fourth quarter 2012, we recorded a $1.2 billion noncash goodwill impairment charge. This amount represents our best estimate of impairment pending finalization of the fair value calculations, which is expected in the first quarter 2013. The impairment charge reflected a decline in the estimated enterprise value of TCEH. The decline was due largely to lower wholesale electricity prices, reflecting the sustained decline in natural gas prices, and the maturing of positions in our natural gas hedge program, as reflected in our cash flow projections, as well as declines in market values of securities of comparable companies. The impairment test was based upon values at the December 1, 2012 test date.

In the third quarter 2010, we recorded a $4.1 billion noncash goodwill impairment charge. The impairment charge reflected a decline in the estimated enterprise value of TCEH. The decline was due largely to lower wholesale electricity prices, reflecting the sustained decline in natural gas prices, as reflected in our cash flow projections, as well as declines in market values of securities of comparable companies. The impairment test was based upon values as of the July 31, 2010 test date.

In the first quarter 2009, we completed the fair value calculations supporting a $8.070 billion goodwill impairment charge, substantially all of which was recorded in 2008. This charge was the first goodwill impairment recorded subsequent to the Merger date.

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, debt yields, 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 11). Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

Identifiable Intangible Assets

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

	December 31, 2012						December 31, 2011
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	378	$	85	$	463	$	344	$	119
Favorable purchase and sales contracts	552		314		238		548		288		260
Software and other computer-related assets	320		112		208		241		79		162
Environmental allowances and credits (a)	594		393		201		582		375		207
Mining development costs	163		82		81		140		55		85
Total intangible assets subject to amortization	$	2,092	$	1,279	813		$	1,974	$	1,141	833
Retail trade name (not subject to amortization)					955						955
Mineral interests (not currently subject to amortization) (b)					13						38
Total intangible assets					$	1,781					$	1,826

___________

(a) See discussion below regarding impairment of emission allowance intangible assets reported in other deductions in the third quarter 2011 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 11).

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

Identifiable Intangible Asset	Income Statement Line	Useful lives at December 31, 2012 (weighted average in years)	Year Ended December 31,
			2012		2011		2010
Retail customer relationship	Depreciation and amortization	5	$	34	$	51	$	78
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	11	25		31		35
Software and other computer-related assets	Depreciation and amortization	5	34		29		23
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	25	18		71		92
Mining development costs	Depreciation and amortization	3	27		38		11
Total amortization expense			$	138	$	220	$	239

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 16).

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

Year	Estimated Amortization Expense
2013	$	130
2014	$	113
2015	$	102
2016	$	84
2017	$	66

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Cross-State Air Pollution Rule Issued by the EPA

In July 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 in July 2011, we determined it would be necessary to idle two of our lignite/coal-fueled generation units at our Monticello facility by the end of 2011, switch the fuel we use at three lignite/coal-fueled generation units from a blend of Texas lignite and Wyoming Powder River Basin coal to 100 percent Powder River Basin coal, cease lignite mining operations that serve our Big Brown and Monticello generation facilities in the first quarter 2012 and construct upgraded scrubbers at five of our lignite/coal-fueled generation units. The action plan to cease operations at the mines required an evaluation of the remaining useful lives and recoverability of recorded values of tangible and intangible assets related to the mines. This evaluation resulted in the recording of accelerated depreciation and amortization expense in the third and fourth quarters of 2011 related to mine assets totaling $44 million. Also, in the third quarter 2011, we recorded asset impairments totaling $9 million related to capital projects in progress at the mines.

Additionally, because of emissions allowance limitations under the CSAPR, we would have 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 11. 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 the third quarter 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 October 2007.

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 August 2012 decision to vacate the CSAPR and remand it to the EPA for further proceedings (see Note 9), we did not idle the two Monticello generation units at the end of 2011 and have continued mining lignite at the mines that serve the Big Brown and Monticello generation facilities.

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4. 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, but the tax years 1997 to 2006 remain in appeals with the IRS, with closing agreements reached on such appeals for tax years 1997 to 2002 currently under review by the IRS Joint Committee. 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 2002.

The EFH Corp. IRS audit for the years 2003 through 2006 was concluded in June 2011. A significant number of proposed adjustments are in appeals with the IRS. The results of the audit did not affect management's assessment of issues for purposes of determining the liability for uncertain tax positions.

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, and a benefit of $8 million in 2010 (all amounts after tax).

Noncurrent liabilities included a total of $172 million and $151 million in accrued interest at December 31, 2012 and 2011, 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, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
Balance at January 1, excluding interest and penalties	$	1,069		$	931		$	903
Additions based on tax positions related to prior years	19			80			26
Reductions based on tax positions related to prior years	(33		)	(6		)	(70		)
Additions based on tax positions related to the current year	23			64			72
Balance at December 31, excluding interest and penalties	$	1,078		$	1,069		$	931

Of the balance at December 31, 2012, $1.010 billion 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 $68 million, and accrued interest would be reversed resulting in a $11 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.

98

5. 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 bound by 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.

The components of our income tax expense (benefit) are as follows:

	Year Ended December 31,
	2012			2011			2010
Current:
US Federal	$	(7	)	$	125		$	(254	)
State	35			48			39
Total current	28			173			(215		)
Deferred:
US Federal	(932		)	(1,120		)	521
State	(20		)	4			12
Total deferred	(952		)	(1,116		)	533
Total	$	(924	)	$	(943	)	$	318

Reconciliation of income taxes computed at the US federal statutory rate to income tax expense:

	Year Ended December 31,
	2012			2011			2010
Loss before income taxes	$	(3,932	)	$	(2,745	)	$	(3,212	)
Income taxes at the US federal statutory rate of 35%	$	(1,376	)	$	(961	)	$	(1,124	)
Nondeductible goodwill impairment	420			—			1,435
Texas margin tax, net of federal benefit	9			33			31
Lignite depletion allowance	(19		)	(23		)	(21		)
Production activities deduction	—			(20		)	—
Interest accrued for uncertain tax positions, net of tax	14			15			(8		)
Nondeductible interest expense	20			14			9
Reversal of previously disallowed interest resulting from debt exchanges	—			(1		)	(13		)
Other	8			—			9
Income tax expense (benefit)	$	(924	)	$	(943	)	$	318
Effective tax rate	23.5		%	34.4		%	(9.9		)%

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Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2012 and 2011 are as follows:

	December 31, 2012						December 31, 2011
	Total		Current		Noncurrent		Total		Current		Noncurrent
Deferred Income Tax Assets
Alternative minimum tax credit carryforwards	$	222	$	—	$	222	$	231	$	—	$	231
Net operating loss (NOL) carryforwards	428		—		428		76		—		76
Unfavorable purchase and sales contracts	221		—		221		231		—		231
Debt extinguishment gains	749		—		749		748		—		748
Employee benefit obligations	42		—		42		50		—		50
Accrued interest	235		—		235		184		—		184
Other	130		—		130		246		—		246
Total	2,027		—		2,027		1,766		—		1,766
Deferred Income Tax Liabilities
Property, plant and equipment	4,353		—		4,353		4,286		—		4,286
Commodity contracts and interest rate swaps	729		31		698		1,373		31		1,342
Identifiable intangible assets	522		—		522		619		—		619
Debt fair value discounts	213		—		213		217		—		217
Other	18		18		—		36		22		14
Total	5,835		49		5,786		6,531		53		6,478
Net Deferred Income Tax Liability	$	3,808	$	49	$	3,759	$	4,765	$	53	$	4,712

At December 31, 2012, we had $222 million of alternative minimum tax credit carryforwards (AMT) available to offset future tax payments. The AMT credit carryforwards have no expiration date. At December 31, 2012, we had net operating loss (NOL) carryforwards for federal income tax purposes of $1.223 billion that expire between 2028 and 2033. The NOL carryforwards can be used to offset future taxable income. We expect to utilize all of our NOL carryforwards prior to their expiration dates.

The income tax effects of the components included in accumulated other comprehensive income at December 31, 2012 and 2011 totaled a net deferred tax asset of $23 million and $26 million, respectively.

See Note 4 for discussion regarding accounting for uncertain tax positions.

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6. OTHER INCOME AND DEDUCTIONS

	Year Ended December 31
	2012		2011		2010
Other income:
Consent fee related to novation of hedge positions between counterparties	$	6	$	—	$	—
Insurance/litigation settlements	2		—		3
Sales tax refunds	—		5		5
Debt extinguishment gains	—		—		687
Settlement of counterparty bankruptcy claims (a)	—		21		—
Property damage claim	—		7		—
Franchise tax refund	—		6		—
Gain on termination of long-term power sales contract (b)	—		—		116
Gain on sale of land/water rights	—		—		44
Gain on sale of interest in natural gas gathering pipeline business	—		—		37
All other	5		9		11
Total other income	$	13	$	48	$	903
Other deductions:
Charges related to pension plan actions (Note 13)	$	141	$	—	$	—
Impairment of mineral interests (Note 3)	24		—		—
Other asset impairments	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 8)	1		86		—
Impairment of emission allowances (Note 3) (c)	—		418		—
Impairment of assets related to mining operations (c)	—		9		—
Other	9		11		18
Total other deductions	$	188	$	524	$	18

____________

(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) In November 2010, the counterparty to a long-term power sales agreement terminated the contract, which had a remaining term of 27 years. The contract was a derivative and subject to mark-to-market accounting. The termination resulted in a noncash gain of $116 million, which represented the derivative liability as of the termination date.

(c) 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 (see Note 3).

101

7. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

In November 2012, TCEH entered into a new accounts receivable securitization program, and EFH Corp. terminated the previous program. Upon termination of the program, TXU Energy repurchased receivables previously sold and then sold them to TXU Energy Receivables Company, a new entity that is described below. Except as noted below, the new program is substantially the same as the terminated program.

Under the program, TXU Energy (originator) sells all of its trade accounts receivable to TXU Energy Receivables Company, which is an entity created for the special purpose of purchasing receivables from the originator and is a consolidated, wholly-owned, bankruptcy-remote subsidiary of TCEH. TXU Energy Receivables Company borrows funds from entities established for this purpose by the participating financial institutions (funding entities) using the accounts receivable as collateral. A direct subsidiary of EFH Corp. with similar characteristics performed these functions under the terminated program by selling undivided interests in the purchased accounts receivable to the funding entities.

The trade accounts receivable amounts under the program are reported in the financial statements as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the program activity was accounted for as a sale of accounts receivable, under accounting rules then applicable to the program, which resulted in the funding being recorded as a reduction of accounts receivable.

The maximum funding amount currently available under the program is $200 million, which approximates the expected usage and applies only to receivables related to non-executory retail sales contracts, as compared to $350 million under the terminated program. Program funding decreased to $82 million at December 31, 2012 from $104 million at December 31, 2011. Because TCEH's credit ratings were lower than Ba3/BB-, under the terms of the program, available funding is reduced by the amount of customer deposits held by the originator, which totaled $36 million at December 31, 2012.

TXU Energy Receivables Company issues a subordinated note payable to the originator for the difference between the face amount of the accounts receivable purchased, less a discount, and cash paid to the originator. Because the subordinated note is limited to 25% of the uncollected accounts receivable purchased, and the amount of borrowings are limited by terms of the financing agreement, any additional funding to purchase the receivables is sourced from cash on hand and/or capital contributions from TCEH. Under the program, the subordinated note issued by TXU Energy Receivables Company is subordinated to the security interests of the funding entities. There was no subordinated note limit under the terminated program. The balance of the subordinated note payable, which is eliminated in consolidation, totaled $97 million and $420 million at December 31, 2012 and December 31, 2011, respectively.

All new trade receivables under the program generated by the originator are continuously purchased by TXU Energy Receivables Company with the proceeds from collections of receivables previously purchased and, as necessary, increased borrowings or funding sources as described immediately above. Changes in the amount of borrowings by TXU Energy Receivables Company reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes.

The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees consist primarily of interest costs on the underlying financing and are reported as interest expense and related charges. The discount also funds a servicing fee, which is reported as SG&A expense, paid by TXU Energy Receivables Company to TXU Energy, which provides recordkeeping services and is the collection agent under the program.

Program fee amounts were as follows:

	Year Ended December 31,
	2012	2011	2010
Program fees	$9	$9	$10
Program fees as a percentage of average funding (annualized)	6.7%	6.4%	3.8%

102

Activities of TXU Energy Receivables Company and TXU Receivables Company were as follows:

	Year Ended December 31,
	2012			2011			2010
Cash collections on accounts receivable	$	4,566		$	5,080		$	6,334
Face amount of new receivables purchased	(4,496		)	(4,992		)	(6,100		)
Discount from face amount of purchased receivables	11			11			12
Program fees paid to funding entities	(9		)	(9		)	(10		)
Servicing fees paid for recordkeeping and collection services	(2		)	(2		)	(2		)
Increase (decrease) in subordinated notes payable	(323		)	(96		)	53
Capital contribution from TCEH, net of cash held	275			—			—
Cash flows used by (provided to) originator under the program	$	22		$	(8	)	$	287

Under the previous accounting rules, changes in funding under the program were reported as operating cash flows. The accounting rules effective January 1, 2010 required that the amount of funding under the program as of the adoption date ($383 million) be reported as a use of operating cash flows and a source of financing cash flows, with all subsequent changes in funding reported as financing activities.

The new program extends the expiration date by two years to November 2015, provided that the expiration date will change to June 2014 if at that time more than $500 million aggregate principal amount of the term loans and deposit letter of credit loans under the TCEH Senior Secured Facilities maturing prior to October 2017 remain outstanding. The new program is subject to the same financial maintenance covenant as the TCEH Senior Credit Facilities as discussed in Note 8. The program may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days outstanding ratio exceed stated thresholds, unless the funding entities waive such events of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Energy Receivables Company defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if EFH Corp., TCEH, any affiliate of TCEH acting as collection agent, any parent guarantor of the originator or the originator defaults in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. At December 31, 2012, there were no such events of termination.

If the program was terminated, TCEH's liquidity would be reduced because collections of sold receivables would be used by TXU Energy Receivables Company to repay borrowings from the funding entities instead of purchasing new receivables. We expect that the level of cash flows would normalize in approximately 16 to 30 days following termination.

Trade Accounts Receivable

	December 31,
	2012			2011
Wholesale and retail trade accounts receivable, including $454 and $524 in pledged retail receivables	$	719		$	787
Allowance for uncollectible accounts	(9		)	(27		)
Trade accounts receivable — reported in balance sheet	$	710		$	760

Gross trade accounts receivable at December 31, 2012 and 2011 included unbilled revenues of $260 million and $269 million, respectively.

103

Allowance for Uncollectible Accounts Receivable

	Year Ended December 31,
	2012			2011			2010
Allowance for uncollectible accounts receivable at beginning of period	$	27		$	64		$	81
Increase for bad debt expense	26			56			108
Decrease for account write-offs	(44		)	(67		)	(125		)
Reversal of reserve related to counterparty bankruptcy (Note 6)	—			(26		)	—
Allowance for uncollectible accounts receivable at end of period	$	9		$	27		$	64

104

8. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At December 31, 2012, outstanding short-term borrowings totaled $2.136 billion, which included $2.054 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.40%, excluding customary fees, and $82 million under the accounts receivable securitization program discussed in Note 7.

At December 31, 2011, outstanding short-term borrowings totaled $774 million, which included $670 million under the TCEH Revolving Credit Facility at a weighted average interest rate of 4.46%, excluding certain customary fees, and $104 million under the accounts receivable securitization program.

Credit Facilities

Credit facilities with cash borrowing and/or letter of credit availability at December 31, 2012 are presented below. The facilities are all senior secured facilities of TCEH.

		December 31, 2012
Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)	October 2013	$	645	$	—	$	645	$	—
TCEH Revolving Credit Facility (a)	October 2016	1,409		—		1,409		—
TCEH Letter of Credit Facility (b)	October 2017 (b)	1,062		—		1,062		—
Total TCEH		$	3,116	$	—	$	3,116	$	—

___________

(a) Facility used for borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. At December 31, 2012, borrowings under the facility maturing October 2013 bear interest at LIBOR plus 3.50%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility. At December 31, 2012, borrowings under the facility maturing October 2016 bear interest at LIBOR plus 4.50%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 1.00% of the average daily unused portion of the facility. In January 2013, commitments maturing in 2013 were extended to 2016 as discussed below.

(b) Facility, $42 million of which matures in October 2014, used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not secured by a first-lien interest in the assets of TCEH. The borrowings under this facility have been recorded by TCEH as restricted cash that supports issuances of letters of credit and are classified as long-term debt. At December 31, 2012, the restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009 related to an office building financing. At December 31, 2012, the restricted cash supports $764 million in letters of credit outstanding, leaving $183 million in available letter of credit capacity.

Amendment and Extension of TCEH Revolving Credit Facility — In January 2013, the Credit Agreement governing the TCEH Senior Secured Facilities was amended to extend the maturity date of the $645 million of commitments maturing in October 2013 to October 2016, bringing the maturity date of the entire commitment of $2.054 billion to October 2016. The extended commitments will 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 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.

105

Long-Term Debt

At December 31, 2012 and 2011, long-term debt consisted of the following:

	December 31,
	2012			2011
TCEH
Senior Secured Facilities:
3.746% TCEH Term Loan Facilities maturing October 10, 2014 (a)(b)	$	3,809		$	3,809
3.712% TCEH Letter of Credit Facility maturing October 10, 2014 (b)	42			42
4.746% TCEH Term Loan Facilities maturing October 10, 2017 (a)(b)(c)	15,370			15,370
4.712% TCEH Letter of Credit Facility maturing October 10, 2017 (b)	1,020			1,020
11.5% Fixed Senior Secured Notes due October 1, 2020	1,750			1,750
15% Fixed Senior Secured Second Lien Notes due April 1, 2021	336			336
15% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B	1,235			1,235
10.25% Fixed Senior Notes due November 1, 2015 (c)	2,046			2,046
10.25% Fixed Senior Notes due November 1, 2015, Series B (c)	1,442			1,442
10.50 / 11.25% Senior Toggle Notes due November 1, 2016	1,749			1,568
Pollution Control Revenue Bonds:
Brazos River Authority:
5.40% Fixed Series 1994A due May 1, 2029	39			39
7.70% Fixed Series 1999A due April 1, 2033	111			111
6.75% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (e)	16			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
0.143% Floating Series 2001D-2 due May 1, 2033 (f)	97			97
0.400% Floating Taxable Series 2001I due December 1, 2036 (g)	62			62
0.143% Floating Series 2002A due May 1, 2037 (f)	45			45
6.75% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (e)	44			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 (e)	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 (h)	(112		)	(120		)
Other:
7.46% Fixed Secured Facility Bonds with amortizing payments through January 2015	12			28
7% Fixed Senior Notes due March 15, 2013	5			5
Capital leases	64			63
Other	3			3
Unamortized discount	(10		)	(11		)
Unamortized fair value discount (h)	(1		)	(1		)
Total TCEH	29,880			29,705

106

	December 31,
	2012			2011
EFCH (parent entity)
9.58% Fixed Notes due in annual installments through December 4, 2019 (i)	35			41
8.254% Fixed Notes due in quarterly installments through December 31, 2021 (i)	39			43
1.113% 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 (h)	(7		)	(8		)
Subtotal	76			85
EFH Corp. debt pushed down (j)
10% Fixed Senior Secured First Lien Notes due January 15, 2020	330			330
9.75% Fixed Senior Secured First Lien Notes due October 15, 2019	58			58
10.875% Fixed Senior Notes due November 1, 2017	32			98
11.25 / 12.00% Senior Toggle Notes due November 1, 2017	30			218
Unamortized premium	—			3
Subtotal — EFH Corp. debt pushed down	450			707
Total EFCH (parent entity)	526			792
Total EFCH consolidated	30,406			30,497
Less amount due currently	(96		)	(39		)
Less amount held by affiliates (Note 15)	(382		)	(382		)
Total long-term debt	$	29,928		$	30,076

____________

(a) Interest rate swapped to fixed on $18.46 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, 2012.

(c) As discussed below and in Note 15, principal amounts of notes/term loans totaling $382 million at both December 31, 2012 and 2011 were held by EFH Corp. and EFIH.

(d) Interest rate in effect at December 31, 2012, excluding a quarterly maintenance fee of $11 million. See "Credit Facilities" above for more information.

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

(f) Interest rates in effect at December 31, 2012. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(g) Interest rate in effect at December 31, 2012. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

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

(i) 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.

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

Debt Amounts Due Currently

Amounts due currently (within twelve months) at December 31, 2012 total $96 million and consist of $60 million principal amount of TCEH pollution control revenue bonds (PCRBs) subject to mandatory tender and remarketing in April 2013, which we expect to repurchase in April 2013, and $36 million of scheduled installment payments on capital leases and debt securities.

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Debt Related Activity in 2013

Issuance of EFIH 10% Senior Secured Notes and EFIH 11.25%/12.25% Toggle Notes in Exchange for EFH Corp. Debt Guaranteed by EFCH -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) 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 applicable to certain amendments to the respective indentures governing such 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) 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.

Largely in early 2013, EFIH returned $6.518 billion principal amount of EFH Corp. debt guaranteed by EFCH that EFIH received in debt exchanges as a dividend to EFH Corp., which cancelled it. The debt returned included $1.754 billion principal amount of EFH Corp. 10.875% Notes, $3.593 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.

After these early 2013 transactions, EFCH guarantees only $60 million principal amount of EFH Corp. debt as discussed below in “Guarantees and Push Down of EFH Corp. Debt.”

Debt Related Activity in 2012

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.”

Debt Related Activity in 2011

Issuances of debt for cash in 2011 consisted of the $1.750 billion principal amount of TCEH 11.5% Senior Secured Notes discussed below (net proceeds of $1.703 billion).

Repayments of long-term debt in 2011 totaled $1.408 billion and included $958 million of long-term debt borrowings under the TCEH Senior Secured Facilities as discussed below, $437 million of principal payments at scheduled maturity or remarketing dates (including $415 million of pollution control revenue bonds) and $13 million of contractual payments under capitalized lease obligations. In addition, short-term borrowings of $455 million under the TCEH Revolving Credit Facility were repaid.

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Amendment and Extension ofTCEH Senior Secured Facilities —Borrowings under the TCEH Senior Secured Facilities totaled $22.295 billion at December 31, 2012 and consisted of:

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

• $15.370 billion of TCEH Term Loan Facilities maturing in October 2017 with interest payable at LIBOR plus 4.50%;

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

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

• Amounts borrowed under the TCEH Revolving Credit Facility, which may be reborrowed from time to time until October 2016 and represent the entire amount of commitments under the facility totaling $2.054 billion at December 31, 2012. See "Credit Facilities" above for discussion regarding the $645 million in commitments maturing in 2013 that were extended to 2016 in January 2013.

The TCEH Commodity Collateral Posting Facility, under which there were no borrowings in 2012, matured in December 2012.

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

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

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

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

• not to make any further loans to EFH Corp. under the SG&A Note (at December 31, 2012, the outstanding balance of the SG&A Note was $233 million, reflecting the repayment discussed below);

• that borrowings outstanding under the P&I Note will not exceed $2.0 billion in the aggregate at any time (at December 31, 2012, the outstanding balance of the P&I Note was $465 million), and

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

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

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

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

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Pursuant to the extension of the TCEH Senior Secured Facilitiesin April 2011:

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

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

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

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

Each of the loans described above that matures in 2016 or 2017 includes a "springing maturity" provision pursuant to which (i) in the event that more than $500 million aggregate principal amount of the TCEH 10.25% Notes due in 2015 (other than notes held by EFH Corp. or its controlled affiliates at March 31, 2011 to the extent held at the determination date as defined in the Credit Agreement) or more than $150 million aggregate principal amount of the TCEH Toggle Notes due in 2016 (other than notes held by EFH Corp. or its controlled affiliates at March 31, 2011 to the extent held at the determination date as defined in the Credit Agreement), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (ii) TCEH's total debt to Adjusted EBITDA ratio (as defined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at the applicable determination date, then the maturity date of the extended loans will automatically change to 90 days prior to the maturity date of the applicable notes.

Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH's available liquidity could be reduced by an amount up to the aggregate amount of such lender's commitments under the TCEH Senior Secured Facilities.

The TCEH Senior Secured Facilities are fully and unconditionally guaranteed jointly and severally on a senior secured basis by EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US subsidiary of TCEH. The TCEH Senior Secured Facilities, along with the TCEH Senior Secured Notes and certain commodity hedging transactions and the interest rate swaps described under "TCEH Interest Rate Swap Transactions" below, are secured on a first priority basis by (i) substantially all of the current and future assets of TCEH and TCEH's subsidiaries who are guarantors of such facilities and (ii) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

The TCEH Senior Secured Facilities contain customary negative covenants that, among other things, restrict, subject to certain exceptions, TCEH and its restricted subsidiaries' ability to:

• incur additional debt;

• create additional liens;

• enter into mergers and consolidations;

• sell or otherwise dispose of assets;

• make dividends, redemptions or other distributions in respect of capital stock;

• make acquisitions, investments, loans and advances, and

• pay or modify certain subordinated and other material debt.

The TCEH Senior Secured Facilities contain certain customary events of default for senior leveraged acquisition financings, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.

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Accounting and Income Tax Effects of the Amendment and Extension— Based on application of the accounting rules, including analyses of discounted cash flows, the amendment and extension transactions were determined not to be an extinguishment of debt. Accordingly, no gain was recognized, and transaction costs totaling $699 million, consisting of consent and extension payments to loan holders, were capitalized. Amounts capitalized will be amortized to interest expense through the maturity dates of the respective loans. Net third party fees related to the amendment and extension totaling $86 million were expensed (see Note 6).

The transactions were determined to be a significant modification of debt for federal income tax purposes, resulting in taxable cancellation of debt income of approximately $2.5 billion. The income will be reversed as deductions in future years (through 2017), and consequently a deferred tax asset has been recorded. The effect of the income on federal income taxes payable related to 2011 was largely offset by current year deductions, including the impact of bonus depreciation, and utilization of approximately $660 million in operating loss carryforwards. The transactions resulted in a cash charge under the Texas margin tax of $13 million (reported as income tax expense).

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

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

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

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

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

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

October 2011 EFH Corp. Debt Exchange — In a private exchange in October 2011, EFH Corp. issued $53 million principal amount of new EFH Corp. Toggle Notes in exchange for $65 million principal amount of EFH Corp. 5.55% Notes. The new EFH Corp. Toggle Notes, which were subject to push down to our balance sheet, had substantially the same terms and conditions and were subject to the same indenture as the existing EFH Corp. Toggle Notes. A premium totaling $6 million was recorded on the transaction and was being amortized to interest expense over the life of the new notes until the notes were acquired in the December 2012 debt exchanges discussed above. Concurrent with the exchange, EFIH returned $53 million principal amount of EFH Corp. Toggle Notes that it had received in prior debt exchange transactions as a dividend to EFH Corp., which cancelled the notes.

2011 EFH Corp. Debt Repurchases — In the fourth quarter 2011, EFH Corp. repurchased $40 million principal amount of TCEH 10.25% Notes due 2015 and $7 million principal amount of EFH Corp. 5.55% Notes in private transactions for $20 million in cash. EFH Corp. retired the 5.55% Notes and held the TCEH 10.25% Notes as an investment.

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Maturities

Long-term debt maturities at December 31, 2012 are as follows:

Year
2013 (a)	$	84
2014 (a)	3,933
2015 (a)	3,659
2016 (a)	1,919
2017 (a) (b)	16,115
Thereafter (a)	4,762
Unamortized discounts (c)	(130		)
Capital lease obligations	64
Total	$	30,406

___________

(a) Long-term debt maturities for EFCH (parent entity), including pushed down debt, total $11 million, $12 million, $13 million, $15 million, $69 million and $413 million for 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.

(b) TCEH Senior Secured Facilities due in 2017 are subject to a "springing maturity" provision as discussed above.

(c) Unamortized fair value discounts for EFCH (parent entity) total $7 million.

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

The amount reflected in our balance sheet as pushed down debt ($450 million and $707 million at December 31, 2012 and 2011, respectively, as shown in the long-term debt table above) represents 50% of the principal amount (plus unamortized premium) of the EFH Corp. Merger-related debt guaranteed by EFCH (parent entity). This percentage reflects the fact that at the time of the Merger, the equity investments of EFCH (parent entity) and EFIH in their respective operating subsidiaries were essentially equal amounts. Because payment of principal and interest on the debt is the responsibility of EFH Corp., we record the settlement of such amounts as noncash capital contributions from EFH Corp.

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The tables below present, at December 31, 2012 and 2011, an analysis of the total outstanding principal amount of EFH Corp. debt that EFCH (parent entity) and EFIH have guaranteed (fully and unconditionally on a joint and several basis), as (i) amounts that EFIH held as an investment, (ii) amounts held by nonaffiliates subject to push down to our balance sheet and (iii) amounts held by nonaffiliates that are not Merger-related. As discussed in note (a) to the December 31, 2012 table below, as a result of transactions in early 2013, debt guaranteed now totals only $60 million. The guarantee is not secured.

December 31, 2012
Securities Guaranteed (principal amounts)	Held by EFIH		Subject to Push Down		Not Merger-Related		Total Guaranteed
EFH Corp. 9.75% and 10% Senior Secured Notes	$	—	$	776	$	400	$	1,176
EFH Corp. 10.875% Senior Notes	1,685		64		—		1,749
EFH Corp. 11.25/12.00% Senior Toggle Notes	3,441		60		—		3,501
Subtotal	$	5,126	$	900	$	400	6,426
TCEH Demand Notes (Note 15)							698
Total							$	7,124

____________

(a) As a result of transactions completed in early 2013, the $5.126 billion principal amount of EFH Corp. Senior Notes were returned by EFIH as a dividend to EFH Corp., which cancelled them, substantially all of the $1.176 billion principal amount of EFH Corp. Senior Secured Notes have been cancelled, $64 million of the $124 million principal amount of EFH Corp. Senior Notes subject to push down have been cancelled and the TCEH Demand Notes have been settled (see Note 15).

December 31, 2011
Securities Guaranteed (principal amounts)	Held by EFIH		Subject to Push Down		Not Merger-Related		Total Guaranteed
EFH Corp. 9.75% and 10% Senior Secured Notes	$	—	$	776	$	400	$	1,176
EFH Corp. 10.875% Senior Notes	1,591		196		—		1,787
EFH Corp. 11.25/12.00% Senior Toggle Notes	2,784		438		—		3,222
Subtotal	$	4,375	$	1,410	$	400	6,185
TCEH Demand Notes (Note 15)							1,592
Total							$	7,777

Information Regarding Other Significant Outstanding Debt

TCEH 11.5% Senior Secured Notes —At December 31, 2012, the principal amount of the TCEH 11.5% Senior Secured Notes totaled $1.750 billion. The notes mature in October 2020, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1, at a fixed rate of 11.5% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The notes are secured, on a first-priority basis, by security interests in all of the assets of TCEH, and the guarantees are secured on a first-priority basis by all of the assets and equity interests held by the Guarantors, in each case, to the extent such assets and equity interests secure obligations under the TCEH Senior Secured Facilities (the TCEH Collateral), subject to certain exceptions and permitted liens.

The notes are (i) senior obligations and rank equally in right of payment with all senior indebtedness of TCEH, (ii) senior in right of payment to all existing or future unsecured and second-priority secured debt of TCEH to the extent of the value of the TCEH Collateral and (iii) senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

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.

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

• make restricted payments, including certain investments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets, and

• engage in certain transactions with affiliates.

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

Until April 1, 2014, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the TCEH Senior Secured Notes from time to time at a redemption price of 111.5% of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEH may redeem the notes at any time prior to April 1, 2016 at a price equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. TCEH may also redeem the notes, in whole or in part, at any time on or after April 1, 2016, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture), TCEH must offer to repurchase the notes at 101% of their principal amount, plus accrued interest.

TCEH 15% Senior Secured Second Lien Notes(including Series B)— At December 31 2012, the principal amount of the TCEH 15% Senior Secured Second Lien Notes totaled $1.571 billion. These notes mature in April 2021, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1 at a fixed rate of 15% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH that guarantees the TCEH Senior Secured Facilities. The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Facilities on a first-priority basis, subject to certain exceptions (including the elimination of the pledge of equity interests of any Subsidiary Guarantor to the extent that separate financial statements would be required to be filed with the SEC for such Subsidiary Guarantor under Rule 3-16 of Regulation S-X) and permitted liens. The guarantee from EFCH is not secured.

The notes are senior obligations of the issuer and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH's obligations under the TCEH Senior Secured Facilities, the TCEH Senior Secured Notes and TCEH's commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

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.

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

• make restricted payments, including certain investments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets, and

• engage in certain transactions with affiliates.

The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes when due. In general, all of the series of TCEH Senior Secured Second Lien Notes vote together as a single class. As a result, if certain events of default occur under the indenture, the trustee or the holders of at least 30% of aggregate principal amount of all outstanding TCEH Senior Secured Second Lien Notes may declare the principal amount on all such notes to be due and payable immediately.

Until October 1, 2013, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of each series of the TCEH Senior Secured Second Lien Notes from time to time at a redemption price of 115.00% of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEH may redeem each series of the notes at any time prior to October 1, 2015 at a price equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. TCEH may also redeem each series of the notes, in whole or in part, at any time on or after October 1, 2015, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture), TCEH must offer to repurchase each series of the notes at 101% of their principal amount, plus accrued interest.

TCEH 10.25% Senior Notes (including Series B) and 10.50/11.25% Senior Toggle Notes (collectively, the TCEH Senior Notes)— At December 31, 2012, the principal amount of the TCEH Senior Notes totaled $5.237 billion, including $363 million aggregate principal amount held by EFH Corp. and EFIH, and the notes are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH's direct parent, EFCH (which owns 100% of TCEH), and by each subsidiary that guarantees the TCEH Senior Secured Facilities. The TCEH 10.25% Notes mature in November 2015, with interest payable in cash semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.25% per annum. The TCEH Toggle Notes mature in November 2016, with interest payable semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK Interest, which option expired with the November 1, 2012 interest payment.

TCEH may redeem the TCEH 10.25% Notes and TCEH Toggle Notes, in whole or in part, at any time, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFCH or TCEH, TCEH must offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

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

• make restricted payments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets, and

• engage in certain transactions with affiliates.

The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under the indenture, the trustee or the holders of at least 30% in principal amount of the notes may declare the principal amount on the notes to be due and payable immediately.

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

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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 issue 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 will rank 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 will be 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 will 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.

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) will 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 will be 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 will not be 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 will control enforcement actions with respect to such collateral, and the holders of the Second Lien Obligations will not be 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 will 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 Long-Term Debt

At December 31, 2012 and 2011, the estimated fair value of our long-term debt (excluding capital leases) totaled $17.858 billion and $18.740 billion, respectively, and the carrying amount totaled $30.342 billion and $30.434 billion, respectively. At December 31, 2012, the estimated fair value of our short-term borrowings under the TCEH Revolving Credit Facilities totaled $1.500 billion and the carrying amount totaled $2.054 billion. We determine fair value in accordance with accounting standards as discussed in Note 11, and at December 31, 2012, our debt fair value represents Level 2 valuations. We obtain security pricing from a vendor who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.

TCEHInterest Rate Swap Transactions

TCEH employs interest rate swaps to hedge exposure to its variable rate debt. As reflected in the table below, at December 31, 2012, 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%	February 2013 through October 2014		$	18.46	billion (a)
6.8	%	-	9.0%	October 2015 through October 2017		$	12.60	billion (b)

___________

(a) Swaps related to an aggregate $2.6 billion principal amount of debt expired in 2012. Per the terms of the transactions, the notional amount of swaps entered into in 2011 grew by $2.405 billion, 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.

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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, 2012 totaled $11.967 billion notional amount, a decrease of $5.783 billion from December 31, 2011 reflecting both new and expired swaps. The basis swaps relate to debt outstanding through 2014.

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

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

	Year Ended December 31,
	2012			2011			2010
Realized net loss	$	(670	)	$	(684	)	$	(673	)
Unrealized net gain (loss)	166			(812		)	(207		)
Total	$	(504	)	$	(1,496	)	$	(880	)

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.065 billion and $2.231 billion at December 31, 2012 and 2011, respectively, of which $65 million and $76 million (both pretax), respectively, were reported in accumulated other comprehensive income.

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9. COMMITMENTS AND CONTINGENCIES

Contractual Commitments

At December 31, 2012, 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		Capacity payments under electricity purchase agreements (a)		Nuclear Fuel Contracts		Other Contracts
2013	$	432	$	31	$	99	$	158	$	130
2014	308		29		—		116		43
2015	292		12		—		167		26
2016	123		—		—		124		26
2017	43		—		—		110		24
Thereafter	44		—		—		645		119
Total	$	1,242	$	72	$	99	$	1,320	$	368

___________

(a) On the basis of current expectations of demand from electricity customers as compared with capacity and take-or-pay payments, management does not consider it likely that any material payments will become due for electricity not taken beyond capacity payments.

Expenditures under our coal purchase and coal transportation agreements totaled $245 million, $463 million and $445 million for the years ended December 31, 2012, 2011 and 2010, respectively.

At December 31, 2012, future minimum lease payments under both capital leases and operating leases are as follows:

	Capital Leases		Operating Leases (a)
2013	$	14	$	42
2014	10		43
2015	7		36
2016	6		46
2017	35		36
Thereafter	—		169
Total future minimum lease payments	72		$	372
Less amounts representing interest	8
Present value of future minimum lease payments	64
Less current portion	12
Long-term capital lease obligation	$	52

___________

(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 $72 million, $66 million and $89 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Guarantees

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

See Note 8 for discussion of guarantees and security for certain of our debt and EFCH guarantees of certain EFH Corp. debt.

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Letters of Credit

At December 31, 2012, TCEH had outstanding letters of credit under its credit facilities totaling $764 million as follows:

• $376 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions and collateral postings with ERCOT;

• $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);

• $71 million to support TCEH's REP financial requirements with the PUCT, and

• $109 million for miscellaneous credit support requirements.

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. Oral argument was held in this administrative appeal on October 23, 2012, and the 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. While we cannot predict the timing or outcome of this proceeding, we believe the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and were in accordance with applicable law.

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

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

Regulatory Reviews

In June 2008, the EPA issued an initial request for information to TCEH under the EPA's authority under Section 114 of the CAA. The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. 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. While we cannot predict whether the EPA will initiate enforcement proceedings under the notice of violation, we believe that we have complied with all requirements of the CAA at all of our generation facilities. We cannot predict the outcome of any resulting enforcement proceedings or estimate the penalties that might be assessed in connection with any such proceedings. In September 2012, we filed a petition for review in the United States Court of Appeals for 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, if any, is held. We cannot predict the outcome of these proceedings, including the financial effects, if any.

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Cross-State Air Pollution Rule (CSAPR)

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

In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule. In April 2012, we filed in the D.C. Circuit Court a petition for review of the Final Revisions on the ground, among others, that the rules do not include all of the budget corrections we requested from the EPA. The parties to the case have 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, a three judge panel of 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. The EPA and the other parties have approximately 90 days to appeal the D.C. Circuit Court's decision to the US Supreme Court. We cannot predict whether any such appeals will be filed.

State Implementation Plan (SIP)

In September 2010, the EPA disapproved a portion of the State Implementation Plan pursuant to which the TCEQ implements its program to achieve the requirements of the Clean Air Act. The EPA disapproved the Texas standard permit for pollution control projects. We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. We challenged the EPA's disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit (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 pollution control projects and remanded the matter to the EPA for reconsideration. We cannot predict the timing or outcome of the EPA's reconsideration, including the financial effects, if any.

In November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacing that exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generation facility-specific permit conditions. We, like many other electricity generation facility operators in Texas, have asserted applicability of the exemption or affirmative defense, and the TCEQ has not objected to that assertion. We have also applied for and received the generation facility-specific permit amendments. We challenged the EPA's disapproval by filing a lawsuit in the Fifth Circuit Court arguing that the TCEQ's adoption of the affirmative defense and phase-out of that affirmative defense as permits are issued is consistent with the 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 original opinion and issued a new 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 new expanded opinion. Other parties to the proceedings also filed a petition with the Fifth Circuit Court asking the panel to reconsider its decision. We cannot predict the timing or outcome of this matter, 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.

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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 CO2 and 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). Also in November 2011, a four-year labor agreement was reached covering bargaining unit personnel engaged in natural gas-fueled generation operations. In October 2010, two-year labor agreements were reached covering bargaining unit personnel engaged in the Sandow lignite-fueled generation operations and the Three Oaks lignite mining operations, and although the term of these agreements have now expired, we are currently negotiating new labor agreements for the Sandow operations and Three Oaks Mine and are operating under the terms of the existing agreements for these two facilities. In August 2010, a three-year labor agreement 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. The liability coverage is governed by the Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage are promulgated by the rules and regulations of the NRC. 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.

With regard to liability coverage, the Act provides 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 $12.5 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 $12.5 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), which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).

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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 $117.5 million plus a 3% insurance premium tax, subject to increases for inflation every five years. Assessments are limited to $17.5 million per operating licensed reactor per year per incident. The company's maximum potential assessment under the industry retrospective plan would be $235 million (excluding taxes) per incident but no more than $35 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. The SFP and liability coverage are not subject to any deductibles.

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 $500 million provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company and $1.25 billion of premature decommissioning coverage also provided by NEIL. The European Mutual Association for Nuclear Insurance 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 losses exceeded its reserves for the applicable coverage, potential assessments in the form of a retrospective premium call could be made up to ten times annual premiums. 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.

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10. EQUITY

Cash Distributions to Parent

We paid no cash distributions to EFH Corp. in 2012, 2011 or 2010.

Dividend Restrictions

While EFCH has no contractual dividend restrictions, the TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash distribution on their common stock unless at the time, and after giving effect to such distribution, TCEH's consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. At December 31, 2012, the ratio was 8.5 to 1.0.

In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and TCEH Senior Secured Second Lien Notes generally restrict TCEH's ability to make distributions or loans to any of its parent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and the indentures governing such notes.

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

Noncontrolling Interests

As discussed in Note 2, we consolidate a joint venture formed in 2009 for the purpose of developing two new nuclear generation units, which results in a noncontrolling interests component of equity. As discussed in Notes 2 and 7, 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, 2011 and 2010.

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11. FAIR VALUE MEASUREMENTS

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

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

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

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

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

Our valuation policies and procedures are developed, maintained and validated by 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 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 swap valuation models utilizing month-end interest rate curves.

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

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

	December 31, 2011
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	395	$	3,915	$	124	$	1	$	4,435
Nuclear decommissioning trust – equity securities (c)	208		124		—		—		332
Nuclear decommissioning trust – debt securities (c)	—		242		—		—		242
Total assets	$	603	$	4,281	$	124	$	1	$	5,009
Liabilities:
Commodity contracts	$	446	$	727	$	71	$	1	$	1,245
Interest rate swaps	—		2,231		—		—		2,231
Total liabilities	$	446	$	2,958	$	71	$	1	$	3,476

 _______________

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

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

(c) The nuclear decommissioning trust investment is included in the investments line in the balance sheet. See Note 16.

In conjunction with ERCOT's transition to a nodal wholesale market structure effective December 2010, we have entered into certain derivative transactions (primarily congestion revenue rights transactions) that are valued at illiquid pricing locations (unobservable inputs), thus requiring classification as Level 3 assets or liabilities.

Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated "normal" purchases or sales. See Note 12 for further discussion regarding the company's use of derivative instruments.

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Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 8 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, 2012, 2011 and 2010. 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, 2012, 2011 and 2010.

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

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

____________

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

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

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

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

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

(f) Based on historical forward price changes.

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

(h) Based on the historical price differences between settlement points in ERCOT North 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.

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The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
Net asset balance at beginning of period	$	53		$	342		$	81
Total unrealized valuation gains (losses)	(17		)	(1		)	266
Purchases, issuances and settlements (a):
Purchases	73			117			68
Issuances	(23		)	(15		)	(31		)
Settlements	(12		)	(41		)	(11		)
Transfers into Level 3 (b)	(42		)	—			(12		)
Transfers out of Level 3 (b)	(3		)	(349		)	(19		)
Net change (c)	(24		)	(289		)	261
Net asset balance at end of period	$	29		$	53		$	342
Unrealized valuation gains (losses) relating to instruments held at end of period	(24		)	17			111

____________

(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 for 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 from commodity hedging and trading activities, except in 2010, a gain of $116 million on the termination of a long-term power sales contract is reported in other income in the income statement. Activity excludes changes in fair value in the month the position settled as well as amounts related to positions entered into and settled in the same month.

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12. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a commodity hedging program and the hedging of interest costs on our long-term debt. See Note 11 for a discussion of the fair value of all derivatives.

Natural Gas Price Hedging Program — TCEH has a natural gas price hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2014. These transactions are intended to hedge a portion of electricity price exposure related to expected lignite/coal- and nuclear-fueled generation for this period. Unrealized gains and losses arising from changes in the fair value of the instruments under the program as well as realized gains and losses upon settlement of the instruments are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in the income statement in interest expense and related charges. See Note 8 for additional information about interest rate swap agreements.

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

Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported in the balance sheets at December 31, 2012 and 2011:

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	)

December 31, 2011
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	2,883		$	—	$	—		$	—		$	2,883
Noncurrent assets	1,552			—		—			—			1,552
Current liabilities	(1		)	—		(1,162		)	(621		)	(1,784		)
Noncurrent liabilities	—			—		(82		)	(1,610		)	(1,692		)
Net assets (liabilities)	$	4,434		$	—	$	(1,244	)	$	(2,231	)	$	959

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At December 31, 2012 and 2011, there were no derivative positions accounted for as cash flow or fair value hedges.

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $568 million and $1.006 billion in net liabilities at December 31, 2012 and 2011, respectively. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

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

	Year Ended December 31,
Derivative (income statement presentation)	2012			2011			2010
Commodity contracts (Net gain from commodity hedging and trading activities) (a)	$	279		$	1,139		$	2,162
Commodity contracts (Other income) (b)	—			—			116
Interest rate swaps (Interest expense and related charges) (c)	(504		)	(1,496		)	(880		)
Net gain (loss)	$	(225	)	$	(357	)	$	1,398

_______________

(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) Represents a noncash gain on termination of a long-term power sales contract (see Note 6).

(c) 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 16).

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, 2012, 2011 or 2010.

Derivative type (income statement presentation of loss reclassified	Year Ended December 31,
from accumulated OCI into income)	2012			2011			2010
Interest rate swaps (interest expense and related charges)	$	(8	)	$	(27	)	$	(87	)
Interest rate swaps (depreciation and amortization)	(2		)	(2		)	(2		)
Commodity contracts (operating revenues)	—			—			(1		)
Total	$	(10	)	$	(29	)	$	(90	)

There were no transactions designated as cash flow hedges during the years ended December 31, 2012, 2011 or 2010.

Accumulated other comprehensive income related to cash flow hedges at December 31, 2012 and 2011 totaled $42 million and $49 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $6 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income at December 31, 2012 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

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Derivative Volumes — The following table presents the gross notional amounts of derivative volumes at December 31, 2012 and 2011:

	December 31,
	2012		2011
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed (a)	$	31,060	$	31,255	Million US dollars
Basis (b)	$	11,967	$	19,167	Million US dollars
Natural gas:
Natural gas price hedge forward sales and purchases (c)	875		1,602		Million MMBtu
Locational basis swaps	495		728		Million MMBtu
All other	1,549		841		Million MMBtu
Electricity	76,767		105,673		GWh
Congestion Revenue Rights (d)	111,185		142,301		GWh
Coal	13		23		Million tons
Fuel oil	47		51		Million gallons
Uranium	441		480		Thousand pounds

_______________

(a) Includes notional amount of interest rate swaps maturing between February 2013 and October 2014 as well as notional amount of swaps effective from October 2014 with maturity dates through October 2017 (see Note 8).

(b) The December 31, 2011 amount includes $1.417 billion notional amount of swaps entered into but not effective until February 2012.

(c) Represents gross notional forward sales, purchases and options transactions in the natural gas price hedging program. The net amount of these transactions was approximately 360 million MMBtu and 700 million MMBtu at December 31, 2012 and 2011, respectively.

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

Credit Risk-Related Contingent Features of Derivatives

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

At December 31, 2012 and 2011, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $58 million and $364 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $12 million and $78 million at December 31, 2012 and 2011, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, at December 31, 2012, there were no remaining liquidity requirements, and at December 31, 2011 the remaining related liquidity requirement would have totaled $7 million after reduction for net accounts receivable and derivative assets under netting arrangements.

In addition, certain derivative agreements that are collateralized primarily with liens on certain of our assets include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. At December 31, 2012 and 2011, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $2.150 billion and $2.651 billion, respectively, before consideration of the amount of assets subject to the liens. No cash collateral or letters of credit were posted with these counterparties at December 31, 2012 or 2011 to reduce the liquidity exposure. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered at December 31, 2012 and 2011, the remaining related liquidity requirement after reduction for derivative assets under netting arrangements but before consideration of the amount of assets subject to the liens would have totaled $1.122 billion and $1.160 billion, respectively. See Note 8 for a description of other obligations that are supported by liens on certain of our assets.

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As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.208 billion and $3.015 billion at December 31, 2012 and 2011, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets subject to related liens.

Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

Concentrations of Credit Risk Related to Derivatives

TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. At December 31, 2012, total credit risk exposure to all counterparties related to derivative contracts totaled $2.139 billion (including associated accounts receivable). The net exposure to those counterparties totaled $255 million at December 31, 2012 after taking into effect netting arrangements, setoff provisions and collateral. At December 31, 2012, the credit risk exposure to the banking and financial sector represented 92% of the total credit risk exposure and 52% of the net exposure, a significant amount of which is related to the natural gas price hedging program, and the largest net exposure to a single counterparty totaled $50 million.

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

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

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

Pension Plan

Our subsidiaries are participating employers in the EFH Retirement Plan (the Plan), a defined benefit pension plan sponsored by EFH Corp. The 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 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. Since October 1, 2007, all new employees, with the exception of employees hired by Oncor, have not been eligible to participate in the Plan. It is EFH Corp.'s policy to fund the Plan to the extent deductible under existing federal tax regulations.

In August 2012, EFH Corp. approved certain amendments to the Plan. 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;

• splitting off assets and liabilities under the Plan associated with active employees of EFH Corp.'s competitive businesses, other than collective bargaining unit (union) employees, to a Terminating Plan, freezing benefits and vesting all accrued plan benefits for these participants;

• the termination of, distributions of benefits under, and settlement of all of EFH Corp.'s liabilities under the Terminating Plan, and

• maintaining assets and liabilities associated with union employees of EFH Corp.'s competitive businesses under the Plan.

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

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 are being 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 2012 and expects to settle the remaining $50 million with EFH Corp. in the first quarter 2013.

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.

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Pension and OPEB Costs Recognized as Expense

The following details net pension and OPEB costs recognized as expense. The pension and OPEB amounts provided represent allocations to us of amounts related to EFH Corp.'s plans.

	Year Ended December 31,
	2012		2011		2010
Pension costs (a)	$	178	$	38	$	28
OPEB costs	1		14		11
Total benefit costs recognized as expense	$	179	$	52	$	39

____________

(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 of 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 Plan was 37% in 2012 and zero percent in each of the years ended December 31, 2011 and 2010. The 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 assumed for pension costs was 5.00% for January through July 2012, 4.15% for August through September 2012, 4.20% for October through December 2012 and 5.50% and 5.90% for the years ended December 31, 2011 and 2010, respectively. The discount rate assumed for OPEB costs was 4.95%, 5.55% and 5.90% for the years ended December 31, 2012, 2011 and 2010, respectively. The expected rate of return on plan assets reflected in the 2012 cost amounts is 7.4% and 6.8% for the pension plan assets and OPEB assets, respectively.

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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 16% 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 for employees who are not covered by the Retirement Plan or who are covered under the Cash Balance Formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the Traditional Retirement Plan Formula of the Retirement Plan. 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 $19 million, $18 million and $17 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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14. 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.

Our stock-based compensation expense recorded for the years ended December 31, 2012, 2011 and 2010 was as follows:

	Year Ended December 31,
Type of award	2012			2011			2010
Restricted stock units granted to employees	$	3		$	2		$	—
Stock options granted to employees	2			4			9
Other share and share-based awards	(1		)	(1		)	(2		)
Total compensation expense	$	4		$	5		$	7

Restricted Stock Units — Restricted stock unit activity for our employees in 2012 consisted of grants of 1.4 million units and forfeitures of 0.2 million units. Restricted stock unit activity in 2011 consisted of the issuance of 11.2 million units in exchange for stock options as discussed below, grants of 2.2 million units and forfeitures of 0.4 million 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, 2012, there was approximately $7.5 million of unrecognized compensation expense related to nonvested restricted stock units expected to be recognized by us through September 2014.

Stock Options — No options were granted to employees in 2012 or 2011. Options to purchase 0.2 million shares of EFH Corp. common stock were granted to certain of our management employees in 2010. The exercise period for vested awards was 10 years from grant date. The options initially provided the holder the right to purchase EFH Corp. common stock for $5.00 per share. The terms of the options were fixed at grant date. One-half of the options initially granted 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. The stock option expense presented in the table above relates to Time-Based Options except for $1.6 million in 2010 related to Performance-Based Options.

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.

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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 and the assumptions noted in the table below. 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.

The weighted average grant-date fair value of the Time-Based Options granted in 2010 was $1.36 per option.

Assumptions supporting the fair values were as follows:

	Year Ended December 31, 2010
Assumptions:	Time-Based Options
Expected volatility	35%
Expected annual dividend	—
Expected life (in years)	6.8
Risk-free rate	2.99%

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, 2012, 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.

137

A summary of Time-Based Options activity 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)	—		$	—

Time-Based Options Activity in 2010:	Options (millions)		Weighted Average Exercise Price
Total outstanding at beginning of period	20.0		$	4.34
Granted	0.2		$	2.18
Exercised	—		$	—
Forfeited	(1.5	)	$	4.59
Total outstanding at end of period (weighted average remaining term of 7 - 10 years)	18.7		$	4.30
Exercisable at end of period (weighted average remaining term of 7 - 10 years)	(2.5	)	$	4.77
Expected forfeitures	(0.1	)	$	5.00
Expected to vest at end of period (weighted average remaining term of 7 - 10 years)	16.1		$	4.22

	2011				2010
Nonvested Time-Based Options Activity:	Options (millions)		Grant-Date Fair Value		Options (millions)		Grant-Date Fair Value
Total nonvested at beginning of period	11.7		$	1.55	15.5		$	1.63
Granted	—		$	—	0.2		$	1.36
Vested	—		$	—	(2.5	)	$	1.92
Forfeited	—		$	—	(1.5	)	$	1.72
Exchanged	(11.7	)	$	1.55	—		$	—
Total nonvested at end of period	—		$	—	11.7		$	1.55

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, 2012, 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. A total of 2.4 million of the 2008 and 0.9 million of the 2009 Performance-Based Options had vested.

138

A summary of Performance-Based Options activity 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)	—		$	—

Performance-Based Options Activity in 2010:	Options (millions)		Weighted Average Exercise Price
Outstanding at beginning of period	4.9		$	5.00
Granted	—		$	—
Exercised	—		$	—
Forfeited	(1.1	)	$	5.00
Exchanged	—		$	—
Total outstanding at end of period (weighted average remaining term of 7 - 10 years)	3.8		$	5.00
Exercisable at end of period (weighted average remaining term of 7 - 10 years)	(0.9	)	$	5.00
Expected forfeitures	—		$	—
Expected to vest at end of period (weighted average remaining term of 7 - 10 years)	2.9		$	5.00

	2011							2010
Performance-Based Nonvested Options Activity:	Options (millions)		Grant-Date Fair Value					Options (millions)		Grant-Date Fair Value
Total nonvested at beginning of period	0.5		$	1.16	-	$	2.01	2.5		$	1.16	-	$	2.01
Granted	—		—		-	—		—		—		-	—
Vested	—		—		-	—		(0.9	)	$	1.77	-	$	1.87
Forfeited	—		—		-	—		(1.1	)	$	1.65	-	$	1.87
Exchanged	(0.5	)	$	1.16	-	$	2.01	—		—		-	—
Total nonvested at end of period	—		$	1.16	-	$	2.01	0.5		$	1.16	-	$	2.01

139

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. The deferred share awards are fully vested and 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. No expense was recognized in 2012 or 2011. Expenses recognized in 2010 related to these grants totaled $0.1 million. The deferred share awards are accounted for as liability awards; therefore, the effects of changes in 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 2012, 2011 and 2010 was reduced by $1.0 million, $1.0 million and $1.9 million, respectively.

140

15. RELATED-PARTY TRANSACTIONS

The following represent our significant related-party transactions.

• TCEH's retail operations pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services totaled $1.0 billion, $1.0 billion and $1.1 billion for the years ended December 31, 2012, 2011 and 2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at December 31, 2012 and 2011 reflect amounts due currently to Oncor totaling $53 million and $138 million, respectively, (included in trade accounts and other payables to affiliates) primarily 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. The note balance at the August 2012 settlement date totaled $159 million. TCEH's payments on the note totaled $20 million, $39 million and $37 million for the years ended December 31, 2012, 2011 and 2010, 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 totaled $16 million, $32 million and $37 million for the years ended December 31, 2012, 2011 and 2010, respectively.

• Notes receivable from EFH Corp. are payable to TCEH on demand (TCEH Demand Notes) and arise from cash loaned for debt principal and interest payments and other general corporate purposes of EFH Corp. At December 31, 2012 and 2011, the notes consisted of:

	December 31,
	2012		2011
Note related to debt principal and interest payments (P&I Note)	$	465	$	1,359
Note related to general corporate purposes (SG&A Note)	233		233
Total	$	698	$	1,592

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 discussed in Note 8, $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. The average daily balance of the TCEH Demand Notes totaled $789 million, $1.542 billion and $1.588 billion for the years ended December 31, 2012, 2011 and 2010, 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 $42 million, $82 million and $85 million for the years ended December 31, 2012, 2011 and 2010, respectively. In January 2013, EFH Corp. repaid the balance of the TCEH Demand Notes.

141

• TCEH had a demand note payable to EFH Corp. totaling $770 million for the period January to April 2011 and for the period February to December 2010. 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 and $644 million for the years ended December 2011 and 2010, respectively. 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 and $25 million for the years ended December 31, 2011 and 2010, respectively. In addition, EFCH has a demand note payable to EFH Corp., the proceeds from which were used to repay outstanding debt. The note totaled $81 million and $57 million at December 31, 2012 and 2011, respectively, and carried interest at a rate based on the one-month LIBOR rate plus 5.00%. Interest expense related to this note totaled $3 million, $2 million and $1 million for the years ended December 31, 2012, 2011 and 2010, 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, 2012 and 2011, 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 $265 million, $213 million and $193 million for the years ended December 31, 2012, 2011 and 2010, respectively. Effective in 2012, TCEH reimburses a subsidiary of EFH Corp. for an allocated share of computer equipment purchased by the subsidiary. Amounts paid by TCEH in 2012 included existing computer equipment and totaled $38 million, which was accounted for as an intangible asset to be amortized over the life of the equipment. Previously, the depreciation of such equipment was included in the administrative cost billings.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to TCEH for contribution in 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, $17 million and $16 million for the years ended December 31, 2012, 2011 and 2010, 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, 2012 and 2011, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $284 million and $225 million, respectively, included in other noncurrent liabilities in our balance sheet.

• EFH Corp. files consolidated federal income tax and Texas state margin tax returns that include our results; however, under a tax sharing agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if we file our own corporate income tax return. As a result, we had income taxes payable to EFH Corp. of $31 million and $74 million at December 31, 2012 and 2011, respectively. We made income tax net payments to EFH Corp. of $84 million, $123 million and $49 million for the years ended December 31, 2012, 2011 and 2010, respectively.

• Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at December 31, 2012 and 2011, TCEH had posted letters of credit in the amount of $11 million and $12 million, respectively, for the benefit of Oncor.

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

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

142

• 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 (see Note 8) 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 as follows (principal amounts):

	December 31,
	2012		2011
TCEH Senior Notes:
Held by EFH Corp.	$	284	$	284
Held by EFIH	79		79
TCEH Term Loan Facilities:
Held by EFH Corp.	19		19
Total	$	382	$	382

Interest expense on the notes totaled $38 million, $34 million and $30 million for the years ended December 31, 2012, 2011 and 2010, respectively.

See Notes 8 and 9 for guarantees and push-down of certain EFH Corp. debt and Note 13 for allocation of EFH Corp. pension and OPEB costs to us and amendments to the EFH Corp. pension plan in 2012.

143

16. SUPPLEMENTARY FINANCIAL INFORMATION

Interest Expense and Related Charges

	Year Ended December 31,
	2012			2011			2010
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	2,616		$	2,540		$	2,266
Interest related to pushed down debt	75			78			211
Accrued interest to be paid with additional toggle notes (Note 8)	152			166			217
Unrealized mark-to-market net (gain) loss on interest rate swaps	(166		)	812			207
Amortization of interest rate swap losses at dedesignation of hedge accounting	8			27			87
Amortization of fair value debt discounts resulting from purchase accounting	11			17			17
Amortization of debt issuance, amendment and extension costs and discounts	182			183			122
Capitalized interest	(36		)	(31		)	(60		)
Total interest expense and related charges	$	2,842		$	3,792		$	3,067

Restricted Cash

	December 31, 2012				December 31, 2011
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH's Letter of Credit Facility (Note 8)	$	—	$	947	$	—	$	947
Amounts related to margin deposits held	—		—		129		—
Total restricted cash	$	—	$	947	$	129	$	947

Inventories by Major Category

	December 31,
	2012		2011
Materials and supplies	$	201	$	177
Fuel stock	168		203
Natural gas in storage	24		38
Total inventories	$	393	$	418

Investments

	December 31,
	2012		2011
Nuclear plant decommissioning trust	$	654	$	574
Assets related to employee benefit plans, including employee savings programs, net of distributions	8		10
Land	41		41
Miscellaneous other	7		4
Total other investments	$	710	$	629

144

Nuclear Decommissioning Trust — Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding change in a receivable/payable that will ultimately be settled through changes in Oncor's delivery fees rates (see Note 15). A summary of investments in the fund follows:

	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

	December 31, 2011
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	231	$	13	$	(2	)	$	242
Equity securities (c)	230		121		(19		)	332
Total	$	461	$	134	$	(21	)	$	574

____________

(a) Includes realized gains and losses on securities sold.

(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.38% at both December 31, 2012 and 2011 and an average maturity of 6 years at both December 31, 2012 and 2011.

(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, 2012 mature as follows: $94 million in one to five years, $55 million in five to ten years and $112 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,
	2012			2011			2010
Realized gains	$	1		$	1		$	1
Realized losses	$	(2	)	$	(3	)	$	(2	)
Proceeds from sales of securities	$	106		$	2,419		$	974
Investments in securities	$	(122	)	$	(2,436	)	$	(990	)

Property, Plant and Equipment

	December 31,
	2012		2011
Generation and mining	$	23,144	$	22,607
Other assets	452		427
Total	23,596		23,034
Less accumulated depreciation	5,845		4,723
Net of accumulated depreciation	17,751		18,311
Construction work in progress	444		575
Nuclear fuel (net of accumulated amortization of $941 and $776)	361		320
Held for sale	—		12
Property, plant and equipment — net	$	18,556	$	19,218

145

Depreciation expense totaled $1.228 billion, $1.330 billion and $1.245 billion for the years ended December 31, 2012, 2011 and 2010, respectively.

Assets related to capital leases included above totaled $70 million and $67 million at December 31, 2012 and 2011, respectively, net of accumulated depreciation.

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, 2012 and 2011:

	Nuclear Plant Decommissioning		Mining Land Reclamation and Other			Total
Liability at January 1, 2011	$	329	$	164		$	493
Additions:
Accretion	19		29			48
Incremental reclamation costs (a)	—		67			67
Reductions:
Payments	—		(72		)	(72		)
Liability at December 31, 2011	$	348	$	188		$	536
Additions:
Accretion	20		37			57
Incremental reclamation costs (a)	—		36			36
Reductions:
Payments	—		(93		)	(93		)
Liability at December 31, 2012	368		168			536
Less amounts due currently	—		(84		)	(84		)
Noncurrent liability at December 31, 2012	$	368	$	84		$	452

____________

(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,
	2012		2011
Uncertain tax positions (including accrued interest)	$	1,250	$	1,220
Asset retirement and mining reclamation obligations	452		505
Unfavorable purchase and sales contracts	620		647
Nuclear decommissioning cost over-recovery (Note 15) (a)	284		225
Retirement plan and other employee benefits	28		44
Other	9		8
Total other noncurrent liabilities and deferred credits	$	2,643	$	2,649

____________

(a) Balance at December 31, 2011 was previously classified as a liability due to affiliates. Because Oncor only acts as collection agent to balance the amounts ultimately collected from its customers with the actual future cost to decommission the nuclear plant, the classification as a liability due Oncor was corrected.

146

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 $27 million, $26 million and $27 million for the years ended December 31, 2012, 2011 and 2010, respectively. See Note 3 for intangible assets related to favorable purchase and sales contracts.

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

Year	Amount
2013	$	26
2014	$	25
2015	$	25
2016	$	25
2017	$	25

Supplemental Cash Flow Information

	Year Ended December 31,
	2012			2011			2010
Cash payments (receipts) related to:
Interest paid (a)	$	2,569		$	2,469		$	2,269
Capitalized interest	(36		)	(31		)	(60		)
Interest paid (net of capitalized interest) (a)	$	2,533		$	2,438		$	2,209
Income taxes	$	84		$	123		$	49
Noncash investing and financing activities:
Effect of Parent's payment of interest and issuance of toggle notes as consideration for cash interest, net of tax, on pushed down debt	$	22		$	33		$	(99	)
Principal amount of TCEH Toggle Notes issued in lieu of cash interest	$	181		$	162		$	211
Construction expenditures (b)	$	46		$	62		$	83
Contribution related to EFH Corp. stock-based compensation	$	5		$	5		$	7
Effect of push down of debt from parent	$	(282	)	$	(167	)	$	(1,618	)
Debt exchange transactions	$	—		$	—		$	527
Gain on termination of long-term power sales contract (Note 6)	$	—		$	—		$	116

____________

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

(b) Represents end-of-period accruals.

147

17. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

At December 31, 2012 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 8). 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 10.

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, 2012, 2011 and 2010 and the condensed consolidating balance sheets at December 31, 2012 and December 31, 2011 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 $62 million and $319 million of the EFH Corp. Senior Notes to the Parent at December 31, 2012 and December 31, 2011, respectively, $388 million of the EFH Corp. Senior Secured Notes to the Parent at both December 31, 2012 and December 31, 2011, 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, 2012 and December 31, 2011 (see Note 8). TCEH Finance's sole function is to be the co-issuer of the certain TCEH debt securities; therefore, it has no other independent assets, liabilities or operations.

EFCH (parent entity) received no dividends/distributions from its consolidated subsidiaries for the years ended December 31, 2012, 2011 and 2010.

148

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Condensed 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	)

149

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Condensed 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	)

150

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Condensed Consolidating Statements of Income (Loss)

Year Ended December 31, 2010

(millions of dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	8,223		$	12		$	—		$	8,235
Fuel, purchased power costs and delivery fees	—			—			(4,371		)	—			—			(4,371		)
Net gain from commodity hedging and trading activities	—			1,373			788			—			—			2,161
Operating costs	—			—			(837		)	—			—			(837		)
Depreciation and amortization	—			—			(1,380		)	—			—			(1,380		)
Selling, general and administrative expenses	—			—			(718		)	(4		)	—			(722		)
Franchise and revenue-based taxes	—			—			(106		)	—			—			(106		)
Impairment of goodwill	—			(4,100		)	—			—			—			(4,100		)
Other income	—			727			176			—			—			903
Other deductions	—			—			(17		)	(1		)	—			(18		)
Interest income	1			388			454			—			(753		)	90
Interest expense and related charges	(231		)	(3,409		)	(1,867		)	(6		)	2,446			(3,067		)
Income (loss) before income taxes	(230		)	(5,021		)	345			1			1,693			(3,212		)
Income tax (expense) benefit	83			281			(91		)	—			(591		)	(318		)
Equity earnings (losses) of subsidiaries	(3,383		)	1,357			—			—			2,026			—
Net income (loss)	(3,530		)	(3,383		)	254			1			3,128			(3,530		)
Other comprehensive income	59			59			—			—			(59		)	59
Comprehensive income (loss)	$	(3,471	)	$	(3,324	)	$	254		$	1		$	3,069		$	(3,471	)

151

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Condensed 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

152

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Condensed 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

153

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Condensed Consolidating Statements of Cash Flows

Year Ended December 31, 2010

(millions of dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(22	)	$	(829	)	$	2,208		$	(100	)	$	—		$	1,257
Cash flows – financing activities:
Issuances of long-term debt	—			350			3			—			—			353
Repayments/repurchases of long-term debt	(8		)	(550		)	(89		)	—			—			(647		)
Net short-term borrowings under accounts receivable securitization program	—			—			—			96			—			96
Increase in other short-term borrowings	—			172			—			—			—			172
Notes/loans from affiliates	34			—			—			—			—			34
Advances from affiliates	(4		)	814			—			—			(810		)	—
Decrease in income tax-related note payable to Oncor	—			—			(37		)	—			—			(37		)
Contributions from noncontrolling interests	—			—			—			32			—			32
Debt discount, financing and reacquisition expenses	—			—			(13		)	—			—			(13		)
Other, net	—			—			37			—			—			37
Cash provided by (used in) financing activities	22			786			(99		)	128			(810		)	27
Cash flows – investing activities:
Net notes/loans to affiliates	—			—			(1,313		)	—			810			(503		)
Capital expenditures	—			—			(764		)	(32		)	—			(796		)
Nuclear fuel purchases	—			—			(106		)	—			—			(106		)
Proceeds from sales of assets	—			—			141			—			—			141
Proceeds from sales of environmental allowances and credits	—			—			12			—			—			12
Purchases of environmental allowances and credits	—			—			(30		)	—			—			(30		)
Changes in restricted cash	—			—			(33		)	—			—			(33		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			—			974			—			—			974
Investments in nuclear decommissioning trust fund securities	—			—			(990		)	—			—			(990		)
Other, net	—			(11		)	4			—			—			(7		)
Cash used in investing activities	—			(11		)	(2,105		)	(32		)	810			(1,338		)
Net change in cash and cash equivalents	—			(54		)	4			(4		)	—			(54		)
Effect of consolidation of VIE	—			—			—			7			—			7
Cash and cash equivalents – beginning balance	—			77			11			6			—			94
Cash and cash equivalents – ending balance	$	—		$	23		$	15		$	9		$	—		$	47

154

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY Condensed Consolidating Balance Sheets December 31, 2012 (millions of dollars)
	Parent Guarantor			Issuer		Other Guarantors		Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	1,115	$	15	$	45	$	—		$	1,175
Restricted cash	—			—		—		—		—			—
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
Notes receivable from parent	—			—		—		—		—			—
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

155

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY Condensed Consolidating Balance Sheets December 31, 2012 (millions of dollars)
	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors		Eliminations			Consolidated
Margin deposits related to commodity positions	—			596			4			—		—			600
Accumulated deferred income taxes	—			3			52			—		(6		)	49
Accrued income taxes payable to parent	2			433			—			6		(410		)	31
Accrued taxes other than income	—			—			17			—		—			17
Accrued interest	18			389			281			—		(281		)	407
Other current liabilities	1			4			253			—		(3		)	255
Total current liabilities	112			12,985			3,585			188		(11,776		)	5,094
Accumulated deferred income taxes	79			—			3,569			—		111			3,759
Commodity and other derivative contractual liabilities	—			1,539			17			—		—			1,556
Notes or other liabilities due affiliates	—			—			5			—		—			5
Long-term debt held by affiliate	—			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

156

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY Condensed Consolidating Balance Sheets December 31, 2011 (millions of dollars)
	Parent Guarantor			Issuer		Other Guarantors		Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	87	$	23	$	10	$	—		$	120
Restricted cash	—			—		129		—		—			129
Advances to affiliates	—			—		41		—		(41		)	—
Trade accounts receivable – net	—			4		651		525		(420		)	760
Notes receivable from parent	—			670		—		—		—			670
Income taxes receivable	11			85		—		—		(96		)	—
Accounts receivable from affiliates	—			9		—		—		(9		)	—
Inventories	—			—		418		—		—			418
Commodity and other derivative contractual assets	—			1,630		1,253		—		—			2,883
Accumulated deferred income taxes	3			—		—		—		(3		)	—
Margin deposits related to commodity positions	—			—		56		—		—			56
Other current assets	—			—		57		1		1			59
Total current assets	14			2,485		2,628		536		(568		)	5,095
Restricted cash	—			947		—		—		—			947
Investments	(6,860		)	22,903		663		—		(16,077		)	629
Property, plant and equipment – net	—			—		19,086		132		—			19,218
Notes receivable from parent	—			922		—		—		—			922
Advances to affiliates	—			—		8,785		—		(8,785		)	—
Goodwill	—			6,152		—		—		—			6,152
Identifiable intangible assets – net	—			—		1,826		—		—			1,826
Commodity and other derivative contractual assets	—			1,511		41		—		—			1,552
Accumulated deferred income taxes	—			294		—		1		(295		)	—
Other noncurrent assets, principally unamortized amendment/issuance costs	6			974		902		6		(889		)	999
Total assets	$	(6,840	)	$	36,188	$	33,931	$	675	$	(26,614	)	$	37,340
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	670	$	670	$	104	$	(670	)	$	774
Notes/advances from affiliates	10			8,816		—		7		(8,826		)	7
Long-term debt due currently	11			—		28		—		—			39
Trade accounts payable	—			—		552		421		(420		)	553
Trade accounts and other payables to affiliates	—			—		215		3		(9		)	209
Notes payable to parent/affiliate	57			—		—		—		—			57
Commodity and other derivative contractual liabilities	—			980		804		—		—			1,784

157

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY Condensed Consolidating Balance Sheets December 31, 2011 (millions of dollars)
	Parent Guarantor			Issuer			Other Guarantors			Non-guarantors		Eliminations			Consolidated
Margin deposits related to commodity positions	—			865			196			—		—			1,061
Accumulated deferred income taxes	—			4			52			—		(3		)	53
Accrued income taxes payable to parent	—			—			170			—		(96		)	74
Accrued taxes other than income	—			—			136			—		—			136
Accrued interest	24			369			258			—		(257		)	394
Other current liabilities	—			11			257			1		(3		)	266
Total current liabilities	102			11,715			3,338			536		(10,284		)	5,407
Accumulated deferred income taxes	82			—			4,124			—		506			4,712
Commodity and other derivative contractual liabilities	—			1,670			22			—		—			1,692
Notes or other liabilities due affiliates	—			—			138			—		—			138
Long-term debt held by affiliate	—			382			—			—		—			382
Long-term debt, less amounts due currently	782			29,230			28,672			—		(28,608		)	30,076
Other noncurrent liabilities and deferred credits	13			52			2,583			—		1			2,649
Total liabilities	979			43,049			38,877			536		(38,385		)	45,056
EFCH shareholder's equity	(7,819		)	(6,861		)	(4,946		)	36		11,771			(7,819		)
Noncontrolling interests in subsidiaries	—			—			—			103		—			103
Total equity	(7,819		)	(6,861		)	(4,946		)	139		11,771			(7,716		)
Total liabilities and equity	$	(6,840	)	$	36,188		$	33,931		$	675	$	(26,614	)	$	37,340

158

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 4.   CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect at December 31, 2012. 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.

159

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

MANAGEMENT'S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Energy Future Competitive Holdings Company 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'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 performed an evaluation as of December 31, 2012 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. Based on the review performed, management believes that as of December 31, 2012 Energy Future Competitive Holdings Company'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 has issued an attestation report on Energy Future Competitive Holdings Company'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                    and Chief Financial Officer

February 19, 2013

160

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Competitive Holdings Company

Dallas, Texas

We have audited the internal control over financial reporting of Energy Future Competitive Holdings Company (a subsidiary of Energy Future Holdings Corp.) and subsidiaries (“EFCH”) as of December 31, 2012 based on criteria established in Internal Control — Integrated Framework 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, 2012, based on the criteria established in Internal Control — Integrated Framework 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 as of and for the year ended December 31, 2012 of EFCH and our report dated February 19, 2013 expressed an unqualified opinion on those financial statements and included an emphasis of matter paragraph related to (1) EFCH's continued net losses, substantial indebtedness and significant cash interest requirements and EFCH's ability to satisfy its obligations in October 2014, which include the maturities of $3.8 billion of Texas Competitive Electric Holdings Company LLC ("TCEH") Term Loan Facilities, being dependent upon completion of one or more actions described in Note 1 to the consolidated financial statements and (2) TCEH's loans, which are payable on demand, to its indirect parent, Energy Future Holdings Corp.

/s/    DELOITTE & TOUCHE LLP

Dallas, Texas

February 19, 2013

161

Item 9b. OTHER INFORMATION

None

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Item 10 is not presented as EFCH meets the conditions set forth in General Instruction (I)(1)(a) and (b).

Item 11. EXECUTIVE COMPENSATION

Item 11 is not presented as EFCH meets the conditions set forth in General Instruction (I)(1)(a) and (b).

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Item 12 is not presented as EFCH meets the conditions set forth in General Instruction (I)(1)(a) and (b).

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Item 13 is not presented as EFCH meets the conditions set forth in General Instruction (I)(1)(a) and (b).

162

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 on-going 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 2012 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.

163

For the years ended December 31, 2012 and 2011, fees billed (in US dollars) to EFCH by Deloitte & Touche were as follows:

	2012		2011
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	$	5,642,000	$	6,035,500
Audit-Related Fees. Fees for services including employee benefit plan audits, 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	506,000		326,000
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	256,000		—
Total	$	6,404,000	$	6,361,500

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(b) Exhibits:

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012
Exhibits	Previously Filed* With File Number	As Exhibit
(3)	Articles of Incorporation and By-laws
3(a)	333-153529 Form S-4 (filed September 17, 2008)	3(b)	—	Second Amended and Restated Articles of Incorporation of Energy Future Competitive Holdings Company (formerly known as TXU US Holdings Company)
3(b)	333-153529 Form S-4 (filed September 17, 2008)	3(e)	—	Restated Bylaws of Energy Future Competitive Holdings Company (formerly known as TXU US Holdings Company)
(4)	Instruments Defining the Rights of Security Holders, Including Indentures**
	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.

164

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012
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 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.
4(g)	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(h)	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(i)	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(j)	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(k)	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(l)	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(m)	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(n)	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.

165

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012
4(o)	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.
4(p)	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.
Texas Competitive Electric Holdings Company LLC
4(q)	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(r)	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(s)	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(t)	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(u)	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.
4(v)	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(w)	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(x)	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.

166

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012
4(y)	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(z)	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(aa)	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(bb)	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.
4(cc)	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(dd)	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(ee)	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
	Credit Agreements and Related Agreements

167

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012
10(a)	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(b)	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(c)	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(d)	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(e)	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(f)	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(g)	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(h)	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(i)	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.

168

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012
10(j)	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(k)	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.
10(l)	1-12833 Form 8-K (filed November 20, 2009)	4.3	—	Pledge Agreement, dated November 16, 2009, made by Energy Future Intermediate Holding Company LLC and the additional pledgers to The Bank of New York Mellon Trust Company, N.A., as collateral trustee for the holders of parity lien obligations.
10(m)	1-12833 Form 8-K (filed November 20, 2009)	4.4	—	Collateral Trust Agreement, dated November 16, 2009, among Energy Future Intermediate Holding Company LLC, The Bank of New York Mellon Trust Company, N.A., as first lien trustee and as collateral trustee, and the other secured debt representatives party thereto.
	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.

169

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012
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.
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
(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.

170

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2012
99(b)		—	Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2012 and 2011.
99(c)		—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2012 and 2011.
	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 long-term 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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Energy Future Competitive Holdings Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY
Date:	February 19, 2013	By	/S/    JOHN F. YOUNG
			(John F. Young, 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 and in the capacities and on the date indicated.

171

Signature	Title	Date
/S/    JOHN F. YOUNG	Principal Executive Officer and Director	February 19, 2013
(John F. Young, Chair, President and Chief Executive)
/S/    PAUL M. KEGLEVIC	Principal Financial Officer and Director	February 19, 2013
(Paul M. Keglevic, Executive Vice President and Chief Financial Officer)
/S/    STANLEY J. SZLAUDERBACH	Principal Accounting Officer	February 19, 2013
(Stanley J. Szlauderbach, Senior Vice President and Controller)
/S/    ARCILIA C. ACOSTA	Director	February 19, 2013
(Arcilia C. Acosta)
/S/    SCOTT LEBOVITZ	Director	February 19, 2013
(Scott Lebovitz)
/S/    MICHAEL MACDOUGALL	Director	February 19, 2013
(Michael MacDougall)
/S/    JONATHAN D. SMIDT	Director	February 19, 2013
(Jonathan D. Smidt)

172

EXHIBIT 12(a)

	Year Ended December 31,
	2012			2011			2010			2009		2008
EARNINGS:
Income (loss) from continuing operations	$	(3,008	)	$	(1,802	)	$	(3,530	)	$	515	$	(9,039	)
Add: Total federal income tax expense (benefit)	(924		)	(943		)	318			351		(504		)
Fixed charges (see detail below)	2,902			3,849			3,150			2,420		4,518
Total earnings (loss)	$	(1,030	)	$	1,104		$	(62	)	$	3,286	$	(5,025	)
FIXED CHARGES:
Interest expense	$	2,878		$	3,824		$	3,127		$	2,395	$	4,492
Rentals representative of the interest factor	24			25			23			25		26
Total fixed charges	$	2,902		$	3,849		$	3,150		$	2,420	$	4,518
RATIO OF EARNINGS TO FIXED CHARGES (a)	—			—			—			1.36		—

____________

(a) Fixed charges exceeded "earnings" by $3.932 billion, $2.745 billion, $3.212 billion and $9.543 billion for the years ended December 31, 2012, 2011, 2010 and 2008, respectively.

173

Exhibit 31(a)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 302

of Sarbanes - Oxley Act of 2002

I, John F. Young, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 19, 2013		/s/ JOHN F. YOUNG
	Name:	John F. Young
	Title:	Chair, President and Chief Executive

174

Exhibit 31(b)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 302

of Sarbanes - Oxley Act of 2002

I, Paul M. Keglevic, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 19, 2013		/s/ PAUL M. KEGLEVIC
	Name:	Paul M. Keglevic
	Title:	Executive Vice President and Chief Financial Officer

175

Exhibit 32(a)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 906

of Sarbanes - Oxley Act of 2002

CERTIFICATION OF CEO

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

1. The Company's Annual Report on Form 10-K for the period ended December 31, 2012 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

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

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 19th day of February, 2013.

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

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

176

Exhibit 32(b)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 906

of Sarbanes - Oxley Act of 2002

CERTIFICATION OF CFO

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

1. The Company's Annual Report on Form 10-K for the period ended December 31, 2012 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

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

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 19th day of February, 2013.

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

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

177

Exhibit 95(a)

Mine Safety Disclosures

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

We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other regulatory agencies such as the RRC. The MSHA inspects US mines, including ours, on a regular basis and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed to the Federal Mine Safety and Health Review Commission (FMSHRC), which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. The number of citations, orders and proposed assessments vary depending on the size of the mine as well as other factors.

Disclosures related to specific mines pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K sourced from data documented at January 3, 2013 in the MSHA Data Retrieval System for the twelve months ended December 31, 2012 (except pending legal actions, which are at December 31, 2012), are as follows:

Mine (a)	Section 104 S and S Citations (b)	Section 104(b) Orders	Section 104(d) Citations and Orders	Section 110(b)(2) Violations	Section 107(a) Orders	Total Dollar Value of MSHA Assessments Proposed (c)	Total Number of Mining Related Fatalities	Received Notice of Pattern of Violations Under Section 104(e)	Received Notice of Potential to Have Pattern Under Section 104(e)	Legal Actions Pending at Last Day of Period (d)	Legal Actions Initiated During Period	Legal Actions Resolved During Period
Beckville	2	—	—	—	—	25	—	—	—	6	2	2
Big Brown	7	—	—	—	—	6	—	—	—	3	3	2
Kosse	10	—	—	—	—	144	—	—	—	5	2	—
Oak Hill	—	—	—	—	—	1	—	—	—	2	—	—
Sulphur Springs	4	—	—	—	—	6	—	—	—	1	1	4
Tatum	3	—	—	—	—	5	—	—	—	2	—	—
Three Oaks	8	—	1	—	—	76	—	—	—	3	2	1
Turlington	—	—	—	—	—	—	—	—	—	1	1	—
Winfield South	1	—	—	—	—	1	—	—	—	1	1	1

____________

(a) Excludes mines for which there were no applicable events.

(b) Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.

(c) Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in the twelve months ended December 31, 2012, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.

(d) Pending actions before the FMSHRC involving a coal or other mine. All 24 are contests of proposed penalties.

178

Exhibit 99(b) Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA Reconciliation (millions of dollars)
	Year Ended December 31,
	2012			2011
Net loss	$	(2,948	)	$	(1,740	)
Income tax benefit	(894		)	(917		)
Interest expense and related charges	2,752			3,699
Depreciation and amortization	1,343			1,470
EBITDA	$	253		$	2,512
Interest income	(46		)	(87		)
Amortization of nuclear fuel	156			142
Purchase accounting adjustments (a)	55			157
Impairment of goodwill	1,200			—
Impairment and write-down of other assets (b)	6			430
Unrealized net (gain) loss resulting from commodity hedging and trading transactions	1,526			(58		)
EBITDA amount attributable to consolidated unrestricted subsidiaries	(4		)	(7		)
Corporate depreciation, interest and income tax expenses included in SG&A expense	17			16
Noncash compensation expense (c)	7			12
Transition and business optimization costs (d)	33			42
Transaction and merger expenses (e)	38			37
Restructuring and other (f)	14			72
Charges related to pension plan actions (g)	141			—
Expenses incurred to upgrade or expand a generation station (h)	100			100
Adjusted EBITDA per Incurrence Covenant	$	3,496		$	3,368
Expenses related to unplanned generation station outages	78			181
Pro forma adjustment for Oak Grove 2 reaching 70% capacity in Q2 2011 (i)	—			27
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (j)	—			8
Adjusted EBITDA per Maintenance Covenant	$	3,574		$	3,584

___________

(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Adjustments in 2011 include $46 million related to an asset sale.

(b) Impairment of assets in 2011 includes impairment of emission allowances and certain mining assets due to EPA rule issued in July 2011.

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

(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costs related to generation plant reliability and supply chain efficiency initiatives.

(e) Transaction and merger expenses primarily represent Sponsor Group management fees.

(f) Restructuring and other in 2011 includes gains on termination of a long-term power sales contract and settlement of amounts due from hedging/trading counterparty, fees related to the amendment and extension of the TCEH Senior Secured Facilities, and reversal of certain liabilities accrued in purchase accounting.

(g) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employees of EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pension obligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensive income.

(h) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs.

(i) Pro forma adjustment for the year ended 2011 represents the annualization of the actual nine months ended December 31, 2011 EBITDA results for Oak Grove 2, which achieved the requisite 70% average capacity factor in the second quarter 2011.

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

179

Exhibit 99(c) Energy Future Holdings Corp. Consolidated Adjusted EBITDA Reconciliation (millions of dollars)
	Year Ended December 31,
	2012			2011
Net loss	$	(3,360	)	$	(1,913	)
Income tax benefit	(1,232		)	(1,134		)
Interest expense and related charges	3,508			4,294
Depreciation and amortization	1,373			1,499
EBITDA	$	289		$	2,746
Oncor Holdings distributions of earnings	147			116
Interest income	(2		)	(2		)
Amortization of nuclear fuel	156			142
Purchase accounting adjustments (a)	74			204
Impairment of goodwill	1,200			—
Impairment and write-down of other assets (b)	48			433
Debt extinguishment gains	—			(51		)
Equity in earnings of unconsolidated subsidiary	(270		)	(286		)
Unrealized net (gain) loss resulting from commodity hedging and trading transactions	1,526			(58		)
EBITDA amount attributable to consolidated unrestricted subsidiaries	4			—
Noncash compensation expense (c)	11			13
Transition and business optimization costs (d)	35			39
Transaction and merger expenses (e)	39			37
Restructuring and other (f)	15			80
Charges related to pension plan actions (g)	285			—
Expenses incurred to upgrade or expand a generation station (h)	100			100
Adjusted EBITDA per Incurrence Covenant	$	3,657		$	3,513
Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)	1,600			1,523
Adjusted EBITDA per Restricted Payments Covenant	$	5,257		$	5,036

___________

(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. Adjustments in 2011 include $46 million related to an asset sale.

(b) Impairment of assets in 2011 includes impairment of emission allowances and certain mining assets due to EPA rule issued in July 2011.

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

(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costs related to generation plant reliability and supply chain efficiency initiatives.

(e) Transaction and merger expenses primarily represent Sponsor Group management fees.

(f) Restructuring and other in 2011 includes gains on termination of a long-term power sales contract and settlement of amounts due from hedging/trading counterparty, fees related to the amendment and extension of the TCEH Senior Secured Facilities, and reversal of certain liabilities accrued in purchase accounting.

(g) Charges related to pension plan actions resulted from the termination and payout of pension obligations for active nonunion employees of EFH Corp.'s competitive businesses and the assumption by Oncor under a new Oncor pension plan of all of EFH Corp.'s pension obligations to retirees and terminated vested participants. The charges represent actuarial losses previously recorded as other comprehensive income.

(h) Expenses incurred to upgrade or expand a generation station represent noncapital outage costs.

180