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, 2011

— OR—

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

Commission File Number 1-12833

Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

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Texas	75-2669310
(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)

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Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
9.75% Senior Secured Notes due 2019	New York Stock Exchange

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

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

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

As of February 20, 2012, there were 1,679,539,245 shares of common stock, no par value, outstanding of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.'s parent holding company, and none of which is publicly traded).

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DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

		Page
Glossary		ii
PART I
Items 1. and 2. BUSINESS AND PROPERTIES		1
Item 1A.	RISK FACTORS	28
Item 1B.	UNRESOLVED STAFF COMMENTS	47
Item 3.	LEGAL PROCEEDINGS	48
Item 4.	MINE SAFETY DISCLOSURES	49
PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	50
Item 6.	SELECTED FINANCIAL DATA	50
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	53
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	100
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	107
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	190
Item 9A.	CONTROLS AND PROCEDURES	190
Item 9B.	OTHER INFORMATION	192
PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	193
Item 11.	EXECUTIVE COMPENSATION	199
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	225
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	229
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	233
PART IV
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	241

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

This annual report on Form 10-K and other Securities and Exchange Commission filings of EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or "we," "our," "us" or "the company"), EFCH, EFIH, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

i

GLOSSARY

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

Adjusted EBITDA	Adjusted EBITDA means EBITDA adjusted to exclude noncash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under US GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-K (see reconciliations in Exhibits 99(b), 99(c) and 99(d)) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with US GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management's discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
ancillary services	Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system.
CAIR	Clean Air Interstate Rule
Capgemini	Capgemini Energy LP, a provider of business support services to EFH Corp. and its subsidiaries
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.
Competitive Electric segment	Refers to the EFH Corp. business segment that consists principally of TCEH.
CREZ	Competitive Renewable Energy Zone
CSAPR	Refers to the final Cross-State Air Pollution Rule issued by the EPA in July 2011.
DOE	US Department of Energy
EBITDA	Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.
EFCH	Refers to Energy Future Competitive Holdings Company, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context.
EFH Corp.	Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor.
EFH Corp. Senior Notes	Refers collectively to EFH Corp.'s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.'s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).
EFH Corp. Senior Secured Notes	Refers collectively to EFH Corp.'s 9.75% Senior Secured Notes due October 15, 2019 (EFH Corp. 9.75% Notes) and EFH Corp.'s 10.000% Senior Secured Notes due January 15, 2020 (EFH Corp. 10% Notes).
EFIH	Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.
EFIH Finance	Refers to EFIH Finance Inc., a direct, wholly-owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities.
EFIH Notes	Refers collectively to EFIH's and EFIH Finance's 9.75% Senior Secured Notes due October 15, 2019 (EFIH 9.75% Notes), 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% Notes) and 11% Senior Secured Second Lien Notes due October 1, 2021 (EFIH 11% Notes).
EPA	US Environmental Protection Agency
EPC	engineering, procurement and construction
ERCOT	Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas
ERISA	Employee Retirement Income Security Act of 1974, as amended

ii

FASB	Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting
FERC	US Federal Energy Regulatory Commission
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GWh	gigawatt-hours
IRS	US Internal Revenue Service
kV	kilovolts
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	Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.
MATS	Refers to 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 oxide
NRC	US Nuclear Regulatory Commission
NYMEX	Refers to the New York Mercantile Exchange, a physical commodity futures exchange.
Oncor	Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.
Oncor Holdings	Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context.
Oncor Ring-Fenced Entities	Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
purchase accounting	The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or "purchase price" of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
Regulated Delivery segment	Refers to the EFH Corp. business segment that consists of the operations of Oncor.
REP	retail electric provider

iii

RRC	Railroad Commission of Texas, which among other things, has oversight of mining activity in Texas
S&P	Standard & Poor's Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)
SEC	US Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
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 Capital, L.P. and GS Capital Partners, an affiliate of Goldman, Sachs & Co. that have an ownership interest in Texas Holdings.
TCEH	Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy.
TCEH Finance	Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.
TCEH Senior Notes	Refers collectively to TCEH's 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015, Series B (collectively, TCEH 10.25% Notes) and TCEH's 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).
TCEH Senior Secured Facilities	Refers collectively to the TCEH Term Loan Facilities, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 10 to Financial Statements for details of these facilities.
TCEH Senior Secured Notes	Refers to TCEH's 11.5% Senior Secured Notes due October 1, 2020.
TCEH Senior Secured Second Lien Notes	Refers collectively to TCEH's 15% Senior Secured Second Lien Notes due April 1, 2021 and TCEH's 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.
TCEQ	Texas Commission on Environmental Quality
Texas Holdings	Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.
Texas Holdings Group	Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.
Texas Transmission	Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group.
TRE	Refers to Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols.
TXU Energy	Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.
US	United States of America
VIE	variable interest entity

iv

PART I

Items 1. and 2. BUSINESS AND PROPERTIES

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

EFH Corp. Business and Strategy

We are a Dallas, Texas-based energy company with a portfolio of competitive and regulated energy businesses in Texas. EFH Corp. is a holding company conducting its operations principally through its TCEH and Oncor subsidiaries. EFCH and TCEH are wholly-owned. EFIH is wholly-owned and indirectly holds an approximately 80% equity interest in Oncor. Immediately below is an organization chart of the key subsidiaries discussed in this report.

EFCH's principal asset is its investment in TCEH. EFCH is a guarantor of a significant portion of the debt of EFH Corp. (parent entity) and TCEH.

TCEH, through its subsidiaries, is engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales.

TCEH 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 the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US. TCEH provides competitive electricity and related services to 1.8 million retail electricity customers in Texas.

EFIH's principal assets consist of its investment in Oncor Holdings, the principal asset of which is an 80% equity interest in Oncor, and its investment in debt securities of EFH Corp. (parent entity) and TCEH that EFIH received in exchange for debt issued by EFIH. EFIH is also a guarantor of a significant portion of EFH Corp.'s (parent entity) debt.

1

Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the PUCT and, in certain instances, FERC. Oncor provides both distribution services to retail electric providers that sell electricity to consumers and transmission services to other electricity distribution companies, cooperatives, municipalities and REPs. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to more than three million homes and businesses and operating more than 118,000 miles of transmission and distribution lines. A significant portion of Oncor's revenues represent fees for delivery services provided to TCEH. Revenues from TCEH represented 33% and 36% of Oncor's total revenues for the years ended December 31, 2011 and 2010, respectively.

2

EFH Corp. and Oncor have implemented certain structural and operational "ring-fencing" measures based on commitments made by Texas Holdings and Oncor to the PUCT that are intended to enhance the credit quality of Oncor. These measures serve to mitigate Oncor's and Oncor Holdings' credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings 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. Accordingly, EFH Corp. and EFIH do not control and do not consolidate Oncor for financial reporting purposes. See Note 1 to Financial Statements for a description of the material features of these "ring-fencing" measures.

As of December 31, 2011, we had approximately 9,300 full-time employees (including approximately 3,700 at Oncor). Approximately 3,000 employees are under collective bargaining agreements (including approximately 850 at Oncor).

EFH Corp.'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 procuring energy on behalf of its members while 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. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events – Wholesale Market Design – Nodal Market" for additional discussion of the ERCOT nodal market.

Oncor, along with other owners of transmission and distribution facilities in Texas, assists the ERCOT ISO in its operations. Oncor has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated distribution service area. Oncor participates with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing and constructing new transmission lines in order to remove existing constraints on the ERCOT transmission grid. The transmission lines are necessary to meet reliability needs, support renewable energy production and increase bulk power transfer capability.

3

The following data is derived from information published by ERCOT:

Installed generation capacity in the ERCOT market for the year 2011 totaled approximately 82,800 MW, including approximately 2,500 MW mothballed (idled) capacity and more than 10,000 MW of wind and other resources that may not be available coincident with system need. In August 2011, ERCOT's hourly demand peaked at a record 68,379 MW. Of ERCOT's total installed capacity, approximately 57% is natural gas-fueled generation, approximately 29% is lignite/coal and nuclear-fueled generation and approximately 14% is wind and other renewable resources. In November 2010, ERCOT changed its minimum reserve margin planning criterion to 13.75% from 12.5%. In January 2012, ERCOT projected the reserve margin for the summer peak load period to be 13.9% in 2012, 12.1% in 2013, and 7.6% in 2014. Reserve margin is the difference between system generation capability and anticipated peak load.

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.

4

Natural gas-fueled generation is the predominant electricity capacity resource (approximately 57%) in the ERCOT market and accounted for approximately 40% of the electricity produced in the ERCOT market in 2011. 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.

EFH Corp.'s Strategies

Each of our businesses focuses its operations on key safety, reliability, economic and environmental drivers for that business, as described below:

• TCEH focuses on optimizing and developing its generation fleet to safely provide reliable electricity supply in a cost-effective manner and in consideration of environmental impacts, hedging its electricity price exposure and providing high quality service and innovative energy products to retail and wholesale customers.

• Oncor focuses on delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in its transmission and distribution infrastructure to maintain its system, serve its growing customer base with a modernized grid and support renewable energy production.

Other elements of our strategies include:

• Increase value from existing business lines. Our strategy focuses on striving for top quartile or better performance across our operations in terms of safety, reliability, cost and customer service. In establishing tactical 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.

5

• 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 alternatives such as natural gas, nuclear, renewable energy and advanced coal technologies.

• 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 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.

• Investing in transmission and distribution, including advanced metering systems and energy efficiency initiatives, and constructing new transmission and distribution facilities to meet the needs of the growing Texas market.

• 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.

6

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 as of December 31, 2011, has effectively sold forward approximately 700 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 82,000 GWh at an assumed 8.5 market heat rate) for the period January 1, 2012 through December 31, 2014 at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.

7

• These transactions, together with forward power sales, have effectively hedged an estimated 86%, 58% and 31% of the price exposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2012, 2013 and 2014, respectively (assuming an 8.5 market heat rate). These estimates reflect currently governing CAIR regulation and do not include any potential impacts of the CSAPR (discussed under "Environmental Regulations and Related Considerations"). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will largely move with prices of natural gas, which is expected to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOT market. If this relationship changes, the cash flows targeted under the natural gas price hedging program may not be achieved. 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 – Natural Gas Prices and Natural Gas Price Hedging Program," "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, we initiated a liability management program focused on improving our balance sheet, and we expect to opportunistically look for ways to reduce the amount and extend the maturity of our outstanding debt. Activities under the liability management program do not include debt issued by Oncor or its subsidiaries. The program has resulted in the capture of $2.0 billion of debt discount and the extension of approximately $23.5 billion of debt maturities to 2017-2021. Activities to date have included debt exchanges, issuances and repurchases as well as amendments to the Credit Agreement governing the TCEH Senior Secured Facilities. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events – Liability Management Program" and Note 10 to Financial Statements for additional discussion of these transactions.

We regularly monitor the capital and bank credit markets for liability management opportunities. Future activities under the liability management program may include the purchase of our outstanding debt for cash in open market purchases or privately negotiated refinancing and exchange transactions (including pursuant to a Section 10b-5(1) plan) or via public or private exchange or tender offers.

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

• 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.

8

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment (consisting largely of TCEH and its subsidiaries) and the Regulated Delivery segment (consisting largely of our investment in Oncor). See Note 21 to Financial Statements for additional financial information for the segments.

Competitive Electric Segment

Key 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 segment operations 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	8,017	5	12
Natural gas (b)	5,110	8	26
Total	15,427	14	40

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

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

The generation units are located primarily on owned land. Nuclear and lignite/coal-fueled units are generally scheduled to run at capacity except for periods of scheduled maintenance activities; however, we reduce production from certain lignite/coal-fueled generation units during periods when wholesale electricity market prices are less than the unit's production costs (i.e., economic backdown). 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 a certain number of these units can more readily be 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 to meet the load requirements in ERCOT. 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 95.7% in 2011 and 100% in both 2010 and 2009.

Luminant has contracts in place for all of its uranium and nuclear fuel conversion, enrichment and fabrication services for 2012. For the period of 2013 through 2018, Luminant has contracts in place for the acquisition of approximately 75% of its uranium requirements and 56% of its nuclear fuel conversion services requirements. In addition, Luminant has contracts in place for all of its nuclear fuel enrichment services through 2013, 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 services and enrichment services in the foreseeable future.

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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 funded from Oncor's customers through an ongoing delivery surcharge. (See Note 17 to Financial Statements for discussion of the decommissioning trust fund.)

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

Nuclear Generation Development— In September 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 January 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.

In December 2011, the NRC updated its official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by July 2014, and it is expected that a license would be issued by year-end 2014.

In 2009, the DOE announced that it had selected four applicants to proceed to the due diligence phase of its Loan Guarantee Program and to commence negotiations towards potential loan guarantees for their respective generation projects. CPNPC was not among the initial four applicants selected by the DOE; however, CPNPC continues to update the DOE on its progress, with the goal of securing a DOE loan guarantee 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 (excluding three recently constructed units) averaged 31 days. Luminant's lignite/coal-fueled generation fleet operated at a capacity factor of 83.5% in 2011, 82.2% in 2010 and 86.5% in 2009, which represents top decile performance of US coal-fueled generation facilities. This performance reflects increased economic backdown of the units as described above.

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 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.

Aggregate cash capital expenditures for these three units totaled approximately $3.25 billion including all construction, site preparation and mining development costs. The investment included approximately $500 million for state-of-the-art emissions controls for the three new units. Including capitalized interest and the step-up in construction work-in-process balances to fair value as a result of purchase accounting for the Merger in 2007, carrying value of the units totaled approximately $4.8 billion upon completion.

Approximately 64% of the fuel used at Luminant's lignite/coal-fueled generation units in 2011 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 790 million tons of lignite reserves dedicated to these sites, and has an undivided interest in 240 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 2011, Luminant recovered approximately 32 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipment to remove the overburden and recover the lignite.

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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 2011, Luminant reclaimed more than 2,700 acres of land. In addition, Luminant planted 1.4 million trees in 2011, 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 western coal resources 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's fleet of 26 natural gas-fueled generation units totaling 5,110 MW of capacity includes 3,455 MW of currently available capacity and 1,655 MW of capacity 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 2010 and 2009, Luminant retired 19 natural gas-fueled units totaling 5,118 MW of installed nameplate capacity and mothballed 4 units totaling the 1,655 MW of capacity.

Wholesale Operations — Luminant's wholesale operations play a pivotal role in our Competitive Electric segment portfolio 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 the largest purchaser of wind-generated electricity in Texas and the fifth largest in 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.

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 electricity market participants, including generators and end-use customers. A significant part of these hedging activities is a natural gas price hedging program, described above under "EFH Corp.'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 result in 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 11 billion cubic feet of natural gas storage capacity.

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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 transactions, 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. Luminant has a disciplinary program to address any violations of the risk management policies and periodically reviews these policies to ensure they are responsive to changing market and business conditions.

TXU Energy — TXU Energy serves 1.8 million residential and commercial retail electricity customers in Texas. Approximately 64% of retail revenues in 2011 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. There are more than 100 active REPs certified to compete within the State of Texas. Based upon data published by the PUCT, as of September 30, 2011, approximately 56% of residential customers and 66% of small commercial customers in competitive areas of ERCOT are served by REPs not affiliated with the pre-competition utility.

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, a new customer management computer system was implemented in 2009, and other customer care enhancements are being implemented to continually improve customer satisfaction. TXU Energy offers a wide range of residential products to meet varying customer needs and is investing $100 million in energy efficiency initiatives over a five-year period ending in 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.

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.

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 prices charged. 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.

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Regulated Delivery Segment

The Regulated Delivery segment consists largely of our investment in Oncor. Oncor is a regulated electricity transmission and distribution company that provides the service of delivering electricity safely, reliably and economically to end-use consumers through its distribution systems, as well as providing transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor's service territory comprises 91 counties and over 400 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen. Oncor's transmission and distribution assets are located principally in the north-central, eastern and western parts of Texas. Most of Oncor's power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. Oncor's transmission and distribution rates are regulated by the PUCT.

Oncor is not a seller of electricity, nor does it purchase electricity for resale. It provides transmission services to other electricity distribution companies, cooperatives and municipalities. It provides distribution services to REPs, which sell electricity to residential, business and other consumers. Oncor 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.

Performance — Oncor achieved or exceeded market performance protocols in 12 out of 14 PUCT market metrics in 2011. These metrics measure the success of transmission and distribution companies in facilitating customer transactions in the competitive Texas electricity market.

Investing in Infrastructure and Technology — In 2011, Oncor invested $1.4 billion in its network to construct, rebuild and upgrade transmission lines and associated facilities, to extend the distribution infrastructure, and to pursue certain initiatives in infrastructure maintenance and information technology. Reflecting its commitment to infrastructure, in September 2008, Oncor and several other ERCOT utilities filed with the PUCT a plan to participate in the construction of transmission improvements designed to interconnect existing and future renewable energy facilities to transmit electricity from Competitive Renewable Energy Zones (CREZs) identified by the PUCT. In 2009, the PUCT awarded CREZ construction projects to Oncor, and Oncor currently estimates the costs of the projects to be approximately $2.0 billion. The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. Through 2011, Oncor's cumulative CREZ-related capital expenditures totaled $899 million, including $583 million invested in 2011. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Regulatory Matters – Oncor Matters with the PUCT."

Oncor's technology upgrade initiatives include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor's plans provide for the full deployment of over three million advanced meters to all residential and most non-residential retail electricity customers in Oncor's service area by the end of 2012. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits. As of December 31, 2011, Oncor has installed approximately 2,302,000 advanced digital meters, including 788,000 in 2011. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $518 million as of December 31, 2011, including $158 million invested in 2011.

In addition to the potential energy efficiencies from advanced metering, Oncor expects to spend approximately $340 million ($100 million in excess of regulatory requirements) over the five-year period ending December 31, 2012 in programs designed to improve customer electricity demand efficiencies. As of December 31, 2011, approximately $265 million had been spent by Oncor, including $75 million in 2011, and 75% of the amount in excess of regulatory requirements had been spent.

In a stipulation with several parties that was approved by the PUCT in 2007, Oncor has committed to a variety of actions, including minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. Approximately 94% of this total had been spent as of December 31, 2011. This spending does not include the CREZ facilities.

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Electricity Transmission — Oncor's electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction and maintenance of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over Oncor's transmission facilities in coordination with ERCOT.

Oncor is a member of ERCOT, and its transmission business actively assists the operations of ERCOT and market participants. Through its transmission business, Oncor participates with ERCOT and other member utilities to plan, design, construct and operate new transmission lines, with regulatory approval, necessary to maintain reliability, interconnect to merchant generation facilities, increase bulk power transfer capability and minimize limitations and constraints on the ERCOT transmission grid.

Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to an interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above. Other services offered by Oncor through its transmission business include, but are not limited to: system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.

PURA allows Oncor to update its transmission rates periodically to reflect changes in invested capital. This "capital tracker" provision encourages investment in the transmission system to help ensure reliability and efficiency by allowing for timely recovery of and return on new transmission investments.

As of December 31, 2011, Oncor's transmission facilities included approximately 5,407 circuit miles of 345-kV transmission lines and approximately 9,935 circuit miles of 138-and 69-kV transmission lines. Sixty-one generation facilities totaling 33,380 MW were directly connected to Oncor's transmission system as of December 31, 2011, and 288 transmission stations and 707 distribution substations were served from Oncor's transmission system.

As of December 31, 2011, Oncor's transmission facilities have the following connections to other transmission grids in Texas:

	Number of Interconnected Lines
Grid Connections	345kV	138kV	69kV
Centerpoint Energy Inc.	8	—	—
American Electric Power Company, Inc (a)	4	7	11
Lower Colorado River Authority	8	22	3
Texas Municipal Power Agency	6	6	—
Texas New Mexico Power	4	9	11
Brazos Electric Power Cooperative, Inc.	6	109	22
Electric Transmission Texas, LLC	2	1	—
Rayburn Country Electric Cooperative, Inc.	—	37	6
City of Georgetown	—	2	—
Tex-La Electric Cooperative of Texas, Inc.	—	12	1
Other small systems operating wholly within Texas	—	4	2

___________

(a) One of the 345-kV lines is an asynchronous high-voltage direct current connection with the Southwest Power Pool.

Electricity Distribution— Oncor's electricity distribution business is responsible for the overall safe and efficient operation of distribution facilities, including electricity delivery, power quality and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the distribution system within Oncor's certificated service area. Oncor's distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through approximately 3,147 distribution feeders.

The Oncor distribution system includes over 3.2 million points of delivery. Over the past five years, the number of distribution system points of delivery served by Oncor, excluding lighting sites, grew an average of approximately 1.12% per year. Oncor added approximately 34,000 points of delivery in 2011.

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The Oncor distribution system consists of approximately 56,466 miles of overhead primary conductors, approximately 21,529 miles of overhead secondary and street light conductors, approximately 15,703 miles of underground primary conductors and approximately 9,738 miles of underground secondary and street light conductors. The majority of the distribution system operates at 25-kV and 12.5-kV.

Oncor's distribution rates for residential and small commercial users are based on actual monthly consumption (kWh), and rates for large commercial and industrial users are based on the greater of actual monthly demand (kilowatt) or 80% of peak monthly demand during the prior eleven months.

Customers— Oncor's transmission customers consist of municipalities, electric cooperatives and other distribution companies. Oncor's distribution customers consist of more than 80 REPs, including TCEH and certain electric cooperatives in Oncor's certificated service area. Revenues from TCEH represented 33% of Oncor's total revenues for 2011. Revenues from subsidiaries of Reliant Energy, Inc., each of which is a non-affiliated REP, represented 12% of Oncor's total revenues for 2011. No other customer represented more than 10% of Oncor's total operating revenues. The consumers of the electricity delivered by Oncor are free to choose their electricity supplier from REPs who compete for their business.

Regulation and Rates— As its operations are wholly within Texas, Oncor is not a public utility as defined in the Federal Power Act and, as a result, it is not subject to general regulation under this Act. However, Oncor is subject to reliability standards adopted and enforced by the TRE and the NERC, including NERC CIP standards, under the Federal Power Act.

In January 2011, Oncor filed for a rate review with the PUCT and 203 cities (PUCT Docket No. 38929) based on a test year ended June 30, 2010. In August 2011, the PUCT issued a final order in the rate review. The rate review, as approved, includes an approximate $137 million base rate increase and additional provisions to address certain expenses. Approximately $93 million of the increase became effective July 1, 2011, and the remainder became effective January 1, 2012. The rate review did not change Oncor's authorized regulatory capital structure of 60% debt to 40% equity or its authorized return on equity of 10.25%. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters."

As directed by Senate Bill 1693, which was passed by the Texas Legislature in 2011, in September 2011, the PUCT approved the periodic rate adjustment rule, which allows utilities to file, under certain circumstances, up to four rate adjustments between rate reviews to recover distribution-related investments on an interim basis.

At the state level, PURA requires owners or operators of transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility's own use of its system. The PUCT has adopted rules implementing the state open-access requirements for utilities, including Oncor, that are subject to the PUCT's jurisdiction over transmission services.

Securitization Bonds— Oncor's operations include its wholly-owned, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuing certain securitization (transition) bonds in 2003 and 2004. Oncor Electric Delivery Transition Bond Company LLC issued $1.3 billion principal amount of transition bonds to recover generation-related regulatory asset stranded costs and other qualified costs under an order issued by the PUCT in 2002. At December 31, 2011, $554 million principal amount of transition bonds were outstanding, which mature in the period from 2012 to 2016. See Note 20 to Financial Statements for discussion of agreements between TCEH and Oncor regarding payment of interest and incremental taxes related to these bonds.

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Environmental Regulations and Related Considerations

Global Climate Change

Background — There is a concern 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 68 million short tons of CO2 in 2011. Other aspects of our operations result in emissions of GHGs including, among other things, coal piles at our generation plants, sulfur hexafluoride in transmission and distribution equipment, 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 and/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 — Several bills have been introduced in the US Congress or advocated by the Obama Administration that are 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 might also 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, including GHG emissions reduction targets for total US GHG emissions and rigorous cost containment measures to ensure that program costs are not prohibitive. In the event GHG legislation involving a cap-and-trade program is enacted, we believe that such a 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 believe 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 participate in a voluntary electric utility industry sector climate change initiative in partnership with the DOE. Our strategies are generally consistent with the "EEI Global Climate Change Points of Agreement" published by the Edison Electric Institute in January 2009 and "The Carbon Principles" announced in February 2008 by three major financial institutions. Finally, we have 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. Our 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.

Federal Level — Recent developments in the US Congress indicate that the prospects for passage of any cap-and-trade legislation in the near-term are not likely. However, if such legislation were to be adopted, our costs of compliance could be material and could have a material effect on our results of operations, liquidity and financial condition.

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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. Following its endangerment finding, the EPA took three regulatory actions with respect to the control of GHG emissions. First, in March 2010, the EPA completed a reconsideration of a memorandum issued in December 2008 by the then EPA Administrator on the issue of when the Clean Air Act's Prevention of Significant Deterioration (PSD) program would apply to newly identified pollutants such as GHGs. The EPA determined that the Clean Air Act's PSD permit requirements would apply 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. Second, in April 2010, the EPA adopted GHG emission standards for certain new motor vehicles. Third, 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, the EPA announced agreements with state and environmental groups to propose New Source Performance Standards for electric power plants by July 2011 and to finalize those standards by May 2012; however, the EPA failed to meet the July 2011 proposal date and will likely release the proposal in early 2012. In addition, in September 2009, the EPA issued a final rule requiring the reporting, by March 2011, of calendar year 2010 GHG emissions from specified large GHG emissions sources in the US (such reporting rule applies to our lignite/coal-fueled generation facilities). The report submittal date was extended to September 2011, and Luminant complied with this requirement. If limitations on emissions of GHGs from existing sources are enacted, our costs of compliance could be material and could have a material effect on our results of operations, liquidity and financial condition.

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 Texas Commission on Environmental Quality (TCEQ). The State of Texas is challenging that rule and the GHG permitting rules through litigation and has refused to implement the GHG permitting rules issued by the EPA. 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 over the next year is possible.

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

In October 2009, the US Court of Appeals for the Fifth Circuit issued a decision in the case of Comer v. Murphy Oil USA reversing the district court's dismissal of the case and holding that certain Mississippi residents had standing to pursue state law nuisance, negligence and trespass claims for injuries purportedly suffered because the defendants' emissions of GHGs allegedly increased the destructive force of Hurricane Katrina. The Fifth Circuit subsequently agreed to rehear the case, but then dismissed the appeal in its entirety when several judges recused themselves in the case. The Fifth Circuit's order dismissing the appeal and vacating the earlier panel's decision had the effect of reinstating the district court's original dismissal of the case. In January 2011, the US Supreme Court rejected the plaintiffs' request that their appeal be reinstated in the Fifth Circuit. In May 2011, the plaintiffs in the Comer case filed a new lawsuit in the United States District Court for the Southern District of Mississippi against numerous defendants (Comer II). The Comer II complaint reasserts that the defendants' emissions of GHGs have contributed to global warming and led to severe weather consequences. The plaintiffs assert claims for public and private nuisance, trespass and negligence, and they seek to have their case certified as a class action.

In September 2009, the US District Court for the Northern District of California issued a decision in the case of Native Village of Kivalina v. ExxonMobil Corporation dismissing claims asserted by an Eskimo village that emissions of GHGs from approximately 24 oil and energy companies are causing global warming, which has damaged the arctic sea ice that protects the village from winter storms and erosion. The court dismissed the claims because they raised political (not judicial) questions and because plaintiffs lacked standing to sue. An appeal of the district court's decision is currently pending in the US Court of Appeals for the Ninth Circuit. Oral argument related to the appeal was held in the US Court of Appeals for the Ninth Circuit in November 2011.

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While we are not a party to these suits, they could encourage or form the basis for a lawsuit asserting similar nuisance claims regarding emissions of GHGs. If any similar suit is successfully asserted against us in the future, it could have a material effect on our results of operations, liquidity and financial condition.

State and Regional Level — There are currently no Texas state regulations in effect concerning GHGs, and there are no regional initiatives concerning GHGs in which the State of Texas is a participant. We oppose state-by-state regulation of GHGs. In October 2009, Public Citizen Inc. filed a lawsuit against the TCEQ and its commissioners seeking to compel the TCEQ to regulate GHG emissions under the Texas Clean Air Act. The Attorney General of Texas has filed special exceptions to the Public Citizen pleading. We are not a party to this litigation.

International Level — The US currently is not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC). The United Nations' Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008 to 2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, leaders of developed and developing countries met in Copenhagen under the 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. The impact, if any, of this agreement 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, financial condition and/or results of operations; 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.

EFH Corp.'s Voluntary Energy Efficiency, Renewable Energy, and Global Climate Change Efforts — We are 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 by Our Competitive Businesses — Our competitive businesses expect to invest $100 million in energy efficiency and related initiatives over a five-year period ending in 2012, 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, 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 delivers 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; and programs promoting distributed renewable generation to reduce peak summer demand on the grid, such as the TXU Energy SolarLease^SM program, our distributed renewable generation surplus buyback program, and the TXU Energy Solar Academy program;

• Investing in Energy Efficiency Initiatives by Oncor — In addition to the potential energy efficiencies from advanced metering, Oncor expects to spend approximately $340 million in energy efficiency initiatives over a five-year period that ends in 2012 through such efforts as traveling across the State of Texas educating consumers about the benefits of energy efficiency, advanced meters and renewable energy, and spending over $23 million in the installation of solar photovoltaic systems in customer homes and facilities that is expected to result in savings of up to 16.5 million kWh of electricity;

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• Participating in the CREZ Program — Oncor has been selected by the PUCT to construct CREZ transmission facilities (currently estimated by Oncor to cost $2.0 billion) that are designed to connect existing and future renewable energy facilities to the electricity transmission system in ERCOT;

• 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;

• Promoting the Use of Solar Power — TXU Energy provides qualified customers, through its SolarLease 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; 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 an application with the NRC for combined construction and operating licenses for up to 3,400 MW 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;

• 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 1.4 million trees in 2011. 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 170,000 trees since its inception in 2002, and

• 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 NOx emissions are installed at Oak Grove Units 1 and 2 and Sandow Unit 4. Selective non-catalytic reduction systems designed to reduce NOx 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 NOx and SO2. Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitator systems also assist in reducing mercury and other emissions.

There is no assurance that the currently-installed emissions control equipment at our lignite/coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Recent EPA regulatory actions could require us to install significant additional control equipment, resulting in material costs of compliance for our generation units, including capital expenditures and higher operating costs. These costs could result in material effects on our results of operations, liquidity and financial condition.

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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 oxide (NOx) 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 August 2010, the EPA issued for comment a proposed replacement rule for CAIR called the Clean Air Transport Rule (CATR), similarly intended to implement CAA Section 110. As proposed, the CATR did not include Texas in its annual SO2 or NOx programs to address alleged downwind fine particulate matter effects.

In July 2011, the EPA issued the final replacement rule for CAIR (as finally issued, the Cross-State Air Pollution Rule (CSAPR)). Unlike the CATR, the CSAPR includes Texas in its annual SO2 and NOx emissions reduction programs, as well as the seasonal NOx emissions reduction program. These programs require significant additional reductions of SO2 and NOx emissions from fossil-fueled generation units in covered states (including Texas) and institute a limited "cap and trade" system as an additional compliance tool to achieve reductions the EPA contends are necessary to implement CAA Section 110. As adopted in July 2011 and absent a judicial stay, the CSAPR would have required our fossil-fueled generation units to (i) reduce their annual SO2 and NOx emissions by approximately 137,000 tons (64 percent) and 9,200 tons (22 percent), respectively, compared to 2010 actual levels, each beginning on January 1, 2012 and (ii) reduce their seasonal NOx emissions by approximately 3,400 tons (19 percent), compared to 2010 actual levels, beginning on May 1, 2012, which is the start of the ozone season.

In September 2011, we filed a petition for review in the D.C. Circuit Court challenging the CSAPR and a motion to stay the effective date of the CSAPR, in each case as applied to Texas.

In December 2011, the D.C. Circuit Court granted our motion and all other motions for a judicial stay of the CSAPR in its entirety, including as applied to Texas. The D.C. Circuit Court's order does not invalidate the CSAPR but stays the implementation of its emissions reduction programs until a final ruling regarding the CSAPR's validity is issued by the D.C. Circuit Court. The D.C. Circuit Court's order states that the EPA is expected to continue administering the CAIR (the predecessor rule to the CSAPR) pending the court's resolution of the petitions for review. The D.C. Circuit Court ordered us and other parties challenging the CSAPR to file opening briefs on February 9, 2012 with all briefing to be completed by March 16, 2012. The D.C. Circuit Court has scheduled oral argument for April 13, 2012. We cannot predict whether we will be successful in our legal challenge to the CSAPR, or when the D.C. Circuit Court will rule on our challenge.

In February 2012, the EPA released a final rule (Final Revisions) and a direct-to-final rule (Direct Final Rule) revising certain aspects of the CSAPR, including emissions budgets for the State of Texas. The Final Revisions increase the emissions budgets for the State of Texas by 50,517 tons for the annual SO₂ program and 1,375 tons for each of the annual NO_x and seasonal NO_x programs. The Direct Final Rule further increases (over the Final Revisions) the Texas annual NO_x emissions budget by 2,731 tons and the seasonal NO_x emissions budget by 1,142 tons. If the EPA receives significant adverse comments on the Direct Final Rule, it will be withdrawn and its provisions considered in a proposed rule subject to normal notice-and-comment rulemaking procedures. In total, the emissions budgets established by the Final Revisions along with the Direct Final 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. The company 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, as described further below. Because the CSAPR is currently stayed by the D.C. Circuit Court, the Final Revisions and the Direct Final Rule do not impose any immediate legal or compliance requirements on Luminant, the State of Texas, or other affected parties. We cannot predict whether, when, or in what form the CSAPR, the Final Revisions, or the Direct Final Rule will take effect.

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The CSAPR establishes a "cap and trade" system as a compliance tool. The system includes three trading programs - one for annual SO2 emissions and one each for seasonal and annual NOx emissions - that allow for limited trading of allowances among sources covered by the programs. An allowance represents a ton of emissions of SO2 or NOx and sources are required to surrender to the EPA one allowance for every ton of emissions they emit in a given compliance period. The CSAPR allocates to each covered state (including Texas) a number of allowances for each of the three programs, and those allowances are then allocated among emission sources within the state. To the extent a source's emissions exceed the number of allowances it has been allocated, the source generally may buy additional allowances from other sources that it can surrender to the EPA in order to comply with the CSAPR. Sources included in the seasonal and annual NOx programs are allowed to trade allowances with any other sources in those programs. The SO2 trading program, however, divides States into Group 1 and Group 2, and permits sources to trade SO2 allowances only with other sources in the same Group. Texas is in Group 2, which is composed of seven states. We believe that there may not be sufficient liquidity in the system for the purchase of allowances to constitute a significant element of our strategy to comply with the CSAPR as originally adopted. Further, we believe that the state assurance levels contained in the CSAPR starting in 2014 (i.e., the level of emissions permitted in a state that, to the extent exceeded, must be offset with allowances on a three to one basis - one allowance for exceeding the applicable emissions limit and two allowances for exceeding the assurance level) could prevent using allowances to offset emissions above our generation fleet's pro rata portion of the Texas assurance level as a viable compliance strategy in 2014 and beyond.

In September 2011, we announced a compliance plan to satisfy the requirements of the CSAPR as issued in July 2011. Consistent with this compliance plan, we submitted a Notice of Suspension of Operations to ERCOT in October 2011 to notify ERCOT that we would suspend operations at Monticello Units 1 and 2 as of January 1, 2012 in order to comply with the emissions limitations in the CSAPR. As a result of the D.C. Circuit Court's order staying the CSAPR, we rescinded our Notice of Suspension of Operations. While the legal challenge to the CSAPR is in process, we intend to continue evaluating the CSAPR, the Final Revisions, and the Direct Final Rule, alternatives for compliance and the expected effects on our operations, liquidity and financial results.

Material capital expenditures would be required to comply with the CSAPR, as revised in February 2012, as well as with other pending and expected environmental regulations. In 2011, total capital expenditures for environmental projects totaled $142 million. Analysis is ongoing regarding expected capital expenditures relating to the CSAPR, the status of which is uncertain given the pending legal proceeding, and the final MATS rule, which was published in February 2012. We currently estimate that total capital expenditures related to the CSAPR, MATS, and other environmental regulations will be approximately $300 million in 2012. Prior to the publication of the final MATS rule, 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 are currently evaluating this estimate in light of the final MATS rule, the Final Revisions and the Direct Final Rule.

Given the uncertainty regarding the CSAPR's (including the Final Revisions and the Direct Final Rule) 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 4 to Financial Statements for discussion of impairments of emission allowances and certain mining assets, as well as accelerated depreciation of mining assets recorded in 2011 as a result of the CSAPR.

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

SO2 and NOx 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 on a unit-by-unit basis. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze to the EPA, which we believe will not have a material impact on our generation facilities. The EPA has not made a final decision on this SIP submittal; however, in December 2011 the EPA proposed a limited disapproval of the SIP and a Federal Implementation Plan for Texas providing that the inclusion in the CSAPR programs meets the requirements for SO2 and NOx reductions.

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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 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 NOx 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 NOx 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. The TCEQ will be required to conduct modeling and develop an implementation plan by June 2013, pursuant to which compliance will be required by 2017, according to the EPA's implementation timeline. 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 2005, the EPA published a final rule requiring reductions of mercury emissions from lignite/coal-fueled generation plants. The Clean Air Mercury Rule (CAMR) was based on a nationwide cap and trade approach. The mercury reductions were required to be phased in between 2010 and 2018. In March 2008, the D.C. Circuit Court vacated CAMR. In February 2009, the US Supreme Court refused to hear the appeal of the D.C. Circuit Court's ruling. The EPA agreed in a consent decree submitted for court approval to propose Maximum Achievable Control Technology (MACT) rules by March 2011 and finalize those rules by November 2011, as subsequently postponed to December 2011. In March 2011, the EPA issued for comment a proposed rule for coal and oil-fueled electric generation units (Utility MACT). In December 2011, the EPA finalized the Utility MACT rule (now called the Mercury and Air Toxics Standard or 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 16, 2012 effective date of the rule. We continue to evaluate the measures necessary to comply with MATS, which are expected to require substantial capital expenditures, and have not finalized cost estimates. As with many EPA regulations, there may be requests for a stay or reconsideration of the rule or petitions to the courts. We cannot predict if these actions will occur or, if they do, the outcome.

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In September 2010, the EPA disapproved a portion of the SIP pursuant to which the TCEQ implements its program to achieve the requirements of the Clean Air Act. The EPA disapproved the Texas standard permit for pollution control projects. We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. We have challenged the EPA's disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit arguing that the TCEQ's adoption of the standard permit conditions for pollution control projects was consistent with the Clean Air Act. We have also formally asked the EPA to stay, reconsider or clarify its disapproval. If the EPA declines to stay or reconsider its disapproval, we asked the EPA to clarify whether it intends that entities, including us, who obtained such permits for pollution control projects should stop operating the pollution control equipment permitted under the standard permit conditions. We cannot predict the outcome of the litigation or the EPA's response to our request.

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 have challenged the EPA's disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit 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. We cannot predict the outcome of, or timing of the court's ruling in, this litigation. Also see Note 11 to Financial Statements for discussion of a petition filed in January 2012 by the Sierra Club in a Texas district court challenging the TCEQ's issuance of our permit amendments.

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In January 2011, the EPA retroactively disapproved a portion of the SIP pursuant to which the TCEQ issued permits for certain formerly non-permitted "grandfathered" facilities approximately 10 years ago. We hold such permits. The EPA took this action despite acknowledging that emissions covered by these standard permits do not threaten attainment or maintenance of the NAAQS under the Clean Air Act. We have challenged the EPA's disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit arguing that the TCEQ's adoption of the standard permit is consistent with the Clean Air Act. If the EPA's action stands, and if it causes us to undertake additional permitting activity and install additional emissions control equipment at our affected generation facilities, we could incur material capital expenditures. We cannot predict the outcome of this litigation.

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 are defending the issuance of the permit. We cannot predict the outcome of the litigation. 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 11 to Financial Statements.)

Recent changes to federal rules pertaining to the Spill Prevention, Control and Countermeasure (SPCC) plans for oil-filled electrical equipment and bulk storage facilities for oil required updating of certain of our facilities. We have developed and implemented SPCC plans as required for those substations, work centers and distribution systems, and we are currently in compliance with the new rules that became effective in November 2011.

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Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits for these activities from the TCEQ for our present operations. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were published by the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuit brought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it was suspending the regulations pending further rulemaking. The US Supreme Court issued a decision in April 2009 reversing the federal court's decision, in part, and finding that the EPA permissibly used cost-benefit analysis in the Section 316(b) regulations. In the absence of regulations, the EPA has instructed the states implementing the Section 316(b) program to use their best professional judgment in reviewing applications and issuing permits under Section 316(b). In April 2010, the EPA entered into a settlement agreement that requires it to propose new rules under Section 316(b) by March 2011 and to finalize those rules by July 2012. In March 2011, the EPA issued for comment the proposed regulations. Although the proposed rule does not mandate a certain control technology, it does require site-specific assessments of technology feasibility on a case-by-case basis at the state level. Compliance with this rule would be required beginning eight years following promulgation. We cannot predict the substance of the final regulations or the impact they may have on our results of operations, liquidity or financial condition.

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Radioactive Waste

We currently 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. In 2003, the State of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal, and in 2004 the State received a license application from such an entity for review. In January 2009, the TCEQ approved this permit. We expect to continue to ship low-level waste material off-site for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will be stored on-site. (See discussion under "Luminant – Nuclear Generation Operations" above.) A rate case is currently before the TCEQ to determine the rates to be charged by the owner of waste disposal facilities to customers (potentially including TCEH) for disposal of low-level radioactive waste in Texas.

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 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, at this time, 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.

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Environmental Capital Expenditures

Capital expenditures for our environmental projects totaled $142 million in 2011 and are expected to total approximately $300 million in 2012 related to the CSAPR, MATS and other environmental regulations.

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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 indebtedness 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 the various debt agreements governing our debt.

We are highly leveraged. As of December 31, 2011, our consolidated principal amount of debt (short-term borrowings and long-term debt, including amounts due currently) totaled $36.7 billion (see Note 10 to Financial Statements), which does not include $6.1 billion principal amount of debt of Oncor. Our substantial indebtedness could have significant consequences, including:

• making it more difficult for us to make payments on our debt;

• requiring a substantial portion of our cash flow to be dedicated to the payment of principal and interest on our debt, thereby 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 generation facilities;

• limiting our ability to obtain additional financing for working capital (including collateral postings), capital expenditures, product development, debt service requirements, acquisitions and general corporate or other purposes, or to refinance existing debt, and

• limiting our ability to adjust to changing market and industry conditions (including changes to environmental regulations) and placing us at a competitive disadvantage compared to competitors who are less highly 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 forward natural gas prices do not significantly increase and/or if environmental regulations are adopted that result in significant capital requirements.

We may not be able to repay or refinance our debt as or before it becomes due, 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, among other things, 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 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 the slow economic recovery, the possibility of rising interest rates and the impending significant debt maturities of numerous other borrowers. 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.

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As of December 31, 2011, a substantial amount of our long-term debt matures in the next few years, including approximately $120 million principal amount of debt maturing in 2012-2013, approximately $4.3 billion principal amount of debt maturing in 2014 and approximately $3.3 billion principal amount of debt maturing in 2015. A substantial amount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities. In April 2011, we were able to secure an extension of a significant portion of the commitments and loans under the TCEH Senior Secured Facilities. However, even after taking the extension into account, we still have a significant amount of commitments and loans under the TCEH Senior Secured Facilities that will mature in 2013 and 2014 because a significant portion of the commitments (approximately $645 million maturing in 2013) and loans (approximately $3.85 billion principal amount maturing in 2014) were not extended. In addition, notwithstanding the extension, the extended 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 two years. As a result, we have a substantial principal amount of debt that matures in 2016 (approximately $1.7 billion) and 2017 (approximately $16.7 billion, including $947 million under the TCEH Letter of Credit Facility that is held in restricted cash).

The extended 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 as of March 31, 2011 to the extent held as of the determination date), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (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 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 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. As of December 31, 2011, $3.125 billion and $1.568 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 $10.90 per MMBtu in mid-2008 to $3.94 per MMBtu at December 31, 2011 for calendar year 2013). 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 recession. 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 the long-term profitability of our generation assets. Specifically, low natural gas prices and their effect in ERCOT on wholesale electricity prices could have a material impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. As of December 31, 2011, we have hedged only approximately 58% and 31% 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 TCEH's ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt.

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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 and those of EFCH exceed our and EFCH's assets as shown on our and EFCH's respective balance sheet prepared in accordance with US GAAP as of December 31, 2011. Our reported assets include $6.152 billion of goodwill as of December 31, 2011. In 2010, we recorded a $4.1 billion noncash goodwill impairment charge 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 value of our goodwill 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. Almost all of our assets are encumbered (in some cases by both first and second liens), and we have a limited value of assets which could be used as additional collateral in future financing transactions.

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 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.

We may pursue transactions and initiatives that are unsuccessful or do not produce the desired outcome.

Future transactions and initiatives that we may pursue may have significant effects on our business, capital structure, liquidity and/or results of operations. For example, in addition to the exchanges, repurchases and extensions of our debt that are described in Note 10 to Financial Statements, we have and may continue to pursue, from time to time, transactions and initiatives of various types, including, without limitation, debt exchange transactions, debt repurchases, equity or debt issuances, debt refinancing transactions (including extensions of maturity dates of our debt), asset sales, joint ventures, recapitalizations, business combinations and other strategic transactions. 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 in a material manner. Moreover, the effects of any of these transactions or initiatives could be material and adverse to holders of our debt and could be disproportionate, and directionally different, with respect to one class or type of debt than with respect to others.

Our debt agreements and the Oncor "ring-fencing" measures contain restrictions that limit flexibility in operating our businesses.

Our debt agreements contain various covenants and other restrictions that limit our ability to engage in specified types of transactions and may adversely affect our ability to operate our businesses. 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 10 to Financial Statements for a description of these covenants and other restrictions.

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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. As of December 31, 2011, TCEH's consolidated secured debt to consolidated EBITDA ratio was 5.78 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 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. For the year ended December 31, 2012, the maximum consolidated secured debt to consolidated EBITDA ratio permitted under the TCEH Senior Secured Facilities continues to be 8.00 to 1.00.

A breach of any of these covenants or restrictions could result in an event of default under one or more of our debt agreements, including as a result of cross 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. If lenders or noteholders accelerate the repayment of all borrowings, we would likely not have sufficient assets and funds to repay those borrowings.

In addition, as described in Note 1 to Financial Statements, 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, many of which were agreed to and required by the PUCT's Order on Rehearing in Docket No. 34077, include, among other things:

• Oncor Holdings' and Oncor's board of directors being comprised of a majority of directors that are independent from the Texas Holdings Group, EFH Corp. and its other subsidiaries;

• Oncor being treated as an unrestricted subsidiary with respect to EFH Corp.'s and EFIH's debt;

• Oncor not being restricted from incurring its own debt;

• Oncor not guaranteeing or pledging any of its assets to secure the debt of any member of the Texas Holdings Group;

• restrictions on distributions by Oncor, and the right of the independent members of Oncor's board of directors and the largest non-majority member of Oncor to block the payment of distributions to Oncor Holdings (i.e., such distributions not being available to EFH Corp. under certain circumstances), and

• restrictions on the ability to sell a majority interest in Oncor until October 2012.

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, adversely affect our ability to raise additional capital and/or refinance our existing debt or require us to repay certain intercompany loans.

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 as recently as the first quarter of 2012, and may include in the future, among other things, claims that certain loans from TCEH to EFH Corp. were fraudulent transfers and should be repaid to TCEH, authorization of these loans violates the fiduciary duties of EFCH's and TCEH's boards of directors or the loans were in violation of the terms of our debt agreements. In the event a lender were to prevail on these claims, EFH Corp. may immediately be required to repay these intercompany loans to TCEH and be prevented from further borrowings under such loans. 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.

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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.

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 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.

Under the terms of the indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp. EFH Corp. may be required to repay all or a portion of the intercompany notes it owes to TCEH.

EFH Corp. is a holding company and substantially all of its reported consolidated assets are held by its subsidiaries. As of December 31, 2011, TCEH and its subsidiaries held approximately 81% of EFH Corp.'s reported consolidated assets, and for the year ended December 31, 2011, TCEH and its subsidiaries represented all of EFH Corp.'s reported consolidated revenues. Accordingly, TCEH and its subsidiaries constitute an important funding source for EFH Corp. to satisfy its obligations. However, under the terms of the indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp., except in the form of certain loans to cover certain of EFH Corp.'s obligations (and dividends and distributions in certain other limited circumstances if permitted by applicable state law). Further, the indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities do not permit such intercompany loans to service EFH Corp.'s debt unless required for EFH Corp. to pay principal, premium and interest when due on debt incurred by EFH Corp. to finance the Merger or that was in existence prior to the Merger, or any debt incurred by EFH Corp. to replace, refund or refinance such debt. Such loans are also permitted in order to service other debt, subject to limitations on the amount of the loans. In addition, TCEH is prohibited from making certain loans to EFH Corp. if certain events of default under the indentures governing the TCEH Senior Notes, Senior Secured Notes or Senior Secured Second Lien Notes or the terms of the TCEH Senior Secured Facilities have occurred and are continuing. As of the date hereof, none of these events of default has occurred or is continuing.

In addition, the TCEH Senior Secured Facilities contain provisions related to TCEH's intercompany notes receivable from EFH Corp., which are guaranteed by EFCH and EFIH on a senior unsecured basis and are demand notes, which means that TCEH can require payment of all or a portion of these notes at any time. As of February 15, 2012, the aggregate principal amount of these intercompany notes was approximately $960 million. These provisions include the following related to cash loaned by TCEH to EFH Corp. for (i) debt principal and interest payments (P&I Note) and (ii) other general corporate purposes (SG&A Note and, together with the P&I Note, the Intercompany Notes):

• TCEH will not make any further loans under the SG&A Note to EFH Corp.;

• borrowings outstanding under the P&I Note 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 Intercompany 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.

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If TCEH is not able to continue making intercompany loans to EFH Corp. as a result of the restrictions in the amendment or otherwise, EFH Corp. may not have sufficient cash flows to meet its obligations. If EFH Corp., or EFIH or EFCH (as guarantors), were not able to repay TCEH, it could negatively impact TCEH's cash flows and its ability to meet its obligations. A failure by EFH Corp. to repay the intercompany notes when required could result in defaults under EFH Corp.'s other debt, including debt that EFCH and EFIH guarantee. It would also likely result in EFCH's and EFIH's guarantees of the intercompany notes being called, which could cause defaults under EFCH's and EFIH's other debt.

Under the terms of the indentures governing the EFIH Notes, EFIH is restricted from making certain payments to EFH Corp.

EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of December 31, 2011, EFIH and its subsidiaries held approximately 13% of EFH Corp.'s reported consolidated assets, which assets consist primarily of EFIH's investment in Oncor Holdings. Accordingly, EFIH constitutes an important funding source of EFH Corp. for a significant amount of its cash flows and relies on such cash flows in order to satisfy its obligations. However, under the terms of the indentures governing the EFIH Notes, EFIH is restricted from making certain payments, including dividends and loans, to EFH Corp., except in limited circumstances.

EFH Corp. has a very limited ability to control activities at Oncor due to structural and operational "ring-fencing" measures.

EFH Corp. depends upon Oncor for a significant amount of its cash flows and relies on such cash flows in order to satisfy its obligations. However, EFH Corp. has a very limited ability to control the activities of Oncor. As part of the "ring-fencing" measures implemented by EFH Corp. and Oncor, a majority of the members of Oncor's board of directors are required to meet the New York Stock Exchange requirements for independence in all material respects, and the unanimous, or majority, consent of such directors is required for Oncor to take certain actions. In addition, any new independent directors are required to be appointed by the nominating committee of Oncor Holdings' board of directors, a majority of whose members are independent directors. No member of EFH Corp.'s management is a member of Oncor's board of directors. Under Oncor Holdings' and Oncor's organizational documents, EFH Corp. has limited indirect consent rights with respect to the activities of Oncor, including (i) new issuances of equity securities by Oncor, (ii) material transactions with third parties involving Oncor outside of the ordinary course of business, (iii) actions that cause Oncor's assets to be subject to an increased level of jurisdiction of the FERC, (iv) any changes to the state of formation of Oncor, (v) material changes to accounting methods not required by US GAAP, and (vi) actions that fail to enforce certain tax sharing obligations between Oncor and EFH Corp. In addition, Oncor's organizational agreements contain restrictions on Oncor's ability to make distributions to its members, including indirectly to EFH Corp.

Risks Related to Our Structure

EFH Corp. is a holding company and its obligations are structurally subordinated to existing and future liabilities and preferred stock of its subsidiaries.

EFH Corp.'s cash flows and ability to meet its obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to EFH Corp. in the form of dividends, distributions, loans or otherwise, and repayment of loans or advances from EFH Corp. These subsidiaries are separate and distinct legal entities and have no obligation (other than any existing contractual obligations) to provide EFH Corp. with funds for its payment obligations. Any decision by a subsidiary to provide EFH Corp. with funds for its 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. Further, the distributions that may be paid by Oncor are limited as discussed below.

Because EFH Corp. is a holding company, its obligations to its creditors are structurally subordinated to all existing and future liabilities and existing and future preferred stock of its subsidiaries that do not guarantee such obligations. Therefore, with respect to subsidiaries that do not guarantee EFH Corp.'s obligations, EFH Corp.'s rights and the rights of its 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 EFH Corp. may be a creditor with recognized claims against any such subsidiary, EFH Corp.'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 EFH Corp. Subject to restrictions contained in financing arrangements, EFH Corp.'s subsidiaries may incur additional debt and other liabilities.

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Oncor may or may not make any distributions to EFH Corp.

Upon the consummation of the Merger, EFH Corp. and Oncor implemented certain structural and operational "ring-fencing" measures, including certain measures required by the PUCT's Order on Rehearing in Docket No. 34077, that were based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor's credit quality. These measures were put in place to mitigate Oncor's credit exposure to the 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, 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.

In addition, Oncor's organizational documents limit Oncor's distributions to its owners, including EFH Corp., through December 31, 2012 to an amount not to exceed Oncor's net income (determined in accordance with US GAAP, subject to certain defined adjustments, including goodwill impairments) and 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.

In 2009, the PUCT awarded Oncor the right to construct transmission lines and facilities associated with its CREZ Transmission Plan, the cost of which is estimated by Oncor to be approximately $2.0 billion (see discussion in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters"). With the award, Oncor has incurred additional debt. In addition, Oncor may incur additional debt in connection with other investments in infrastructure or technology. Accordingly, while Oncor is required to maintain a specified debt-to-equity ratio, there can be no assurance that Oncor's equity balance will be sufficient to maintain the required debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, thereby restricting Oncor from making any distributions to EFH Corp. In addition, any increase in Oncor's interest expense may reduce the amounts available to be distributed to EFH Corp.

Oncor's ring-fencing measures may not work as planned.

In 2007, EFH Corp. and Oncor implemented certain structural and operational "ring-fencing" measures, including certain measures required by the PUCT's Order on Rehearing in Docket No. 34077, that were based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor's credit quality. These measures were put in place to mitigate Oncor's credit exposure to the Texas Holdings Group and to reduce the risk that a court would order any of the Oncor Ring-Fenced Entities' assets and liabilities to be substantively consolidated with those of any member of the Texas Holdings Group in the event that a member of the Texas Holdings Group were to become a debtor in a bankruptcy case. Nevertheless, bankruptcy courts have broad equitable powers, and as a result, outcomes in bankruptcy proceedings are inherently difficult to predict. Accordingly, if any member of the Texas Holdings Group were to become a debtor in a bankruptcy case, there can be no assurance (however remote in consideration of the ring-fencing measures) that a court would not order an Oncor Ring-Fenced Entity's assets and liabilities to be substantively consolidated with those of such member of the Texas Holdings Group or that a proceeding would not result in a disruption of services Oncor receives from or jointly with affiliates. See Note 1 to Financial Statements for additional information on ring-fencing measures.

In addition, Oncor's access to capital markets and cost of debt could be directly affected by its credit ratings. Any adverse action with respect to Oncor's credit ratings would generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease. Oncor's credit ratings are currently substantially higher than those of the Texas Holdings Group. If credit rating agencies were to change their views of Oncor's independence from any member of the Texas Holdings Group, Oncor's credit ratings would likely decline. Despite the ring-fencing measures, rating agencies could take an adverse action with respect to Oncor's credit ratings in response to liability management or other activities by EFH Corp. or any of its subsidiaries, including the incurrence of debt by EFH Corp. and/or EFIH which is secured by a lien on the equity of Oncor Holdings held by EFIH. In the event any such adverse action takes place and causes Oncor's borrowing costs to increase, it may not be able to recover these increased costs if they exceed Oncor's PUCT-approved cost of debt determined in its most recent rate case or subsequent rate cases.

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Risks Related to Our Businesses

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, construction and operation of transmission facilities, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, decommissioning costs, return on invested capital for regulated businesses, 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 next regular legislative session is scheduled to begin 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. There can be no assurance that future action of the Texas Legislature will not result in legislation that could have a material effect on our businesses.

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.

The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include coal-fueled 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 coal-fueled 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. Several bills addressing climate change have been introduced in the US Congress or discussed by the Obama Administration that are 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), 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 has issued a rule, known as the Prevention of Significant Deterioration (PSD) tailoring rule, which establishes new 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.

The EPA also announced in late 2010 its intent to promulgate GHG emission limits known as New Source Performance Standards that would apply to new and modified sources, as well as GHG emission guidelines that states might apply to existing sources of GHGs. The EPA has indicated that such new standards and guidelines would be applicable to electricity generation facilities. We cannot predict what limits or guidelines the EPA might adopt. 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 Cross-State Air Pollution Rule (CSAPR) as revised by the EPA in February 2012, we will likely incur material capital expenditures and operating costs and experience material revenue decreases due to reduced generation and wholesale power sales volumes.

In July, 2011, the EPA issued the CSAPR. In February 2012, the EPA released a final rule (Final Revisions) and a direct-to-final rule (Direct Final 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." If the EPA receives significant adverse comments on the Direct Final Rule, it will be withdrawn and its provisions considered in a proposed rule subject to normal notice-and-comment rulemaking procedures. In total, the emissions budgets established by the Final Revisions along with the Direct Final 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 is currently stayed by the D.C. Circuit Court, the Final Revisions and the Direct Final Rule do not impose any immediate legal or compliance requirements on Luminant, the State of Texas, or other affected parties. We cannot predict whether, when, or in what form the CSAPR, the Final Revisions, or the Direct Final Rule will take effect.

Material capital expenditures would be required to comply with the CSAPR, as revised in February 2012, as well as with other pending and expected environmental regulations, including MATS. In 2011, total capital expenditures for environmental projects totaled $142 million. Analysis is ongoing regarding expected capital expenditures relating to the CSAPR, the Final Revisions and the Direct Final Rule, the status of which is uncertain given the pending legal proceeding, and the final MATS rule, which was published in February 2012. We currently estimate that total capital expenditures related to the CSAPR, the Final Revisions, the Direct Final Rule, MATS, and other environmental regulations will be approximately $300 million in 2012. Prior to the publication of the final MATS rule, 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 are currently evaluating this estimate in light of the final MATS rule, the Final Revisions and the Direct Final Rule.

We cannot predict (i) whether the legal challenge to the CSAPR will be ultimately successful on the merits, (ii) when the D.C. Circuit Court will issue a final ruling on the validity of the CSAPR and/or (iii) the effective date of the CSAPR if it is ultimately implemented. As a result, there can be no assurance that we will not be required to implement a CSAPR compliance plan 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.

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.

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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 Investigations and 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.

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 (our largest business) is not guaranteed any rate of return on capital investments in its businesses. We market and trade electricity and natural gas, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale markets operation. TCEH's results of operations depend in large part upon wholesale market prices for electricity, natural gas, uranium, coal 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;

• 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.

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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 2011, are dependent in significant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008 (from $10.90 per MMBtu in mid-2008 to $3.94 per MMBtu at December 31, 2011 for calendar year 2013). 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 recession. 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.

The percentage of our wholesale natural gas price exposure that is hedged declines significantly in future periods, which could result in reduced earnings (and related cash flows) and adversely affect our ability to pay principal and interest on our debt in those periods and refinance our debt if wholesale natural gas prices do not increase.

Our hedging activities, in particular our natural gas price hedging program, are designed to mitigate the adverse effect on earnings (and related cash flows) of low wholesale electricity prices (due to low natural gas prices). These market conditions are challenging to the long-term profitability of our generation assets. Specifically, low natural gas prices and their effect in ERCOT on wholesale power prices could have a material impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. While we have significantly hedged our natural gas price exposure for 2012 (approximately 86% under CAIR regulation), as of December 31, 2011, we have hedged only approximately 58% and 31% of our wholesale natural gas price exposure related to expected generation output for 2013 and 2014, respectively, and do not have any significant amounts of hedges in place for periods after 2014.

Forward natural gas prices have generally trended downward since mid-2008. 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 recession. 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. 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 TCEH's ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt. Consequently, our ability to fund our operations, meet our obligations under our debt agreements, refinance or extend our substantial indebtedness and obtain additional financing in the future is dependent on increases in the current and expected future price of natural gas.

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 natural gas prices, or market heat rates 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.

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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, 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 collateral requirements for hedging arrangements could be materially impacted if the 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, substantial portions of the legislation are currently under rulemakings by federal governmental agencies to implement the standards set out in the legislation and adopt new standards.

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives 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, entities are exempt from these clearing requirements if they (i) are not "Swap Dealers" or "Major Swap Participants" as will be defined in the rulemakings and (ii) use the swaps to hedge or mitigate commercial risk. The proposed definition of Swap Dealer is broad and will, as drafted, include many end users. We are evaluating whether or not the type of asset-backed OTC derivatives that we use to hedge commodity and interest rate risk is exempt from the clearing requirements. Existing swaps are grandfathered from the clearing requirements. The legislation mandates significant reporting and compliance requirements for any entity that is determined to be a Swap Dealer or Major Swap Participant.

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. 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 rulemakings to implement the OTC derivative market provisions of the Financial Reform Act. These rulemakings 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;

• 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 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 and delivery facilities involves significant risks that could adversely affect our results of operations, liquidity and financial condition.

The operation and maintenance of electricity generation and delivery 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 and transmission and distribution 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 on our investment in the project or improvement.

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.

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Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material effect on our results of operations, liquidity and financial condition.

Many of our facilities were constructed many years ago and require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could materially affect our results of operations, liquidity and financial condition.

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.

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 transmission and distribution system or 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 been experiencing sustained, severe drought conditions that may 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.

The rates of Oncor's electricity delivery business are subject to regulatory review, and may be reduced below current levels, which could adversely impact Oncor's results of operations, liquidity and financial condition.

The rates charged by Oncor are regulated by the PUCT and certain cities and are subject to cost-of-service regulation and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Oncor's rates are regulated based on an analysis of Oncor's costs and capital structure, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge all of Oncor's costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that Oncor's rates are based upon, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of Oncor's costs, including regulatory assets reported on Oncor's balance sheet, and the return on invested capital allowed by the PUCT. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters" for discussion of recent and pending rate-related filings with the PUCT.

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In addition, in connection with the Merger, Oncor made several commitments to the PUCT regarding its rates. For example, Oncor committed that it will, in rate cases after its 2008 general rate case through proceedings initiated prior to December 31, 2012, support a cost of debt that will be no greater than the then-current cost of debt of electric utilities with investment grade credit ratings equal to Oncor's ratings as of October 1, 2007. As a result, Oncor may not be able to recover all of its debt costs if they are above those levels.

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 intend to take steps to reduce our costs. While we have a number of initiatives underway 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.

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. Recently 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 and transmission and distribution 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 as is reflected in a 17% decline in customers (based on meters) served over the last three 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.

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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.

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.

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 its customers, its 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/or Oncor's electricity delivery 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.

Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of our generation assets and electricity delivery facilities. 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 invest in conservation measures.

44

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

EFH Corp.'s (or any subsidiary's) credit ratings could negatively affect EFH Corp.'s (or such subsidiary's) ability to access capital and could require EFH Corp. or its subsidiaries to post collateral or repay certain indebtedness.

EFH Corp.'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 EFH Corp.'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 EFH Corp. or any of its subsidiaries, including the issuance of additional debt or the consummation of additional debt exchanges, could result in temporary or permanent downgrades of EFH Corp.'s or its subsidiaries' credit ratings.

Most of EFH Corp.'s large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us. If EFH Corp.'s (or any subsidiary's) credit ratings decline, the costs to operate its businesses would likely increase because counterparties could require the posting of collateral in the form of cash or cash-related instruments, or counterparties could decline to do business with EFH Corp. (or such subsidiary).

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 liquidity 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 liquidity 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 liquidity facilities could be adversely impacted by various factors, such as:

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

• economic weakness in the ERCOT or general US market;

• changes in interest rates;

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

• a reduction in EFH Corp.'s or its applicable subsidiaries' credit ratings;

• a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our liquidity 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 liquidity facilities.

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Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of the natural gas price 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. While these potential posting obligations are primarily supported by our liquidity facilities, for certain transactions there is a potential for the timing of postings on the commodity contract obligations to vary from the timing of borrowings from the TCEH Commodity Collateral Posting Facility. Any perceived reduction in our creditworthiness could result in clearing agents or other counterparties requesting additional collateral. We have credit concentration risk related to the limited number of lenders that provide liquidity to support our hedging program. A deterioration of the creditworthiness of such lenders could materially affect our ability to continue such program on acceptable terms. 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 liquidity facilities are being used largely to support the natural gas price 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 its natural gas price hedging program.

The costs of providing pension and OPEB and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material effect on our results of operations, liquidity and financial condition.

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

The values of the investments that fund our 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 18 to Financial Statements for further discussion of our pension and OPEB plans.

As discussed in Note 5 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 to write off some or all of this goodwill and other intangible assets, which may cause adverse impacts on our results of operations and financial condition.

In accordance with accounting standards, goodwill and certain other indefinite-lived intangible assets that are not subject to amortization are reviewed annually or more frequently for impairment, if certain conditions exist, and may be impaired. 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.

46

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 Capital, L.P. and GS Capital Partners, each of which acts independently of the others with respect to its investment in EFH Corp. and Texas Holdings.

Additionally, 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.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

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Item 3. LEGAL PROCEEDINGS

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 seek a reversal of the TCEQ's order and a remand back to the TCEQ for further proceedings. In addition to this administrative appeal, in November 2010, two other petitions were filed in Travis County, Texas District Court by Sustainable Energy and Economic Development Coalition and Paul and Lisa Rolke, respectively, who were non-parties to the administrative hearing before the State Office of Administrative Hearings, challenging the TCEQ's decision to renew and amend Oak Grove's TPDES permit and asking the District Court to remand the matter to the TCEQ for further proceedings. In January 2012, the petition filed by Paul and Lisa Rolke was dismissed. Although we cannot predict the outcome of these proceedings, we believe that the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and that the application for and the processing of Oak Grove's TPDES permit renewal and amendment by the TCEQ were in accordance with applicable law. There can be no assurance that the outcome of these matters would not result in an adverse impact on our results of operations, liquidity or financial condition.

In January 2012, the Sierra Club filed a petition in Travis County, Texas District Court challenging the TCEQ's decision to issue permit amendments imposing limits on emissions during planned startup, shutdown and maintenance activities at Luminant's Big Brown, Monticello, Martin Lake and Sandow Unit 4 generation facilities. Although we cannot predict the outcome of this proceeding, we believe that the permit amendments are protective of the environment and in accordance with applicable law. There can be no assurance that the outcome of this matter would not result in an adverse impact on our results of operations, liquidity or financial condition.

In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violations of the Clean Air Act at Luminant's Martin Lake generation facility. While we are unable to estimate any possible loss or predict the outcome of the litigation, we believe that the Sierra Club's claims are without merit, and we intend to vigorously defend this litigation. The litigation is currently stayed by the court. In addition, in February 2010, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Big Brown generation facility. Subsequently, in December 2010, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Monticello generation facility. In October 2011, the Sierra Club again informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Big Brown and Monticello generation facilities. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

See Items 1 and 2, "Business and Properties – Environmental Regulations and Related Considerations – Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions – Cross-State Air Pollution Rule" for discussion of our petition for review in the D.C. Circuit Court challenging the CSAPR and a motion to stay the effective date of the CSAPR, in each case as applied to Texas.

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

Other Matters

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, is 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 regulatory agencies such as the RRC. The MSHA inspects US mines, including ours, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Disclosure of MSHA citations, orders and proposed assessments 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

EFH Corp.'s common stock is privately held and has no established public trading market.

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

The number of holders of EFH Corp.'s common stock of as of February 20, 2012 was 120.

Item 6. SELECTED FINANCIAL DATA

EFH CORP. AND SUBSIDIARIES SELECTED CONSOLIDATED FINANCIAL DATA (millions of dollars, except ratios)
	Successor															Predecessor
	Year Ended December 31,												Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
	2011			2010			2009			2008
Operating revenues	$	7,040		$	8,235		$	9,546		$	11,364		$	1,994		$	8,044
Impairment of goodwill	—			(4,100		)	(90		)	(8,860		)	—			—
Income (loss) from continuing operations	(1,913		)	(2,812		)	408			(9,998		)	(1,361		)	699
Income from discontinued operations, net of tax effect	—			—			—			—			1			24
Net income (loss)	(1,913		)	(2,812		)	408			(9,998		)	(1,360		)	723
Net (income) loss attributable to noncontrolling interests	—			—			(64		)	160			—			—
Net income (loss) attributable to EFH Corp.	(1,913		)	(2,812		)	344			(9,838		)	(1,360		)	723
Ratio of earnings to fixed charges (a)	—			—			1.24			—			—			2.30
Cash provided by (used in) operating activities from continuing operations	841			1,106			1,711			1,505			(450		)	2,265
Cash provided by (used in) financing activities from continuing operations	(1,014		)	(264		)	422			2,837			33,865			1,394
Cash used in investing activities from continuing operations	(535		)	(468		)	(2,633		)	(2,934		)	(34,563		)	(2,283		)
Capital expenditures, including nuclear fuel	$	684		$	944		$	2,545		$	3,015		$	716		$	2,542

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EFH CORP. AND SUBSIDIARIES SELECTED CONSOLIDATED FINANCIAL DATA (CONTINUED) (millions of dollars, except ratios)
	As of December 31,
	2011			2010			2009			2008			2007
Total assets	$	44,077		$	46,388		$	59,662		$	59,263		$	64,804
Property, plant & equipment — net	$	19,427		$	20,366		$	30,108		$	29,522		$	28,650
Goodwill and intangible assets	$	7,997		$	8,552		$	17,192		$	17,379		$	27,319
Investment in unconsolidated subsidiary (Note 2)	$	5,720		$	5,544		$	—		$	—		$	—
Capitalization
Long-term debt, less amounts due currently	$	35,360		$	34,226		$	41,440		$	40,838		$	38,603
EFH Corp. common stock equity	(7,852		)	(5,990		)	(3,247		)	(3,673		)	6,685
Noncontrolling interests in subsidiaries	95			79			1,411			1,355			—
Total	$	27,603		$	28,315		$	39,604		$	38,520		$	45,288
Capitalization ratios
Long-term debt, less amounts due currently	128.1		%	120.9		%	104.6		%	106.0		%	85.2		%
EFH Corp. common stock equity	(28.4		)%	(21.2		)%	(8.2		)%	(9.5		)%	14.8		%
Noncontrolling interests in subsidiaries	0.3		%	0.3		%	3.6		%	3.5		%	—		%
Total	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%
Short-term borrowings	$	774		$	1,221		$	1,569		$	1,237		$	1,718
Long-term debt due currently	$	47		$	669		$	417		$	385		$	513

___________

(a) Fixed charges exceeded earnings (see Exhibit 12(a)) by $3.217 billion, $2.531 billion, $10.469 billion and $2.034 billion for the years ended December 31, 2011, 2010 and 2008 and the period from October 11, 2007 through December 31, 2007, respectively.

Note: Although EFH Corp. continued as the same legal entity after the Merger, its "Selected Financial Data" for periods preceding the Merger and for periods succeeding the Merger are presented as the consolidated financial statements of the "Predecessor" and the "Successor," respectively. See Note 1 to Financial Statements "Basis of Presentation." The consolidated financial statements of the Successor reflect the application of "purchase accounting." Results for 2010 reflect the prospective adoption of amended guidance regarding consolidation accounting standards related to variable interest entities that resulted in the deconsolidation of Oncor Holdings as discussed in Note 3 to Financial Statements 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 9 to Financial Statements. Results for 2011 were significantly impacted by an impairment charge related to emissions allowance intangible assets as discussed in Note 4 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 5 to Financial Statements and debt extinguishment gains as discussed in Notes 8 and 10. 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.

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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.

	First Quarter			Second Quarter			Third Quarter (a)			Fourth Quarter
2011:
Operating revenues	$	1,672		$	1,679		$	2,321		$	1,368
Net loss	$	(362	)	$	(705	)	$	(710	)	$	(136	)

	First Quarter		Second Quarter			Third Quarter (b)			Fourth Quarter
2010:
Operating revenues	$	1,999	$	1,993		$	2,607		$	1,636
Net income (loss)	$	355	$	(426	)	$	(2,902	)	$	161

___________

(a) Net loss includes the effect of an impairment charge related to emissions allowance intangible assets (see Note 4 to Financial Statements).

(b) Net loss includes the effect of a goodwill impairment charge (see Note 5 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 fiscal years ended December 31, 2011, 2010 and 2009 should be read in conjunction with Selected Financial Data and our audited consolidated financial statements and the notes to those statements. Unless otherwise noted, disclosures in the following paragraphs related to hedged or estimated generation output and commodity price sensitivities reflect the expected effects on our operations of the currently governing CAIR. See Items 1 and 2, "Environmental Regulations and Related Considerations" for discussion of the CSAPR, including the judicial stay of the CSAPR, related litigation and the EPA's revisions.

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

Business

EFH Corp., a Texas corporation, is a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. EFCH and its direct subsidiary, TCEH, are wholly-owned. 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. EFIH is wholly-owned and indirectly holds an approximately 80% equity interest in Oncor. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Various "ring-fencing" measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 3 to Financial Statements for discussion of the material features of these "ring-fencing" measures and the reporting of our investment in Oncor (and its majority owner, Oncor Holdings) as an equity method investment effective January 1, 2010.

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment consists largely of TCEH. The Regulated Delivery segment consists largely of our investment in Oncor . See Notes 1 and 3 to Financial Statements for discussion of the deconsolidation of Oncor and its parent, Oncor Holdings, effective in 2010.

See Note 21 to Financial Statements for further information regarding reportable business segments.

Significant Activities and Events

Natural Gas Prices and 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. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2011, has effectively sold forward approximately 700 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 82,000 GWh at an assumed 8.5 market heat rate) at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.

These transactions, together with forward power sales, have effectively hedged an estimated 86%, 58% and 31% of the price exposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2012, 2013 and 2014, respectively, (assuming an 8.5 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will generally move with prices of natural gas, which is expected 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 22% of the positions in the natural gas price hedging program as of December 31, 2011, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the natural gas price hedging program.

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The following table summarizes the natural gas positions in the hedging program as of December 31, 2011:

	Measure	2012	2013	2014	Total
Natural gas hedge volumes (a)	mm MMBtu	~294	~254	~149	~697
Weighted average hedge price (b)	$/MMBtu	~7.36	~7.19	~7.80	—
Weighted average market price (c)	$/MMBtu	~3.24	~3.94	~4.34	—
Realization of hedge gains (d)	$ billions	~$1.7	~$0.9	~$0.5	~$3.1

___________

(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 137 million MMBtu in 2014.

(b) Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the natural gas price hedging program (excluding the impact of offsetting purchases for rebalancing). 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 as of December 31, 2011.

Changes in the fair value of the instruments in the natural gas price hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the natural gas price hedging program as of December 31, 2011, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $700 million in pretax unrealized mark-to-market gains or losses.

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

	Year Ended December 31,
	2011			2010		2009
Realized net gain	$	1,265		$	1,151	$	752
Unrealized net gain (loss) including reversals of previously recorded amounts related to positions settled	(19		)	1,165		1,107
Total	$	1,246		$	2,316	$	1,859

The cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging program totaled $3.124 billion and $3.143 billion as of December 31, 2011 and 2010, respectively.

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

The significant cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging program reflects declining forward market natural gas prices. Forward natural gas prices have generally trended downward since mid-2008. 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 the long-term profitability of our generation assets. Specifically, these lower natural gas prices and their effect in ERCOT on wholesale electricity prices could have a material impact on the overall profitability of our generation assets for periods in which we have less significant natural gas hedge positions (i.e., beginning in 2014).

Also see discussion below regarding the goodwill impairment charge recorded in 2010.

As of December 31, 2011, approximately 90% of the natural gas price hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH's assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility – see discussion below under "Financial Condition — Liquidity and Capital Resources"), thereby reducing the cash and letter of credit collateral requirements for the hedging program.

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See discussion below under "Key Risks and Challenges," specifically, "Substantial Leverage, Uncertain Financial Markets and Liquidity Risk" and "Natural Gas Price and Market Heat Rate Exposure."

Impairment of Goodwill— In the third quarter 2010, we recorded a $4.1 billion noncash goodwill impairment charge (which was not deductible for income tax purposes) related to the Competitive Electric segment. The write-off reflected the estimated effect of lower wholesale power prices on the enterprise value of the Competitive Electric segment, driven by the sustained decline in forward natural gas prices as discussed above. Recorded goodwill related to the Competitive Electric segment totaled $6.2 billion as of December 31, 2011.

The noncash impairment charge did not cause EFH Corp. 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 5 to Financial Statements and "Application of Critical Accounting Policies" below for more information on goodwill impairment testing and charges.

Liability Management Program — As of December 31, 2011, EFH Corp. and its consolidated subsidiaries had $36.0 billion principal amount of long-term debt outstanding. In October 2009, we implemented a liability management program designed to reduce debt and extend debt maturities through debt exchanges, repurchases and extensions. Activities under the liability management program do not include debt issued by Oncor or its subsidiaries.

Amendments to the TCEH Senior Secured Facilities completed in April 2011 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 $1.4 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016.

Other liability management activities from inception of the program in October 2009 through December 2011 include debt exchange, issuance and repurchase activities as follows (except where noted, debt amounts are principal amounts):

	Since Inception
Security	Debt Acquired		Debt Issued/ Cash Paid
EFH Corp 10.875% Notes due 2017	$	1,804	$	—
EFH Corp. Toggle Notes due 2017	2,661		53
EFH Corp. 5.55% Series P Senior Notes due 2014	674		—
EFH Corp. 6.50% Series Q Senior Notes due 2024	10		—
EFH Corp. 6.55% Series R Senior Notes due 2034	6		—
TCEH 10.25% Notes due 2015	1,875		—
TCEH Toggle Notes due 2016	751		—
TCEH Senior Secured Facilities due 2013 and 2014	1,623		—
EFH Corp. and EFIH 9.75% Notes due 2019	—		256
EFH Corp 10% Notes due 2020	—		561
EFIH 11% Notes due 2021	—		406
EFIH 10% Notes due 2020	—		2,180
TCEH 15% Notes due 2021	—		1,221
TCEH 11.5% Notes due 2020 (a)	—		1,604
Cash paid, including use of proceeds from debt issuances in 2010 (b)	—		1,062
Total	$	9,404	$	7,343

___________

(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 $100 million of the proceeds from the January 2010 issuance of $500 million principal amount of EFH Corp. 10% Notes due 2020 and $290 million of the proceeds from the October 2010 issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021. The total $390 million of proceeds was used to repurchase debt.

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Since inception, the transactions in the liability management program resulted in the capture of $2 billion of debt discount and the extension of approximately $23.5 billion of debt maturities to 2017-2021.

Liability management program activities in 2011 included the amendment and extension of the TCEH Senior Secured Facilities discussed above, as well as $2.143 billion principal amount of debt acquired and $2.209 billion principal amount of debt issued. In February 2012, EFIH and EFIH Finance issued $800 million principal amount of 11.750% Senior Secured Second Lien Notes due 2022. The net proceeds will be used for general corporate purposes, including the payment of a $650 million dividend to EFH Corp., which was used to repay a portion of the demand notes payable by EFH Corp. to TCEH. The balance of the demand notes payable totaled approximately $960 million at February 15, 2012, reflecting the repayment. Also see "Key Risks and Challenges – Substantial Leverage, Uncertain Financial Markets and Liquidity Risk" and Note 10 to Financial Statements.

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

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

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

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

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

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

ERCOT previously had a zonal wholesale market structure consisting of four geographic zones. The new location-based congestion-management market is referred to as a "nodal" market because wholesale pricing differs across the various nodes on the transmission grid instead of across the geographic zones. There are over 500 nodes in the ERCOT market. The nodal market design was implemented in conjunction with transmission improvements designed to reduce current congestion. We are fully certified to participate in both the "day-ahead" and "real-time markets." Additionally, all of our operational generation assets and our qualified scheduling entities are certified and operate in the nodal market. Since the opening of the nodal market, the amount of letters of credit posted with ERCOT to support our market participation has fluctuated between $125 million and $425 million based upon weekly settlement activity, and as of December 31, 2011, totaled $170 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 (loss) from commodity hedging and trading activities. As a result of these changes, reported wholesale revenues and purchased power costs (and the associated volumes) in 2011 were materially less than amounts reported in prior periods.

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TCEHInterest Rate Swap Transactions — As reflected in the table below, as of December 31, 2011, 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 2012 through October 2014	$18.65 billion (a)
6.8% — 9.0%	October 2015 through October 2017	$12.60 billion (b)

___________

(a) Includes swaps entered into in 2011 related to an aggregate $5.45 billion principal amount of debt growing to $10.58 billion over time, generally as existing swaps expire. Swaps related to an aggregate $2.60 billion principal amount of debt expired or were terminated in 2011. Taking into consideration these swap transactions, as of December 31, 2011, 2% of our long-term debt portfolio is exposed to variable interest rate risk to October 2014.

(b) These swaps were all entered into in 2011 and are effective from October 2014 through October 2017. The swaps include $3 billion that expires in October 2015 and the remainder 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 (through swaps) borrowing costs. Basis swaps in effect at December 31, 2011 related to an aggregate of $17.75 billion principal amount of senior secured debt maturing from 2012 through 2014, an increase of $2.55 billion from December 31, 2010 reflecting new and expired swaps. A forward-starting basis swap was entered into in 2011 related to an aggregate $1.42 billion principal amount of senior secured debt effective for a 21-month period beginning February 2012.

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

	Year Ended December 31,
	2011			2010			2009
Realized net loss	$	(684	)	$	(673	)	$	(684	)
Unrealized net gain (loss)	(812		)	(207		)	696
Total	$	(1,496	)	$	(880	)	$	12

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.231 billion and $1.419 billion as of December 31, 2011 and 2010, respectively, of which $76 million and $105 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. For example, as of December 31, 2011, a one percent change in interest rates would result in an increase or decrease of approximately $900 million in our cumulative unrealized mark-to-market net liability. See discussion in Note 10 to Financial Statements regarding interest rate swap transactions.

Construction of New Lignite-Fueled Generation Units — In 2010, TCEH completed a program to construct three lignite-fueled generation units (2 units at the Oak Grove plant site and 1 unit at the Sandow plant site) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow and first Oak Grove units achieved substantial completion (as defined in the EPC agreement) in the fourth quarter 2009, and the second Oak Grove unit achieved substantial completion (as defined in the EPC agreement) in the second quarter 2010. We began depreciating the units and recognizing revenues and fuel costs for accounting purposes in those respective periods. Aggregate cash capital expenditures for these three units totaled approximately $3.25 billion including all construction, site preparation and mining development costs. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, totaled approximately $4.8 billion.

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

As of December 31, 2011, Oncor had installed 2,302,000 advanced digital meters, including 788,000 in 2011. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $518 million as of December 31, 2011, including $158 million in 2011. Oncor expects to complete installations of the remaining approximately 700,000 advanced meters by the end of 2012.

Oncor Rate Review Filed with the PUCT — In January 2011, Oncor filed for a rate review with the PUCT and 203 cities based on a test year ended June 30, 2010. In August 2011 the PUCT issued a final order in the rate review. The rate review as approved includes an approximate $137 million base rate increase and additional provisions to address certain expenses. Approximately $93 million of the increase became effective July 1, 2011, and the remainder became effective January 1, 2012. The rate review did not change Oncor's authorized regulatory capital structure of 60% debt and 40% equity or its authorized return on equity of 10.25%. See "Regulatory Matters" below for further discussion.

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

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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, 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 $36.7 billion as of December 31, 2011, and cash interest payments in 2011 totaled $3 billion.

Significant amounts of our long-term debt mature in the next few years, including approximate principal amounts of $120 million in 2012-2013, $4.3 billion in 2014 and $3.3 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 principle amount of debt under these facilities to 2017. 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 (see Note 10 to Financial Statements).

While we believe our cash on hand and cash flow from operations combined with availability under existing credit facilities provide sufficient liquidity to fund current and projected expenses and capital requirements for 2012, 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, as a result of the financial crisis that arose in 2008 and continued market and regulatory uncertainty, there has been a reduction of available counterparties for 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 - Natural Gas Prices and Natural Gas Price Hedging Program."

We are focused on improving the balance sheet and expect to opportunistically look for ways to reduce the amount, and extend the maturity, of our outstanding debt and maintain adequate liquidity. Progress to date on this initiative includes the debt extensions, exchanges, issuances and repurchases completed in 2009 through 2011, which resulted in the extension of approximately $23.5 billion of debt maturities to 2017-2021, and the 2012 issuance of $800 million principal amount of 11.750% Senior Secured Second Lien Notes due 2022 in 2012. We have also hedged a substantial portion of variable rate debt exposure through 2017 using interest rate swaps. See "Significant Activities and Events - Liability Management Program" and Note 10 to Financial Statements.

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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 been declining, reflecting discovery and increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic recession.

	Forward Market Prices for Calendar Year ($/MMBtu) (a)
Date	2012		2013		2014		2015		2016
December 31, 2008	$	7.23	$	7.15	$	7.15	$	7.21	$	7.30
March 31, 2009	$	6.96	$	7.11	$	7.18	$	7.25	$	7.33
June 30, 2009	$	7.16	$	7.30	$	7.43	$	7.57	$	7.71
September 30, 2009	$	7.00	$	7.06	$	7.17	$	7.31	$	7.43
December 31, 2009	$	6.53	$	6.67	$	6.84	$	7.05	$	7.24
March 31, 2010	$	5.79	$	6.07	$	6.36	$	6.68	$	7.00
June 30, 2010	$	5.68	$	5.89	$	6.10	$	6.37	$	6.68
September 30, 2010	$	5.07	$	5.29	$	5.42	$	5.60	$	5.76
December 31, 2010	$	5.08	$	5.33	$	5.49	$	5.64	$	5.79
March 31, 2011	$	5.06	$	5.41	$	5.73	$	6.08	$	6.41
June 30, 2011	$	4.84	$	5.16	$	5.42	$	5.70	$	5.98
September 30, 2011	$	4.24	$	4.80	$	5.13	$	5.39	$	5.61
December 31, 2011	$	3.24	$	3.94	$	4.34	$	4.60	$	4.85

___________

(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 2011, increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect on wholesale electricity prices in ERCOT.

The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate 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 mix of generation assets resulting from generation capacity changes such as additions and retirements of generation facilities in ERCOT. 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 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 and liquidity risk, and

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

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As discussed above in "Significant Activities and Events," 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 power sales. As of December 31, 2011, 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 pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH's unhedged position and forward prices as of December 31, 2011, 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 2012 (a)	2013	2014	2015	2016
$1.00/MMBtu change in gas price (b)	$ ~75	$ ~220	$ ~365	$ ~530	$ ~525
0.1/MMBtu/MWh change in market heat rate (c)	$ ~10	$ ~30	$ ~35	$ ~40	$ ~40
$1.00/gallon change in diesel fuel price	$ ~10	$ ~45	$ ~45	$ ~45	$ ~45

___________

(a) Balance of 2012 is from February 1, 2012 through December 31, 2012.

(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 as of December 31, 2011.

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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.

New and Changing Environmental Regulations

We are subject to various environmental laws and regulations related to SO2, NOx 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 passed 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 11 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 increased 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."

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Competitive Retail Markets and Customer Retention

Competitive retail activity in Texas has resulted in retail customer churn. Our total retail customer counts declined 9% in 2011, 6% in 2010 and 3% in 2009. Based upon 2011 results discussed below in "Results of Operations – Competitive Electric Segment," a 1% decline in residential customers would result in a decline in annual revenues of approximately $35 million. In responding to the competitive landscape in the ERCOT marketplace, we are focusing on the following key initiatives:

• Maintaining competitive pricing initiatives on most 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. TXU Energy has completed over 60% of its planned $100 million investment in retail initiatives aimed at helping consumers conserve energy and other 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 a new customer management system implemented in 2009, new product price/service offerings and a multichannel approach for the small business market.

Financial Services Reform Legislation

In July 2010, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act) was enacted. 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, substantial portions of the legislation are currently under rulemakings by federal governmental agencies to implement the standards set out in the legislation and adopt new standards.

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives 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, entities are exempt from these clearing requirements if they (i) are not "Swap Dealers" or "Major Swap Participants" as will be defined in the rulemakings and (ii) use the swaps to hedge or mitigate commercial risk. The proposed definition of Swap Dealer is broad and will, as drafted, include many end users. We are evaluating whether or not the type of asset-backed OTC derivatives that we use to hedge commodity and interest rate risk is exempt from the clearing requirements. Existing swaps are grandfathered from the clearing requirements. The legislation mandates significant reporting and compliance requirements for any entity that is determined to be a Swap Dealer or Major Swap Participant.

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. 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 rulemakings to implement the OTC derivative market provisions of the Financial Reform Act. These rulemakings 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.

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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 market prices as of December 31, 2011) to be approximately $2 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 11 to Financial Statements.

The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review and regulation by the NRC, 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.

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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.

Volatile Energy Prices and Regulatory Risk

Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in retail electricity prices elevated public awareness of energy costs and dampened customer demand. Natural gas prices remain subject to events that create price volatility, and while not reaching 2005 levels, natural gas prices rose substantially in 2007 and part of 2008 before falling in the second half of 2008 through 2011. Sustained high energy prices and/or ongoing price volatility also creates a risk for regulatory and/or legislative intervention with the mechanisms that govern the competitive wholesale and retail markets in ERCOT to provide lower or more predictable prices. Sustained low energy prices also create a risk of such intervention if, in an effort to incent investment to provide sufficient generation resources to be available to meet future demand, regulators or legislators take actions that impact the competitive markets.

We believe that competitive markets result in a broad range of innovative pricing and service alternatives to consumers and ultimately the most efficient use of resources and that regulatory entities should continue to take actions that encourage competition in the industry. Regulatory and/or legislative intervention could materially affect the competitive electricity industry in ERCOT, including disrupting the relationship between natural gas prices and electricity prices, which could materially impact the results of our natural gas price hedging program. (Also see "Regulatory Matters – Sunset Review.") We continue to closely monitor any potential legislative and regulatory changes and work with legislators and regulators, providing them information on the market and related matters.

Oncor's Ring-Fencing and Credit Risk

Our investment in Oncor, which represents approximately 80% of its membership interests, is a significant value driver of our overall business. Oncor's access to capital markets and cost of debt could be directly affected by its credit ratings. Any adverse action with respect to Oncor's credit ratings would generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease. Oncor's credit ratings are currently substantially higher than those of the Texas Holdings Group. If credit rating agencies were to change their views of Oncor's independence from any member of the Texas Holdings Group, Oncor's credit ratings would likely decline. We believe these risks are substantially mitigated by the significant ring-fencing measures implemented by EFH Corp. and Oncor as described in Note 1 to Financial Statements.

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Declining Reserve Margins and Weather Extremes

Planning reserve margin is the difference between system generation capability and anticipated peak load. As reflected in the table below, ERCOT is projecting declining reserve margins in the ERCOT market such that by 2014, the margin will be substantially below ERCOT's minimum reserve planning criterion of 13.75%. Weather extremes exacerbate the risks of inadequate reserve margins.

	2012		2013		2014		2015		2016
Firm load forecast (MW)	64,618		65,428		68,174		71,457		73,713
Resources forecast (MW)	73,574		73,327		73,383		73,992		76,833
Reserve margin (a)	13.86	%	12.07	%	7.64	%	3.55	%	4.23	%

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(a) Source: ERCOT's "Report on the Capacity, Demand, and Reserves in the ERCOT Region - December 2011." The 2012 resource forecast and reserve margin reflect an update presented in the January 17, 2012 ERCOT Board of Directors meeting that includes our Monticello Units 1 and 2 due to the stay of the CSAPR, which is discussed in Items 1 and 2, "Business and Properties - Environmental Regulations and Related Considerations." Reserve margin (planning) = (Resources forecast - Firm load forecast) / Firm load forecast.

We and the ERCOT market broadly experienced the effects of weather extremes in 2011. Severe cold weather in North Texas impacted the availability of generation capacity in ERCOT, including certain of our generation units, resulting in electricity outages and reduced customer satisfaction, as well as loss of revenues and higher costs in our competitive business 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. 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, 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 plant equipment maintenance and readiness to increase system reliability and help ensure generation availability. We are actively focused on implementing the learnings from the winter and summer peaks of 2011 and are developing plans to assure the highest possible delivery of generation during critical periods, delivering demand side management responses and assuring we utilize our 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.

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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 and transmission 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.

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 expected long-term decline in natural gas prices and/or market heat rates. We evaluate investments in unconsolidated subsidiaries for impairment when factors indicate that a decrease in the value of the investment has occurred that is not temporary. Indications of a loss in value might include a series of operating losses of the investee or a fair value of the investment that is less than its carrying amount. 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, group of assets or investment in unconsolidated subsidiary. 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 units, which are our two segments: Competitive Electric and Regulated Delivery, and goodwill impairment testing is performed at the reporting unit level. (See Notes 1 and 3 to Financial Statements for discussion of the deconsolidation of Oncor Holdings as of January 1, 2010, which resulted in a reduction in reported goodwill for the amount related to the Regulated Delivery segment, and see above for discussion of impairment testing for equity-method investments such as Oncor Holdings.) 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 company values taking into consideration any recent pending and/or completed relevant transactions. 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. Another key variable in the income approach is the discount rate, or weighted average cost of capital. The determination of the discount rate takes into consideration the capital structure, debt ratings and current debt yields of comparable 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 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 inputs in developing the best estimate of enterprise value.

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Since the Merger, we have recorded goodwill impairment charges totaling $13.050 billion; including $4.1 billion recorded in 2010 and $8.950 billion (including $860 million related to the Regulated Delivery segment) recorded largely in 2008. The total impairment charges represent approximately 60% of the goodwill balance resulting from purchase accounting for the Merger. The impairment in 2010 reflected the estimated effect of lower wholesale power prices in ERCOT on the enterprise value of the Competitive Electric segment, 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 5 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 14 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 as of December 31, 2011, 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 are being 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 are being marked-to-market in net income. See further discussion of the natural gas price hedging program and interest rate swap transactions under "Business – Significant Activities and Events."

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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. (Excludes the effects related to Oncor since its deconsolidation effective January 1, 2010).

	Year Ended December 31,
	2011			2010			2009
Amounts recognized in net income or net loss (after-tax):
Unrealized net gains on positions marked-to-market in net income	$	205		$	1,257		$	1,573
Unrealized net losses representing reversals of previously recognized fair values of positions settled in the period	(696		)	(606		)	(332		)
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	(19		)	(59		)	(130		)
Total net gain (loss) recognized	$	(510	)	$	667		$	1,111
Amounts recognized in other comprehensive income or loss (after-tax):
Net losses in fair value of positions accounted for as cash flow hedges	$	—		$	—		$	(20	)
Reclassifications of net losses on cash flow hedge positions to net income	19			59			130
Total net gain recognized	$	19		$	59		$	110

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

	December 31,
	2011			2010
Commodity contract assets	$	4,435		$	4,705
Commodity contract liabilities	$	(1,245	)	$	(1,608	)
Interest rate swap assets	$	142		$	98
Interest rate swap liabilities	$	(2,397	)	$	(1,544	)
Net accumulated other comprehensive loss included in shareholders' equity (amounts after tax)	$	(50	)	$	(69	)

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 16 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 the non-active derivative. (See Note 14 to Financial Statements for additional discussion of how broker quotes are utilized.)

Level 3 valuations generally apply to congestion revenue rights, options to purchase or sell power and our more complex long-term power purchases and sales agreements, including longer term wind power purchase contracts. 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 $124 million and $401 million as of December 31, 2011 and 2010, respectively, and represented approximately 2% and 8%, respectively, of the assets measured at fair value, or less than 1% of total assets in both years. Level 3 liabilities totaled $71 million and $59 million as of December 31, 2011 and 2010, 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. As of December 31, 2011 and 2010, a $5.00 per MWh change in electricity price assumptions across unobservable inputs would cause an approximate $5 million change in net Level 3 assets. A 10% change in coal price assumptions across unobservable inputs would cause an approximate $21 million change in net Level 3 assets. See Note 14 to Financial Statements for additional information about fair value measurements, including a table presenting the changes in Level 3 assets and liabilities for the twelve months ended December 31, 2011, 2010 and 2009.

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 and resulted in the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor. 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 Notes 2 and 3 to Financial Statements for our analysis of the Oncor relationship and 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 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 $269 million, $297 million and $546 million as of December 31, 2011, 2010 and 2009, 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 competitive retail operations, totaled $56 million, $108 million and $113 million for the years ended December 31, 2011, 2010 and 2009, 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, 2011. See Item 3, "Legal Proceedings" for discussion of significant litigation.

Accounting for Income Taxes

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 judgments and estimates 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. Our 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.

In 2010, we reduced our liability for uncertain tax positions by $162 million as a result of negotiations with the IRS. This reduction consisted of a $225 million reversal of accrued interest ($146 million after-tax), partially offset by a $63 million reclassification to net deferred tax liabilities. Upon conclusion of all issues contested with the IRS from that 1997 through 2002 audit, which could occur by the end of 2012, we expect to reduce the liability for uncertain tax positions by approximately $700 million with an offsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes. Any cash income tax liability related to the conclusion of the 1997 through 2002 audit is expected to be immaterial. The IRS audit for the years 2003 through 2006 was concluded in June 2011. A significant number of proposed adjustments are in appeals with the IRS. The results of the audit did not affect management's assessment of issues for purposes of determining the liability for uncertain tax positions. See Notes 1, 6 and 7 to Financial Statements for discussion of income tax matters.

Depreciation and Amortization

Depreciation expense related to generation facilities is based on the estimates of fair value and economic useful lives as determined in the application of purchase accounting for the Merger. The accuracy of these estimates directly affects the amount of depreciation expense. 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 21 to 58 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 5 to Financial Statements for additional information.

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Defined Benefit Pension Plans and OPEB Plans

We provide pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provide certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from our company. Reported costs of providing noncontributory defined pension benefits and OPEB are dependent upon numerous factors, assumptions and estimates.

PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility. These costs are associated with Oncor's active and retired employees, as well as active and retired personnel engaged in other EFH Corp. activities related to their service prior to the deregulation and disaggregation of our business effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs reflected in Oncor's approved (by the PUCT) billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Accordingly, Oncor defers (principally as a regulatory asset or property) additional pension and OPEB costs consistent with PURA. Amounts deferred are ultimately subject to regulatory approval.

Benefit costs are impacted by actual and actuarial estimates of 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. Actuarial assumptions are reviewed and updated annually based on current economic conditions and trends. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

In accordance with accounting rules, changes in benefit obligations associated with these factors may not be immediately recognized as costs in the income statement, but are recognized in future years over the remaining average service period of plan participants. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Pension and OPEB costs as determined under applicable accounting rules are summarized in the following table:

	Year Ended December 31,
	2011			2010			2009
Pension costs	$	141		$	100		$	44
OPEB costs	94			80			70
Total benefit costs	$	235		$	180		$	114
Less amounts expensed by Oncor (and not consolidated)	(37		)	(37		)	—
Less amounts deferred principally as a regulatory asset or property by Oncor	(130		)	(93		)	(66		)
Net amounts recognized as expense	$	68		$	50		$	48
Discount rate (a)	5.50		%	5.90		%	6.90		%

___________

(a) Discount rate for OPEB was 5.55%, 5.90% and 6.85% in 2011, 2010 and 2009, respectively.

See Note 18 to Financial Statements regarding other disclosures related to pension and OPEB obligations.

Sensitivity of these costs to changes in key assumptions is as follows:

Assumption	Increase/ (decrease) in 2011 Pension and OPEB Costs
Discount rate – 1% increase	$	(49	)
Discount rate – 1% decrease	$	57
Expected return on assets – 1% increase	$	(24	)
Expected return on assets – 1% decrease	$	24

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RESULTS OF OPERATIONS

Effects of Change in Wholesale Electricity Market

As discussed above under "Significant Activities and Events," the nodal wholesale market design implemented by ERCOT in December 2010 resulted in operational changes that facilitate hedging and trading of power. As part of ERCOT's transition to a nodal wholesale market, volumes under nontrading bilateral purchase and sales contracts are no longer scheduled as physical power with ERCOT. As a result of these changes in market operations, reported wholesale revenues and purchased power costs in 2011 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 (loss) from commodity hedging and trading activities.

Consolidated Financial Results — Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

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

In 2010, a $4.1 billion impairment of goodwill was recorded in the Competitive Electric segment as discussed in Note 5 to Financial Statements.

See Note 8 to Financial Statements for details of other income and deductions.

Interest expense and related charges increased $740 million, or 21%, to $4.294 billion in 2011. Interest paid/accrued increased $346 million to $3.027 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, $58 million in higher amortization of debt issuance and amendment costs and discounts and $29 million in lower capitalized interest, partially offset by a $227 million decrease in interest accrued or paid with additional toggle notes due to debt exchanges and repurchases and $60 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting.

Income tax benefit totaled $1.134 billion on a pretax loss in 2011 compared to income tax expense totaling $389 million on a pretax gain in 2010, excluding the $4.1 billion nondeductible goodwill impairment charge. The effective rate was 34.0% and 27.8% in 2011 and 2010, respectively, excluding the goodwill impairment charge. The increase in the rate was driven by a $146 million reversal in 2010 of previously accrued interest related to uncertain tax positions due to expected resolution of matters related to the 1997 through 2002 tax audit.

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) increased $9 million to $286 million in 2011 reflecting improved results at Oncor due to higher revenue rates and the effects of warmer weather, partially offset

by higher depreciation and operation and maintenance expense.

Net loss decreased$899 million to $1.913 billion in 2011.

• Net loss in the Competitive Electric segment decreased $1.638 billion to $1.825 billion.

• Earnings from the Regulated Delivery segment increased $9 million to $286 million as discussed above.

• After-tax results of Corporate and Other activities totaled $374 million in net expense in 2011 compared to net income of $374 million in 2010. The amounts in 2011 and 2010 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The $748 million change reflected a $693 million (after tax) decrease in debt extinguishment gains (reported in other income) and the $121 million Corporate and Other portion of the 2010 reversal of previously accrued interest on uncertain tax positions discussed above, partially offset by an $86 million (after tax) decrease in interest expense and related charges driven by the effects of the liability management program.

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Consolidated Financial Results — Year Ended December 31, 2010 Compared to Pro Forma Year Ended December 31, 2009

As the result of deconsolidation of Oncor Holdings effective 2010, the results of Oncor Holdings are reflected in the 2010 consolidated statement of income as equity in earnings of unconsolidated subsidiary (net of tax) instead of separately as revenues and expenses as they are shown for periods prior to January 1, 2010. The following pro forma results for the year ended December 31, 2009 are presented to provide for a meaningful comparison of 2010 to 2009 results, along with the analyses on the following pages, of EFH Corp.'s consolidated operating results in consideration of the deconsolidation of Oncor Holdings as discussed in Notes 1 and 3 to Financial Statements.

	Year Ended December 31, 2010			Year Ended December 31, 2009
				As Reported			Pro Forma Adjustments (a)			Pro Forma
	(millions of dollars)
Operating revenues	$	8,235		$	9,546		$	(1,632	)	$	7,914
Fuel, purchased power costs and delivery fees	(4,371		)	(2,878		)	(1,058		)	(3,936		)
Net gain from commodity hedging and trading activities	2,161			1,736			—			1,736
Operating costs	(837		)	(1,598		)	908			(690		)
Depreciation and amortization	(1,407		)	(1,754		)	557			(1,197		)
Selling, general and administrative expenses	(751		)	(1,068		)	193			(875		)
Franchise and revenue-based taxes	(106		)	(359		)	250			(109		)
Impairment of goodwill	(4,100		)	(90		)	—			(90		)
Other income	2,051			204			(50		)	154
Other deductions	(31		)	(97		)	34			(63		)
Interest income	10			45			(1		)	44
Interest expense and related charges	(3,554		)	(2,912		)	306			(2,606		)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries	(2,700		)	775			(493		)	282
Income tax (expense) benefit	(389		)	(367		)	173			(194		)
Equity in earnings of unconsolidated subsidiaries (net of tax)	277			—			256			256
Net income (loss)	(2,812		)	408			(64		)	344
Net income attributable to noncontrolling interests	—			(64		)	64			—
Net income (loss) attributable to EFH Corp.	$	(2,812	)	$	344		$	—		$	344

___________

(a) All pro forma adjustments relate to Oncor Holdings and result in the presentation of the investment in Oncor Holdings under the equity method of accounting for the year ended December 31, 2009.

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

SG&A expenses decreased $124 million, or 14%, to $751 million in 2010 driven by $66 million in lower transition costs associated with outsourced support services and the retail customer information system implemented in 2009, $18 million in lower employee compensation-related expense and $12 million of accounts receivable securitization program fees that are reported as interest expense and related charges in 2010 (see Notes 9 and 22 to Financial Statements).

See Note 5 to Financial Statements for discussion of the $4.1 billion impairment of goodwill recorded in the Competitive Electric segment in 2010. The $90 million impairment of goodwill recorded in 2009 largely related to the Competitive Electric segment and resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter 2008.

75

Other income totaled $2.051 billion in 2010 and $154 million in 2009. Debt extinguishment gains totaled $1.814 billion and $87 million in 2010 and 2009, respectively (see discussion of debt exchanges and repurchases in Note 10 to Financial Statements). The 2010 amount also included a $116 million gain on termination of a long-term power sales contract, a $44 million gain on sale of land and related water rights and a $37 million gain on sale of interests in a natural gas gathering pipeline business. The 2009 amount included $23 million of income arising from the reversal of a use tax accrual recorded in purchase accounting related to periods prior to the Merger, which was triggered by a state ruling in the third quarter 2009, and $11 million of income arising from the reversal of exit liabilities recorded in purchase accounting due to sooner than expected transition of outsourcing services (see Note 8 to Financial Statements).

Other deductions totaled $31 million in 2010 and $63 million in 2009. The 2009 amount included an impairment charge of $34 million related to land expected to be sold. See Note 8 to Financial Statements for details of other income and deductions.

Interest income decreased $34 million, or 77%, to $10 million in 2010 reflecting lower interest on $465 million in collateral under a funding arrangement, due to settlement of the arrangement as described in Note 16 to Financial Statements.

Interest expense and related charges increased $948 million to $3.554 billion in 2010 reflecting a $207 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $696 million net gain in 2009 and a $214 million decrease in capitalized interest due to completion of new generation facility construction activities, partially offset by $97 million in decreased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges, reflecting values attributed to earlier periods, as well as lower interest expense resulting from reduced debt under the liability management program as described above under "Significant Activities and Events." Also, see Note 22 to Financial Statements.

Income tax expense totaled $389 million in 2010 compared to $194 million in 2009. Excluding the effects of the $4.1 billion and $90 million nondeductible goodwill impairment charges in 2010 and 2009, respectively, the effective tax rates were 27.8% in 2010 and 52.2% in 2009. The decrease in the effective tax rate in 2010 was driven by lower interest accrued related to uncertain tax positions, including the effect of a $146 million reversal of previously accrued interest (see Note 6 to Financial Statements) net of the effect of an $8 million deferred tax charge related to the Patient Protection and Affordable Care Act (see Note 7 to Financial Statements).

Equity in earnings of unconsolidated subsidiaries (net of tax) increased $21 million to $277 million in 2010 driven by improved earnings of Oncor, which reflected higher revenues, primarily due to weather effects and rate increases, and the effect of a $25 million write off of regulatory assets in 2009, partially offset by increased noncash expenses recognized as a result of the PUCT's final order in the June 2008 rate review.

The consolidated net loss of $2.812 billion in 2010 represented a $3.156 billion decrease in results.

• Results in the Competitive Electric segment decreased $4.094 billion to a loss of $3.463 billion.

• Earnings from the Regulated Delivery segment increased $21 million to $277 million as discussed above.

• Corporate and Other net income totaled $374 million in 2010 compared to net expenses of $543 million in 2009. The amounts in 2010 and 2009 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The change of $917 million reflected $670 million in higher debt extinguishment gains in 2010, the $121 million Corporate and Other portion of the 2010 reversal of accrued interest on uncertain tax positions discussed above, $68 million in lower SG&A expense primarily reflecting lower transition costs associated with outsourced support services and costs allocated to the competitive operations effective 2010 and a $20 million goodwill impairment charge in 2009, partially offset by an $8 million deferred tax charge due to the implementation of the Patient Protection and Affordable Care Act in 2010 (all amounts after-tax).

Non-GAAP Earnings Measures

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

76

Competitive Electric Segment

Financial Results

	Year Ended December 31,
	2011			2010			2009
Operating revenues	$	7,040		$	8,235		$	7,911
Fuel, purchased power costs and delivery fees	(3,396		)	(4,371		)	(3,934		)
Net gain from commodity hedging and trading activities	1,011			2,161			1,736
Operating costs	(924		)	(837		)	(693		)
Depreciation and amortization	(1,471		)	(1,380		)	(1,172		)
Selling, general and administrative expenses	(728		)	(722		)	(741		)
Franchise and revenue-based taxes	(96		)	(106		)	(108		)
Impairment of goodwill	—			(4,100		)	(70		)
Other income	45			903			59
Other deductions	(526		)	(21		)	(68		)
Interest income	87			91			64
Interest expense and related charges	(3,830		)	(2,957		)	(1,946		)
Income (loss) before income taxes	(2,788		)	(3,104		)	1,038
Income tax (expense) benefit	963			(359		)	(407		)
Net income (loss)	$	(1,825	)	$	(3,463	)	$	631

77

Competitive Electric Segment

Sales Volume and Customer Count Data

	Year Ended December 31,						2011		2010
	2011		2010		2009		% Change		% Change
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential	27,337		28,208		28,046		(3.1	)	0.6
Small business (a)	7,059		8,042		7,962		(12.2	)	1.0
Large business and other customers	12,828		15,339		14,573		(16.4	)	5.3
Total retail electricity	47,224		51,589		50,581		(8.5	)	2.0
Wholesale electricity sales volumes (b)	34,496		51,359		42,320		(32.8	)	21.4
Total sales volumes	81,720		102,948		92,901		(20.6	)	10.8
Average volume (kWh) per residential customer (c)	16,100		15,532		14,855		3.7		4.6
Weather (North Texas average) – percent of normal (d):
Cooling degree days	132.7	%	108.9	%	98.1	%	21.9		11.0
Heating degree days	109.7	%	116.6	%	105.8	%	(5.9	)	10.2
Customer counts:
Retail electricity customers (end of period and in thousands) (e):
Residential	1,625		1,771		1,862		(8.2	)	(4.9	)
Small business (a)	185		217		262		(14.7	)	(17.2	)
Large business and other customers	19		20		23		(5.0	)	(13.0	)
Total retail electricity customers	1,829		2,008		2,147		(8.9	)	(6.5	)

___________

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

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

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

(d) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over a 10-year period.

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

78

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Year Ended December 31,						2011 %  Change		2010 %  Change
	2011		2010		2009
Operating revenues:
Retail electricity revenues:
Residential	$	3,377	$	3,663	$	3,806	(7.8	)	(3.8	)
Small business (a)	896		1,052		1,164		(14.8	)	(9.6	)
Large business and other customers	997		1,211		1,261		(17.7	)	(4.0	)
Total retail electricity revenues	5,270		5,926		6,231		(11.1	)	(4.9	)
Wholesale electricity revenues (b) (c)	1,482		2,005		1,383		(26.1	)	45.0
Amortization of intangibles (d)	18		16		5		12.5		—
Other operating revenues	270		288		292		(6.3	)	(1.4	)
Total operating revenues	$	7,040	$	8,235	$	7,911	(14.5	)	4.1
Net gain from commodity hedging and trading activities:
Realized net gains on settled positions	$	971	$	1,008	$	459	(3.7	)	—
Unrealized net gains	40		1,153		1,277		(96.5	)	(9.7	)
Total	$	1,011	$	2,161	$	1,736	(53.2	)	24.5

___________

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

(b) Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which we deem "unrealized." (The offsetting differences between contract and market prices are reported in net gain (loss) from commodity hedging and trading activities.) The decreases in 2011 reflect the change in reporting of bilateral contracts under the nodal market. These amounts are as follows:

	Year Ended December 31,
	2011		2010			2009
Reported in revenues	$	—	$	(28	)	$	(166	)
Reported in fuel and purchased power costs	18		96			114
Net gain (loss)	$	18	$	68		$	(52	)

(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.

79

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Year Ended December 31,									2011 %  Change		2010 %  Change
	2011			2010			2009
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	160		$	159		$	121		0.6		31.4
Lignite/coal	984			910			670			8.1		35.8
Total nuclear and lignite/coal	1,144			1,069			791			7.0		35.1
Natural gas fuel and purchased power (a)	434			1,502			1,224			(71.1	)	22.7
Amortization of intangibles (b)	111			161			285			(31.1	)	(43.5	)
Other costs	309			187			202			65.2		(7.4	)
Fuel and purchased power costs	1,998			2,919			2,502			(31.6	)	16.7
Delivery fees (c)	1,398			1,452			1,432			(3.7	)	1.4
Total	$	3,396		$	4,371		$	3,934		(22.3	)	11.1
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:
Nuclear fuel	$	8.30		$	7.89		$	5.98		5.2		31.9
Lignite/coal (d)	$	20.03		$	19.19		$	16.47		4.4		16.5
Natural gas fuel and purchased power (e)	$	51.88		$	43.95		$	44.36		18.0		(0.9	)
Delivery fees per MWh	$	29.52		$	28.06		$	28.09		5.2		(0.1	)
Production and purchased power volumes (GWh):
Nuclear	19,283			20,208			20,104			(4.6	)	0.5
Lignite/coal	58,165			54,775			45,684			6.2		19.9
Total nuclear- and lignite/coal-fueled generation (f)	77,448			74,983			65,788			3.3		14.0
Natural gas-fueled generation	1,233			1,648			2,447			(25.2	)	(32.7	)
Purchased power (g)	3,039			26,317			24,666			(88.5	)	6.7
Total energy supply volumes	81,720			102,948			92,901			(20.6	)	10.8
Capacity factors (f):
Nuclear	95.7		%	100.3		%	100.0		%	(4.6	)	0.3
Lignite/coal	83.5		%	82.2		%	86.5		%	1.6		(5.0	)
Total	86.2		%	86.6		%	90.3		%	(0.5	)	(4.1	)

___________

(a) See note (b) on previous page.

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

(c) Includes delivery fee charges from Oncor that prior to 2010 were eliminated in consolidation.

(d) Includes depreciation and amortization of lignite mining assets (except for incremental depreciation due to the CSAPR as discussed in Note 4 to Financial Statements), which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.

(e) Excludes volumes related to line loss and power imbalances.

(f) Includes the estimated effects of 4,290 GWh, 3,536 GWh and 2,486 GWh of economic backdown of lignite/coal-fueled units in 2011, 2010 and 2009, respectively, due to low wholesale electricity market prices.

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

80

Competitive Electric Segment – 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 decreased revenues by $501 million and was driven by declines in the large and small business and residential markets. Business volumes decreased 15% reflecting reduced contract signings driven by competitive activity. Residential 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 decreased 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 $74 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:

	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.

81

Operating costs increased $87 million, or 10%, to $924 million in 2011. The increase reflected $48 million in higher nuclear 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 facilities reflecting the retirement of nine units in 2010.

Depreciation and amortization increased $91 million, or 7%, to $1.471 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 planned mine closures to comply with the CSAPR by January 1, 2012 (see Note 4 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 5 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 benefits expenses and $16 million in higher information technology and other services costs, partially offset by $52 million in lower retail bad debt expense reflecting improved collection initiatives and customer mix.

In 2010, a $4.1 billion impairment of goodwill was recorded as discussed in Note 5 to Financial Statements.

Other income totaled $45 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.

Other deductions totaled $526 million in 2011 and $21 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 4, 8 and 10 to Financial Statements.

Interest expense and related charges increased $873 million, or 30%, to $3.830 billion in 2011. Interest paid/accrued increased $276 million to $2.531 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, $64 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 $963 million on a pretax loss in 2011 compared to income tax expense totaling $359 million on a pretax gain in 2010 before the nondeductible goodwill impairment charge. The effective rate was 34.5% and 36.0% 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 for the segment declined $1.638 billion to $1.825 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.

82

Competitive Electric Segment – Financial Results – Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Operating revenues increased $324 million, or 4%, to $8.235 billion in 2010.

Wholesale electricity revenues increased $622 million, or 45%, to $2.005 billion in 2010. A 21% increase in wholesale electricity sales volumes, reflecting production from the new generation units and increased sales to third-party REPs, increased revenues by $332 million. An 8% increase in average wholesale electricity prices, reflecting higher natural gas prices at the time the underlying contracts were executed, increased revenues by $149 million. The balance of the revenue increase reflected lower unrealized losses in 2010 related to physical derivative commodity sales contracts as discussed in footnote (b) to the "Revenue and Commodity Hedging and Trading Activities" table above.

Retail electricity revenues decreased $305 million, or 5%, to $5.926 billion and reflected the following:

• Lower average pricing decreased revenues by $429 million reflecting declines in both the business and residential markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

• A 2% increase in sales volumes increased revenues by $124 million reflecting increases in both the business and residential markets. A 4% increase in business markets sales volumes reflected a change in customer mix resulting from contracts executed with new customers. Residential sales volumes increased 1% reflecting higher average consumption driven by colder winter weather and hotter summer weather, partially offset by a decline in residential customer counts.

Fuel, purchased power costs and delivery fees increased $437 million, or 11%, to $4.371 billion in 2010. Higher purchased power costs contributed $255 million to the increase and reflected increased planned generation unit outages and higher retail demand, as well as increased prices driven by the effect of higher natural gas prices at the time the underlying contracts were executed. Other factors contributing to the increase included $126 million in higher lignite/coal costs at existing plants, reflecting higher purchased coal transportation and commodity costs, $114 million in increased lignite fuel costs related to production from the new generation units, a $39 million increase in nuclear fuel expense reflecting increased uranium and conversion costs, a $23 million increase in natural gas and fuel oil costs driven by higher prices, $20 million in higher delivery fees, reflecting increased retail sales volumes and tariffs, and an $18 million decrease in unrealized gains related to physical derivative commodity purchase contracts. These increases were partially offset by $124 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting, which reflected expiration of commodity contracts and consumption of the nuclear fuel.

Overall nuclear and lignite/coal-fueled generation production increased 14% in 2010 driven by production from the new generation units. Nuclear production increased 1%, and existing lignite/coal-fueled generation decreased 2% driven by increased economic backdown.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the years ended December 31, 2010 and 2009, which totaled $2.161 billion and $1.736 billion, respectively:

	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

	Year Ended December 31, 2009
	Net Realized Gains		Net Unrealized Gains		Total
Hedging positions	$	449	$	1,260	$	1,709
Trading positions	10		17		27
Total	$	459	$	1,277	$	1,736

83

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 $68 million in net gains in 2010 and $52 million in net losses in 2009.

Operating costs increased $144 million, or 21%, to $837 million in 2010. The increase reflected $90 million in incremental expense related to the new generation units. The balance of the increase was driven by installation and maintenance of emissions control equipment at the existing lignite/coal-fueled generation facilities and higher maintenance costs at both the nuclear and existing lignite/coal-fueled facilities reflecting timing and scope of project work.

Depreciation and amortization increased $208 million, or 18%, to $1.380 billion in 2010. The increase reflected $162 million in incremental expense related to the new generation units and associated mining operations. The balance of the increase was driven by equipment additions.

SG&A expenses decreased $19 million, or 3%, to $722 million in 2010. The decrease reflected:

• $31 million in lower transition costs associated with outsourced services and the retail customer information management system implemented in 2009;

• $16 million in lower employee compensation-related expense in 2010;

• $12 million of accounts receivable securitization program fees that are reported in 2010 as interest expense and related charges (see Note 9 to Financial Statements), and

• $8 million in lower bad debt expense,

partially offset by $46 million of costs allocated from corporate in 2010, principally fees paid to the Sponsor Group.

See Note 5 to Financial Statements for discussion of the $4.1 billion impairment of goodwill recorded in 2010 and of the $70 million impairment of goodwill recorded in 2009 that resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008.

Other income totaled $903 million in 2010 and $59 million in 2009. 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. The 2009 amount included a $23 million reversal of a use tax accrual, an $11 million reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements and $25 million in several individually immaterial items. See Note 8 to Financial Statements.

Other deductions totaled $21 million in 2010 and $68 million in 2009. The 2010 amount included several individually immaterial items. The 2009 amount included $34 million in charges for the impairment of land expected to be sold, $7 million in severance charges and other individually immaterial miscellaneous expenses. See Note 8 to Financial Statements.

Interest income increased $27 million, or 42%, to $91 million in 2010 reflecting higher notes receivable balances from affiliates.

Interest expense and related charges increased by $1.011 billion, or 52%, to $2.957 billion in 2010 reflecting a $207 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $696 million net gain in 2009 and a $214 million decrease in capitalized interest due to completion of new generation facility construction activities, partially offset by a $97 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges.

Income tax expense totaled $359 million in 2010 compared to $407 million in 2009. Excluding the $4.1 billion and $70 million nondeductible goodwill impairment charges in 2010 and 2009, respectively, the effective tax rates were 36.0% and 36.7%, respectively.

Results for the segment decreased $4.094 billion in 2010 to a loss of $3.463 billion reflecting the $4.1 billion goodwill impairment charge and increased interest expense, partially offset by debt extinguishment gains and an increase in net gains from commodity hedging and trading activities.

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

The table below summarizes the changes in commodity contract assets and liabilities for the periods presented. The net change in these assets and liabilities, excluding "other activity" as described below, reflects the $58 million, $1.219 billion and $1.223 billion in unrealized net gains in 2011, 2010 and 2009, 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,
	2011			2010			2009
Commodity contract net asset as of beginning of period	$	3,097		$	1,718		$	430
Settlements of positions (a)	(1,081		)	(943		)	(518		)
Changes in fair value of positions in the portfolio (b)	1,139			2,162			1,741
Other activity (c)	35			160			65
Commodity contract net asset as of end of period	$	3,190		$	3,097		$	1,718

__________

(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 gains and losses recognized, primarily related to positions in the natural gas price hedging program (see discussion above under "Natural Gas Prices and Natural Gas Price Hedging Program"). 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 and physical natural gas exchange transactions. The 2011 amount relates to purchases and expirations of options. 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 as of December 31, 2011, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract asset as of December 31, 2011
Source of fair value:	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(21	)	$	(30	)	$	—		$	—		$	(51	)
Prices provided by other external sources	1,721			1,467			—			—			3,188
Prices based on models	50			3			—			—			53
Total	$	1,750		$	1,440		$	—		$	—		$	3,190
Percentage of total fair value	55		%	45		%	—		%	—		%	100		%

The "prices actively quoted" category reflects only exchange-traded contracts for which active quotes are readily available. The "prices provided by other external sources" category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West hub) generally extend through 2014 and over-the-counter quotes for natural gas generally extend through 2016, depending upon delivery point. The "prices based on models" category contains the value of all non-exchange-traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 14 to Financial Statements for fair value disclosures and discussion of fair value measurements.

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FINANCIAL CONDITION

Liquidity and Capital Resources

Operating Cash Flows

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 — Cash provided by operating activities decreased $265 million to $841 million in 2011. The change included the effect of amended accounting standards related to the accounts receivable securitization program (see Note 9 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 $648 million, which 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 $300 million increase in interest payments, partially offset by the contribution from the new lignite-fueled generation units (see Results of Operations). A $408 million increase in net margin deposits received from counterparties was substantially offset by a $249 million decrease in net cash received from Oncor in the form of income tax payments and distributions. A $109 million income tax refund was paid to Oncor in 2011 for overpayments in 2010 related to federal taxes.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash provided by operating activities declined $605 million to $1.106 billion in 2010. The deconsolidation of Oncor in 2010 reduced reported cash provided by operating activities by $932 million. The decrease also reflected a $350 million effect of the amended accounting standard related to the accounts receivable securitization program (see Note 9 to Financial Statements), under which the $383 million of funding under the program upon the January 1, 2010 adoption is reported as a use of operating cash flows and a source of financing cash flows, with subsequent 2010 activity reported as financing, and the $33 million decline in funding in 2009 is reported as use of operating cash flows. These accounting effects were partially offset by improved working capital performance, particularly in retail accounts receivable due to the effects in 2009 of implementing a new customer information management system and more timely collections in 2010, as well as higher cash earnings from the competitive business driven by the contribution of the new generation units.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $244 million, $282 million and $345 million for the years ended December 31, 2011, 2010 and 2009, 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, 2011 Compared to Year Ended December 31, 2010 — Cash used in financing activities totaled $1.014 billion and $264 million in 2011 and 2010, respectively. 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 10 to Financial Statements. Activity in 2010 reflected the net repayment of debt as part of the liability management program, partially offset by 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.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash used in financing activities totaled $264 million in 2010 compared to cash provided of $422 million in 2009. The $686 million change was driven by debt repurchases under our liability management program (see Note 10 to Financial Statements), partially offset by 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 10 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, 2011 Compared to Year Ended December 31, 2010 — Cash used in investing activities totaled $535 million and $468 million in 2011 and 2010, respectively. Investing activities in 2010 reflected the return of a $400 million cash investment posted with a derivative counterparty in 2009. Capital expenditures (excluding nuclear fuel) decreased $286 million to $552 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 $684 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

• $72 million for information technology, nuclear generation development and other corporate investments.

Reported cash capital expenditures in 2011 were reduced by $24 million of reimbursements from the DOE related to dry cask storage. We expect to continue 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. A claim was filed with the DOE in late 2011 for an additional $19 million of such allowable costs.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash used in investing activities totaled $468 million and $2.633 billion in 2010 and 2009, respectively. Capital expenditures (excluding nuclear fuel) totaled $838 million and $2.348 billion in 2010 and 2009, respectively. The $1.510 billion decline in capital spending reflected the deconsolidation of Oncor ($998 million capital expenditures in 2009) (see Note 3 to Financial Statements) in 2010 and a decrease in spending related to the construction of the now complete new generation facilities. The decline in cash used in investing activities also reflected a $400 million cash investment posted with a derivative counterparty in 2009 that was returned in 2010.

Capital expenditures, including nuclear fuel, in 2010 totaled $944 million and consisted of:

• $487 million for major maintenance, primarily in existing generation operations;

• $140 million related to completion of the construction of a second generation unit and mine development at Oak Grove;

• $106 million for environmental expenditures related to existing generation units;

• $106 million for nuclear fuel purchases;

• $42 million for information technology and other corporate investments;

• $34 million related to nuclear generation development, and

• $29 million primarily related to the new retail customer information system.

Debt Financing Activity— Activities related to short-term borrowings and long-term debt during the year ended December 31, 2011 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

	Borrowings (a)		Repayments and Repurchases (b)
TCEH	$	1,912	$	(1,439	)
EFCH	—		(8		)
EFIH	406		—
EFH Corp.	97		(511		)
Total long-term	2,415		(1,958		)
Total short-term – TCEH (c)	—		(455		)
Total	$	2,415	$	(2,413	)

___________

(a) Includes $665 million of noncash principal increases, including $406 million of EFIH debt and $53 million of EFH Corp. Toggle Notes issued in debt exchanges discussed in Note 10 to Financial Statements and $162 million of TCEH Toggle Notes and $43 million of EFH Corp. Toggle Notes issued in payment of accrued interest as discussed below under "Toggle Notes Interest Election."

(b) Includes $527 million of noncash retirements primarily consisting of $493 million of EFH Corp. debt exchanged as discussed in Note 10 to Financial Statements.

(c) Short-term amounts represent net borrowings/repayments under the TCEH Revolving Credit Facility.

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See Note 10 to Financial Statements for further detail of long-term debt and other financing arrangements, including $47 million of debt due currently (within 12 months) as of December 31, 2011.

We regularly monitor the capital and bank credit markets for liability management opportunities that we believe will improve our balance sheet, including capturing debt discount and extending debt maturities. As a result, we may engage, from time to time, in liability management transactions. Future activities under the liability management program may include the purchase of our outstanding debt for cash in open market purchases or privately negotiated refinancing, extension and exchange transactions (including pursuant to a Section 10b-5(1) plan) or via public or private exchange or tender offers.

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

Available Liquidity — The following table summarizes changes in available liquidity for the year ended December 31, 2011:

	Available Liquidity
	December 31, 2011		December 31, 2010		Change
Cash and cash equivalents	$	826	$	1,534	$	(708	)
TCEH Revolving Credit Facility (a)	1,384		1,440		(56		)
TCEH Letter of Credit Facility	169		261		(92		)
Total liquidity	$	2,379	$	3,235	$	(856	)

___________

(a) In connection with the April 2011 amendment and extension of the TCEH Senior Secured Facilities, this facility now has a limit of $2.054 billion, and there were $670 million of borrowings as of December 31, 2011.

In February 2012, EFIH and EFIH Finance issued $800 million principal amount of 11.750% Senior Secured Second Lien Notes due 2022. The net proceeds will be used for general corporate purposes, including the payment of a $650 million dividend to EFH Corp., which was used to repay a portion of the demand notes payable by EFH Corp. to TCEH. The demand notes payable totaled approximately $960 million as of February 15, 2012, reflecting the repayment. See Note 10 to Financial Statements. TCEH used the $650 million it received from EFH Corp. to repay borrowings under the TCEH Revolving Credit Facility.

Available liquidity decreased $856 million in 2011 reflecting $857 million in financing related cash transaction costs, largely related to the April 2011 amendment and extension of the TCEH Senior Secured Facilities. Other significant cash flows included $841 million in cash provided by operating activities, which reflected $540 million of margin deposits received from counterparties, and $684 million in capital expenditures and nuclear fuel purchases. The net effect of other financing related cash activity was not material.

Secured Debt Capacity—As of February 15, 2012, EFH Corp. believes that it and its subsidiaries (excluding the Oncor Ring-Fenced Entities) are permitted under their applicable debt agreements to issue additional senior secured debt (in each case, subject to certain exceptions and conditions set forth in their applicable debt documents) as follows:

• EFH Corp. and EFIH collectively are permitted to issue up to approximately $2.15 billion of additional aggregate principal amount of debt secured by EFIH's equity interest in Oncor Holdings (of which approximately $500 million can be on a first-priority basis and the remainder on a second-priority basis);

• TCEH is permitted to issue approximately $2.63 billion of additional aggregate principal amount of debt secured by substantially all of the assets of TCEH and certain of its subsidiaries (of which $750 million can be on a first-priority basis and the remainder on a second-priority basis), and

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

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These amounts are estimates based on EFH Corp.'s current interpretation of the covenants set forth in its and its subsidiaries' applicable debt agreements and do not take into account exceptions in the agreements that may allow for the incurrence of additional secured debt, including, but not limited to, acquisition debt, coverage ratio 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 a change in the debt agreement that results from negotiations with new or existing lenders. In addition, covenants included in agreements governing additional, future debt may impose greater restrictions on the incurrence of secured debt by EFH Corp. and its subsidiaries. Consequently, the actual amount of senior secured debt that EFH Corp. and its subsidiaries are permitted to incur under their respective debt agreements could be materially different than the amounts provided above. Also see “Risk Factors - Risks Related to Substantial Indebtedness.”

Liquidity Needs, Including Capital Expenditures — Capital expenditures and nuclear fuel purchases for 2012 are expected to total approximately $975 million and include:

• $650 million for investments in TCEH generation facilities, including approximately:

• $350 million for major maintenance and

• $300 million for environmental expenditures related to the CSAPR, MATS and other environmental regulations;

• $225 million for nuclear fuel purchases and

• $100 million for information technology, nuclear generation development and other corporate investments.

We expect cash flows from operations combined with availability under our credit facilities discussed in Note 10 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.

Pension and OPEB Plan Funding — We made pension and OPEB contributions of $176 million and $26 million, respectively, in 2011, of which an aggregate $190 million was contributed by Oncor. Pension and OPEB plan funding is expected to total $124 million and $24 million, respectively, in 2012, including approximately $140 million to be funded by Oncor.

See Note 18 to Financial Statements for more information regarding the pension and OPEB plans, including the funded status of the plans as of December 31, 2011.

Toggle Notes Interest Election — EFH Corp. and TCEH have the option every six months at their discretion, ending with the interest payment due November 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. We elected to do so beginning with the May 2009 interest payment as an efficient and cost-effective method to further enhance liquidity. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.

EFH Corp. made its 2011, 2010 and 2009 interest payments and will make its May 2012 interest payment on the EFH Corp. Toggle Notes by using the PIK feature of those notes. During the applicable interest periods, the interest rate on these notes is increased from 11.25% to 12.00%. Accordingly, in lieu of cash interest, EFH Corp. issued additional EFH Corp. Toggle Notes to nonaffiliates totaling $43 million, $194 million and $309 million aggregate principal amount in 2011, 2010 and 2009, respectively, and is expected to issue an additional $27 million aggregate principal amount of the notes in May 2012. Also as a result of EFIH's ownership of EFH Corp. Toggle Notes ($2.784 billion principal amount as of December 31, 2011 that is eliminated in consolidation), EFH Corp. issued additional EFH Corp. Toggle Notes to EFIH in lieu of cash interest totaling $312 million and $130 million aggregate principal amount in 2011 and 2010, respectively, and is expected to issue to EFIH an additional $167 million aggregate principal amount of the notes in May 2012. The elections increased liquidity in 2011 by an amount equal to $40 million (excluding $293 million related to notes held by EFIH) and is expected to further increase liquidity in May 2012 by an amount equal to a currently estimated $25 million (excluding $156 million related to notes held by EFIH), constituting the amounts of cash interest that otherwise would have been payable on the notes. See Note 10 to Financial Statements for further discussion of the EFH Corp. Toggle Notes, including debt exchange and repurchase transactions involving the notes.

Similarly, TCEH made its 2011, 2010 and 2009 interest payments and will make its May 2012 interest payment on the TCEH Toggle Notes by using the PIK feature of those notes. During the applicable interest periods, the interest rate on the notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $162 million in 2011, $212 million in 2010, including $7 million principal amount to EFH Corp. and eliminated in consolidation, and $202.5 million in 2009, and is expected to further increase the aggregate principal amount of the notes by $88 million in May 2012. The elections increased liquidity in 2011 by an amount equal to $152 million and is expected to further increase liquidity in May 2012 by an amount equal to an estimated $82 million, constituting the amounts of cash interest that otherwise would have been payable on the notes.

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Liquidity Effects of Commodity Hedging and Trading Activities—Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH's Commodity Collateral Posting Facility (CCP facility), an uncapped senior secured revolving credit facility that matures in December 2012, funds the cash collateral posting requirements for a significant portion of the positions in the natural gas price hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of the CCP facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the CCP facility, as of December 31, 2011, approximately 90% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. Due to declines in forward natural gas prices, no amounts were borrowed against the CCP facility as of December 31, 2011 and 2010. See Note 10 to Financial Statements for more information about the TCEH Senior Secured Facilities, which include the CCP facility.

Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of December 31, 2011, restricted cash collateral held totaled $129 million. See Note 22 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. As of December 31, 2011, approximately 170 million MMBtu of positions related to the natural gas price hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped CCP facility supports the collateral posting requirements related to the majority of these transactions.

As of December 31, 2011, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $50 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $165 million posted as of December 31, 2010;

• $1.055 billion in cash has been received from counterparties, net of $6 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $630 million received, net of $1 million in cash posted, as of December 31, 2010;

• $363 million in letters of credit have been posted with counterparties, as compared to $473 million posted as of December 31, 2010, and

• $103 million in letters of credit have been received from counterparties, as compared to $25 million received as of December 31, 2010.

Income Tax Refunds/Payments — Income tax payments related to the Texas margin tax are expected to total approximately $64 million, and no payments or refunds of federal income taxes are expected in the next 12 months. Net payments totaled $37 million and $64 million in the years ended December 31, 2011 and 2010, respectively. In 2009, we received a refund totaling $98 million in income taxes and related interest related to IRS audits of 1993 and 1994 income tax returns and made net payments totaling approximately $44 million related to the Texas margin tax.

As discussed in Note 6 to Financial Statements, we assess uncertain tax positions under a "more-likely-than-not" standard. 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 2012.

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

Accounts Receivable Securitization Program— TXU Energy participates in EFH Corp.'s accounts receivable securitization program with financial institutions (the funding entities). In accordance with transfers and servicing accounting standards, the trade accounts receivable amounts under the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated, wholly-owned, bankruptcy-remote, direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $104 million and $96 million as of December 31, 2011 and 2010, respectively. See Note 9 to Financial Statements for a more complete description of the program, including the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.

Distributions from Oncor —Oncor's distributions to us totaled $116 million, $169 million and $216 million in the years ended December 31, 2011, 2010 and 2009, respectively. We expect to receive a distribution of between $33 million and $39 million from Oncor in late February 2012. Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor's net income determined in accordance with US GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor's regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. (See Note 12 to Financial Statements.)

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

Capitalization — Our capitalization ratios consisted of 128.1% and 120.9% long-term debt, less amounts due currently, and (28.1)% and (20.9)% common stock equity, as of December 31, 2011 and 2010, respectively. Total debt to capitalization, including short-term debt, was 127.3% and 119.6% as of December 31, 2011 and 2010, respectively.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of December 31, 2011, we were in compliance with all such covenants.

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

Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Secured Notes) for the year ended December 31, 2011 totaled $5.036 billion for EFH Corp. See Exhibits 99(b), 99(c) and 99(d) for a reconciliation of net income (loss) to Adjusted EBITDA for EFH Corp., TCEH and EFIH, respectively, for the years ended December 31, 2011 and 2010.

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The table below summarizes TCEH's secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp., EFIH and TCEH that are applicable under certain other threshold covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Notes that were issued in 2011, the TCEH Senior Secured Second Lien Notes, the EFH Corp. Senior Notes, the EFH Corp. Senior Secured Notes and the EFIH Notes as of December 31, 2011 and 2010. The debt incurrence and restricted payments/limitations on investments covenants thresholds described below represent levels that must be met in order for EFH Corp., EFIH or TCEH to incur certain permitted debt or make certain restricted payments and/or investments. EFH Corp. and its consolidated subsidiaries are in compliance with their maintenance covenants.

	December 31, 2011	December 31, 2010	Threshold Level as of December 31, 2011
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to Adjusted EBITDA ratio (a)	5.78 to 1.00	5.19 to 1.00	Must not exceed 8.00 to 1.00 (b)
Debt Incurrence Covenants:
EFH Corp. Senior Secured Notes:
EFH Corp. fixed charge coverage ratio	1.1 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.3 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
EFIH Notes:
EFIH fixed charge coverage ratio (c)	(d)	(d)	At least 2.0 to 1.0
TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes:
TCEH fixed charge coverage ratio	1.3 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.3 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (Sponsor Group payments):
EFH Corp. leverage ratio	9.7 to 1.0	8.5 to 1.0	Equal to or less than 7.0 to 1.0
EFH Corp. Senior Secured Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (e)	1.4 to 1.0	1.6 to 1.0	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (e)	1.1 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	9.7 to 1.0	8.5 to 1.0	Equal to or less than 7.0 to 1.0
EFIH Notes:
General restrictions (non-EFH Corp. payments):
EFIH fixed charge coverage ratio (c) (f)	81.7 to 1.0	23.9 to 1.0	At least 2.0 to 1.0
General restrictions (EFH Corp. payments):
EFIH fixed charge coverage ratio (c) (f)	(d)	(d)	At least 2.0 to 1.0
EFIH leverage ratio	5.3 to 1.0	5.3 to 1.0	Equal to or less than 6.0 to 1.0
TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes:
TCEH fixed charge coverage ratio	1.3 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to Adjusted EBITDA ratio	8.7 to 1.0	7.9 to 1.0	Equal to or less than 6.5 to 1.0

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(a) As of December 31, 2010, includes Adjusted EBITDA for the new Sandow 5 and Oak Grove 1 generation units and their proportional amount of outstanding debt under the Delayed Draw Term Loan. As of December 31, 2011, includes pro forma Adjusted EBITDA for the new Oak Grove 2 generation unit as well as Adjusted EBITDA for Sandow 5 and Oak Grove 1 units and all outstanding debt under the Delayed Draw Term Loan.

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(b) Threshold level increased to a maximum of 8.00 to 1.00 for the test periods ending March 31, 2011 through December 31, 2014, effective with the April 2011 amendment to the TCEH Senior Secured Facilities discussed in Note 10 to Financial Statements. Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities and up to $1.5 billion ($906 million excluded as of December 31, 2011) principal amount of TCEH senior secured first lien notes whose proceeds are used to prepay term loans or deposit letter of credit loans under the TCEH Senior Secured Facilities.

(c) Although EFIH currently meets the fixed charge coverage ratio threshold applicable to certain covenants contained in the indentures governing the EFIH Notes, EFIH's ability to use such thresholds to incur debt or make restricted payments/investments is currently limited by the covenants contained in the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes.

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

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

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

Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity — As a result of TCEH's non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of December 31, 2011, counterparties to those contracts could have required TCEH to post up to an aggregate of $18 million in additional collateral. This amount largely represents the below market terms of these contracts as of December 31, 2011; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH's below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of December 31, 2011, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $25 million, with $12 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of December 31, 2011, TCEH posted letters of credit in the amount of $76 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 $800 million to $990 million. 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" and "real-time markets" operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $170 million as of December 31, 2011 (which is subject to daily adjustments based on settlement activity with ERCOT).

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

Other arrangements of EFH Corp. and its subsidiaries, including Oncor's credit facility, the accounts receivable securitization program (see Note 9 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

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

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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 ($20.892 billion as of December 31, 2011) under such facilities.

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

Under the terms of a TCEH rail car lease, which had $43 million in remaining lease payments as of December 31, 2011 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Under the terms of another TCEH rail car lease, which had $47 million in remaining lease payments as of December 31, 2011 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

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

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

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (a direct subsidiary of EFH Corp.), as collection agent, in the aggregate have a cross default threshold of $50,000. If any of 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 contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge or interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

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

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Long-Term Contractual Obligations and Commitments— The following table summarizes our contractual cash obligations as of December 31, 2011 (see Notes 10 and 11 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)	$	74	$	4,444	$	5,093	$	26,461	$	36,072
Long-term debt – interest (b)	3,100		6,203		5,124		6,344		20,771
Operating and capital leases (c)	65		100		83		230		478
Obligations under commodity purchase and services agreements (d)	979		1,277		740		936		3,932
Total contractual cash obligations	$	4,218	$	12,024	$	11,040	$	33,971	$	61,253

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(a) Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting. Also excludes $115 million of additional principal amount of notes expected to be issued in May 2012 and due in 2016 and 2017, reflecting the election of the PIK feature on toggle notes as discussed above under "Toggle Notes Interest Election." Further, includes a noninterest bearing note payable by TCEH to Oncor with a principal balance of $179 million ($41 million current portion) as of December 31, 2011 that matures in 2016 as discussed in Note 20.

(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect as of December 31, 2011.

(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 2011 price for all periods except where contractual price adjustment or index-based prices are specified.

The following are not included in the table above:

• contracts between affiliated entities and intercompany debt, including a $225 million liability due to Oncor related to the nuclear plant decommissioning trust fund described in Note 20;

• 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;

• estimated funding of pension plan totaling $124 million in 2012 and approximately $800 million for the 2012 to 2016 period as discussed above under "Pension and OPEB Plan Funding," and

• liabilities related to uncertain tax positions totaling $1.779 billion (excluding accrued interest totaling $193 million) discussed in Note 6 to Financial Statements as the ultimate timing of payment, if any, is not known.

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

OFF–BALANCE SHEET ARRANGEMENTS

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

COMMITMENTS AND CONTINGENCIES

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

CHANGES IN ACCOUNTING STANDARDS

There have been no recently issued accounting standards effective after December 31, 2011 that are expected to materially impact our financial statements.

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REGULATORY MATTERS

See discussions in Part I under "Environmental Regulations and Related Considerations" and in Note 11 to Financial Statements.

Sunset Review and Other State Legislation

PURA, the PUCT, the RRC, ERCOT, the TCEQ and the Texas Office of Public Utility Counsel (OPUC) were subject to "sunset" review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT, the RRC, ERCOT, the TCEQ or the OPUC), along with an evaluation of the advisability of any changes to that agency's authorizing legislation (e.g. PURA). During the 2011 legislative session, the Texas Legislature extended the life of the PUCT and the RRC until 2013, at which time the PUCT will undergo a limited purpose sunset review and the RRC will undergo a full sunset review. The Texas Legislature also continued ERCOT until the subsequent PUCT sunset review and the OPUC and the TCEQ for 12 years.

During the 2011 legislative session, the Texas Legislature passed Senate Bill 1693, which directed the PUCT to adopt a rule that will allow utilities to recover distribution-related investments on an interim basis without the need for a full rate case. In September 2011, the PUCT approved the periodic rate adjustment rule, which allows utilities to file, under certain circumstances, up to four periodic rate adjustments for these distribution investments between rate cases. No other legislation passed during the 2011 legislative session is expected to have a material impact on Oncor's or our operations, results of operations, liquidity or financial condition.

Oncor Matters with the PUCT

2011 Rate Review Filing(PUCT Docket No. 38929) — In January 2011, Oncor filed for a rate review with the PUCT and 203 original jurisdiction cities based on a test year ended June 30, 2010. If approved as requested, this review would have resulted in an aggregate annual rate increase of approximately $353 million over the test year period adjusted for the impact of weather. Oncor also requested a revised regulatory capital structure of 55% debt to 45% equity. In April 2011, Oncor filed, and the administrative law judges in the rate review granted, a motion requesting abatement of the procedural schedule on the grounds that Oncor and the other parties had reached a Memorandum of Settlement that would settle and resolve all issues in the rate review. Oncor filed a stipulation (including a proposed order and proposed tariffs) in May 2011 that incorporated the Memorandum of Settlement along with other documentation (stipulation) for the purpose of obtaining final approval of the settlement. The terms of the stipulation include an approximate $137 million base rate increase and additional provisions to address franchise fees (discussed below) and other expenses. The stipulation resulted in an impact of less than 1% on an average retail residential monthly bill of 1,300 kWh. Approximately $93 million of the increase became effective in July 2011, and the remainder became effective January 1, 2012. Under the stipulation, amortization of Oncor's regulatory assets increased by approximately $24 million ($14 million of which will be recognized as income tax expense) annually beginning January 1, 2012. The stipulation did not change Oncor's authorized regulatory capital structure of 60% debt and 40% equity or its authorized return on equity of 10.25%. Under the terms of the stipulation, Oncor cannot file another general base rate review prior to July 1, 2013, but is not restricted from filing wholesale transmission rate, transmission cost recovery factor, distribution-related investment and other rate updates and adjustments permitted by Texas state law and PUCT rules. In August 2011, the PUCT issued a final order approving the rate review settlement terms contained in a "modified" stipulation, which removed a payment to certain cities of franchise fees as discussed immediately below.

In response to concerns raised by PUCT Commissioners at a July 2011 PUCT open meeting regarding the stipulation, Oncor filed a modified stipulation that removed from the stipulation a one-time payment to certain cities served by Oncor for retrospective franchise fees. Instead, pursuant to the terms of a separate agreement with certain cities served by Oncor, Oncor will make retrospective franchise fee payments to cities that accept the terms of the separate agreement. If all cities accept, the payments will total approximately $22 million. Through December 31, 2011, Oncor had made substantially all of the franchise fee payments. The payments are subject to refund from the cities or recovery from customers after final resolution of proceedings related to the appeals from Oncor's June 2008 rate review filing discussed below. No other significant terms of the stipulation were revised.

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2008 Rate Review Filing(PUCT Docket No. 35717) — In August 2009, the PUCT issued a final order with respect to Oncor's June 2008 rate review filing with the PUCT and 204 cities based on a test year ended December 31, 2007, and new rates were implemented in September 2009. The final order approved a total annual revenue requirement for Oncor of $2.64 billion, based on a 2007 test year cost of service and customer characteristics. New rates were calculated for all customer classes using 2007 test year billing metrics and the approved class cost allocation and rate design. The PUCT staff estimated that the final order resulted in an approximate $115 million increase in base rate revenues over Oncor's 2007 adjusted test year revenues, before recovery of rate case expenses. Prior to implementing the new rates in September 2009, Oncor had already begun recovering $45 million of the $115 million increase as a result of approved transmission cost recovery factor and energy efficiency cost recovery factor filings, such as those discussed below.

Key findings by the PUCT in the rate review included:

• recognizing and affirming Oncor's corporate ring-fence from EFH Corp. and its unregulated affiliates by rejecting a proposed consolidated tax savings adjustment arising out of EFH Corp.'s ability to offset Oncor's taxable income against losses of EFH Corp.'s unregulated affiliates;

• approving the recovery of all of Oncor's capital investment in its transmission and distribution system, including investment in certain automated meters that will be replaced pursuant to Oncor's advanced meter deployment plan;

• denying recovery of $25 million of regulatory assets, which resulted in a $16 million after-tax loss being recognized in the third quarter 2009, and

• setting Oncor's return on equity at 10.25%.

In November 2009, Oncor and four other parties appealed various portions of the rate case final order to a state district court. In January 2011, the district court signed its judgment reversing the PUCT with respect to two issues: the PUCT's disallowance of certain franchise fees and the PUCT's decision that PURA no longer requires imposition of a rate discount for state colleges and universities. Oncor filed an appeal with the Austin Court of Appeals in February 2011 with respect to the issues it appealed to the district court and did not prevail upon, as well as the district court's decision to reverse the PUCT with respect to discounts for state colleges and universities. All briefing has been completed and the parties are waiting for the Court of Appeals to set a date for oral argument. Oncor is unable to predict the outcome of the appeal.

Competitive Renewable Energy Zones (CREZs) — In 2009, the PUCT awarded Oncor CREZ construction projects (PUCT Docket Nos. 35665 and 37902) requiring 14 related Certificate of Convenience and Necessity (CCN) amendment proceedings before the PUCT for 17 projects. All 17 projects and 14 CCN amendments have been approved by the PUCT. The projects involve the construction of transmission lines and stations to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of Texas. In addition to these projects, ERCOT completed a study in December 2010 that will result in Oncor and other transmission service providers building additional facilities to provide further voltage support to the transmission grid as a result of CREZ. Oncor currently estimates, based on these additional voltage support facilities and the approved routes and stations for its awarded CREZ projects, that CREZ construction costs will total approximately $2.0 billion. CREZ-related costs could change based on finalization of costs for the additional voltage support facilities and final detailed designs of subsequent project routes. As of December 31, 2011, Oncor's cumulative CREZ-related capital expenditures totaled $899 million, including $583 million in 2011. Oncor expects that all necessary permitting actions and other requirements and all line and station construction activities for Oncor's CREZ construction projects will be completed by the end of 2013 with additional voltage support projects completed by early 2014.

Transmission Cost Recovery and Rates(PUCT Docket Nos. 39940, 39456, 38938, 38460, 37882, 40142, 39644 and 38495) —In order to recover its wholesale transmission costs, including fees paid to other transmission service providers, Oncor updates the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs twice a year. In November 2011, Oncor filed an application to update the TCRF, which has been approved and will become effective March 1, 2012. This application is designed to lower Oncor's revenues for the period from March 2012 through August 2012 by $41 million, reflecting over-recoveries due to hot weather in the summer of 2011. In June 2011, Oncor filed an application to increase the TCRF, which became effective in September 2011. This application was designed to increase Oncor's revenues for the period from September 2011 through February 2012 by $24 million.

In December 2010, Oncor filed an application to increase the TCRF, which was administratively approved in January 2011 and became effective March 1, 2011. This application was designed to increase Oncor's revenues for the period from March 2011 through August 2011 by $17 million. In July 2010, an application was filed to increase the TCRF, which was administratively approved in August 2010 and became effective September 1, 2010. This application was designed to increase Oncor's revenues for the period September 2010 through February 2011 by $7 million. In January 2010, an application was filed to increase the TCRF, which was administratively approved in February 2010 and became effective March 1, 2010. This application was designed to increase Oncor's revenues for the period May 2010 through August 2010 by $6 million.

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In January 2012, Oncor filed an application for an interim update of its wholesale transmission rate. Oncor expects PUCT approval of the new rate by the end of March 2012. The effect on Oncor's annualized revenues is expected to be immaterial.

In August 2011, Oncor filed an application for an interim update of its wholesale transmission rate, and the PUCT approved the new rate effective October 27, 2011. Oncor's annualized revenues increased by an estimated $35 million with $22 million of this increase recoverable through transmission rates charged to wholesale customers and the remaining $13 million recoverable from REPs through the TCRF component of Oncor's delivery rates.

In July 2010, Oncor filed an application for an interim update of its wholesale transmission rate, and the PUCT approved the new rate effective September 29, 2010. Oncor's annualized revenues increased by an estimated $43 million with $27 million of this increase recoverable through transmission rates charged to wholesale customers and the remaining $16 million recoverable from REPs through the TCRF component of Oncor's delivery rates.

Application for Reconciliation of Advanced Meter Surcharge (PUCT Docket No. 39552) — In July 2011, Oncor filed an application with the PUCT for reconciliation of all costs incurred and investments made through December 31, 2010, in the deployment of its advanced meter system (AMS) pursuant to its AMS Deployment Plan that was approved in Docket No. 35718. The order in Docket No. 35718 included a requirement that Oncor file a reconciliation proceeding two years after the implementation of the AMS surcharge. Through the end of 2010, Oncor spent approximately $357 million in executing the approved AMS Deployment Plan and billed customers approximately $171 million through the AMS surcharge. Oncor did not seek a change in the AMS surcharge or the AMS Deployment Plan in this proceeding. In October 2011, Oncor and other parties to the case filed a proposed order and stipulation, which would resolve all issues in the case. In November 2011, the PUCT issued a final order in the proceeding approving the stipulation and finding that costs expended and investments made in the deployment of Oncor's AMS through December 31, 2010 were properly allocated, reasonable and necessary.

As of December 31, 2011, Oncor had installed 2,302,000 advanced digital meters, including 788,000 in 2011. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $518 million as of December 31, 2011, including $158 million in 2011. Oncor expects to complete installations of the advanced meters by the end of 2012.

Oncor may, through subsequent reconciliation proceedings, request recovery of additional costs that are reasonable and necessary. While there is a presumption that costs spent in accordance with a plan approved by the PUCT are reasonable and necessary, recovery of any costs that are found not to have been spent or properly allocated, or not to be reasonable or necessary, must be refunded.

Application for 2012 and 2011 Energy Efficiency Cost Recovery Factors (PUCT Docket Nos. 39375 and 38217) — In May 2011, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2012. PUCT rules require Oncor to make an annual EECRF filing by May 1 (or the first business day in May) for implementation at the beginning of the next calendar year. The requested 2012 EECRF is $54 million, as compared to $51 million established for 2011, and would result in a $0.99 per month charge for residential customers, as compared to the 2011 residential charge of $0.91 per month. In September 2011, Oncor and the other parties to the case filed a proposed order and stipulation, which would resolve all issues in the case. As agreed in the stipulation, the 2012 EECRF is designed to recover $49 million of Oncor's costs for the 2012 programs and an $8 million performance bonus based on 2010 results, partially offset by a $3 million reduction for over-recovery of 2010 costs. In November 2011, The PUCT approved the proposed order and stipulation.

In April 2010, Oncor filed an application with the PUCT to request approval of an EECRF for 2011. In September 2010, the PUCT ruled that Oncor would be allowed to recover $51 million through its 2011 EECRF, including $45 million for 2011 program costs and an $11 million performance bonus based on 2009 results partially offset by a $5 million reduction for over-recovery of 2009 costs, as compared to $54 million recovered through its 2010 EECRF. The resulting monthly charge for residential customers was $0.91, as compared to the 2010 residential charge of $0.89 per month.

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Remand of 1999 Wholesale Transmission Matrix Case (PUCT Docket No. 38780)— In October 2010, the PUCT established Docket No. 38780 for the remand of Docket No. 20381, the 1999 wholesale transmission charge matrix case. A joint settlement agreement was entered into effective October 6, 2003. This settlement resolved disputes regarding wholesale transmission pricing and charges for the period January 1997 through August 1999, the period prior to the September 1, 1999 effective date of the legislation that authorized 100% postage stamp pricing for ERCOT wholesale transmission. Since a series of appeals has become final, the 1999 matrix docket has been remanded to the PUCT to address additional issues.

The first issue is the wholesale transmission transition mechanism for the period of September 1999 through December 1999. The appealing parties (Texas Municipal Power Agency, the City of Denton, the City of Garland and GEUS (formerly known as Greenville Electric Utility System)) argued that the transition mechanism was not authorized in the September 1, 1999 100% postage stamp pricing legislation and should not have continued it for the last four months of 1999. In October 2011, certain parties filed a proposed settlement of this issue, subject to PUCT approval, in which Oncor would pay approximately $9 million including interest through October 9, 2003. The PUCT approved the settlement at its January 12, 2012 open meeting. Oncor anticipates making the payment in accordance with the settlement in the first quarter of 2012. Oncor believes the settlement payment is probable for future recovery through rates.

Regarding the second issue, the San Antonio City Public Service Board (CPSB) made a filing in January 2011 with the PUCT (PUCT Docket No. 39068) seeking an additional $22 million of Transmission Cost of Service (TCOS) revenue, including interest, for the period of September 1999 through December 2000, based upon CPSB's claim that the PUCT did not have the authority to reduce CPSB's requested TCOS revenue requirement for that period. Oncor would be responsible for approximately $11 million of the requested revenue. In January 2012, the PUCT upheld an administrative law judge's earlier decision to dismiss CPSB's request.

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

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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Item7A. 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 unregulated energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (VaR) methodologies. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, validation of transaction capture, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

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

Commodity Price Risk

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

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

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

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

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

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

	Year Ended December 31,
	2011		2010
Month-end average Trading VaR:	$	4	$	3
Month-end high Trading VaR:	$	8	$	4
Month-end low Trading VaR:	$	1	$	1

VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.

	Year Ended December 31,
	2011		2010
Month-end average MtM VaR:	$	195	$	426
Month-end high MtM VaR:	$	268	$	621
Month-end low MtM VaR:	$	121	$	321

Earnings at Risk (EaR) — This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). Transactions accounted for as cash flow hedges are also included for this measurement. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.

	Year Ended December 31,
	2011		2010
Month-end average EaR:	$	170	$	477
Month-end high EaR:	$	228	$	662
Month-end low EaR:	$	121	$	323

The decreases in the risk measures (MtM VaR and EaR) above reflected a reduction of positions in the natural gas price hedging program due to maturities and lower volatility in commodity prices and lower forward natural gas prices.

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Interest Rate Risk

The table below provides information concerning our financial instruments as of December 31, 2011 and 2010 that are sensitive to changes in interest rates, which include 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 fixed borrowing costs as discussed in Note 10 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 as of December 31, 2011. See Note 10 to Financial Statements for a discussion of debt obligations.

	Expected Maturity Date
	(millions of dollars, except percentages)
	2012			2013			2014			2015			2016			There- after			2011 Total Carrying Amount			2011 Total Fair Value		2010 Total Carrying Amount			2010 Total Fair Value
Long-term debt (including current maturities):
Fixed rate debt amount (a)	$	33		$	91		$	375		$	3,147		$	1,588		$	10,230		$	15,464		$	10,249	$	14,037		$	10,052
Average interest rate	8.17		%	7.24		%	5.69		%	10.24		%	11.22		%	10.36		%	10.29		%			9.98		%
Variable rate debt amount	$	—		$	—		$	3,890		$	154		$	154		$	16,231		$	20,429		$	13,153	$	21,383		$	16,542
Average interest rate	—		%	—		%	3.79		%	4.78		%	4.78		%	4.72		%	4.54		%			3.73		%
Total debt	$	33		$	91		$	4,265		$	3,301		$	1,742		$	26,461		$	35,893		$	23,402	$	35,420		$	26,594
Debt swapped to fixed:
Amount (b)	$	2,600		$	1,600		$	14,455		$	3,000		$	—		$	9,600		$	—				$	15,800
Average pay rate	8.99		%	8.53		%	8.42		%	6.85		%	—			8.95		%	—					7.99		%
Average receive rate	4.94		%	5.00		%	4.94		%	4.94		%	—			4.94		%	—					3.79		%
Variable basis swaps:
Amount	$	7,200		$	10,917		$	1,050		$	—		$	—		$	—		$	19,167				$	15,200
Average pay rate	0.38		%	0.39		%	0.38		%	—		%	—			—			0.39		%			0.32		%
Average receive rate	0.26		%	0.26		%	0.26		%	—		%	—			—			0.26		%			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 10 to Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing.

(b) $18.655 billion notional amount outstanding beginning 2012 that mature through October 2014 and $12.6 billion notional amount beginning October 2014 that mature through October 2017. $3.622 billion of the swaps that mature in 2012 and 2013 will be replaced with new swaps that mature in 2014.

As of December 31, 2011, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $9 million, taking into account the interest rate swaps discussed in Note 10 to Financial Statements.

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Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty's financial condition, credit rating and other quantitative and qualitative credit criteria and authorize specific risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties' financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.

Credit Exposure — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $2.180 billion as of December 31, 2011. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of December 31, 2011 include $525 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $69 million. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

The remaining credit exposure arises from wholesale trade receivables, commodity contracts and hedging and trading activities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of December 31, 2011, the exposure to credit risk from these counterparties totaled $1.655 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $1.074 billion in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $581 million decreased $1.025 billion in the year ended December 31, 2011, driven by an increase in derivative liabilities related to interest rate swaps due to lower interest rates.

Of this $581 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.

103

The following table presents the distribution of credit exposure as of December 31, 2011 arising from wholesale trade receivables, commodity contracts and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as liens on assets. See Note 16 to Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

									Gross Exposure by Maturity
	Exposure Before Credit Collateral			Credit Collateral		Net Exposure			2 years or less		Between 2-5  years		Greater than 5 years			Total
Investment grade	$	1,641		$	1,066	$	575		$	1,515	$	153	$	(27	)	$	1,641
Noninvestment grade	14			8		6			14		—		—			14
Totals	$	1,655		$	1,074	$	581		$	1,529	$	153	$	(27	)	$	1,655
Investment grade	99.2		%			99.0		%
Noninvestment grade	0.8		%			1.0		%

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

Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented 41% and 30% of the $581 million net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty's credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.

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

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "should," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under Item 1A, "Risk Factors" 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 FERC, the NERC, the TRE, the PUCT, the RRC, the NRC, the EPA, the TCEQ and the CFTC, with respect to, among other things:

◦ allowed prices;

◦ allowed rates of return;

◦ permitted capital structure;

◦ industry, market and rate structure;

◦ purchased power and recovery of investments;

◦ operations of nuclear generation facilities;

◦ operations of fossil-fueled generation facilities;

◦ operations of mines;

◦ acquisition and disposal of assets and facilities;

◦ development, construction and operation of facilities;

◦ decommissioning costs;

◦ present or prospective wholesale and retail competition;

◦ changes in tax laws and policies;

◦ changes in and compliance with environmental and safety laws and policies, including 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 a recessionary environment;

• our ability to attract and retain profitable customers;

• our ability to profitably serve our customers;

• restrictions on competitive retail pricing;

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

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

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

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

• weather conditions and other natural phenomena, and acts of sabotage, wars or terrorist or cybersecurity threats or activities;

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

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

• access to adequate transmission facilities to meet changing demands;

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

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

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

• 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;

105

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

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

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

• our ability to successfully execute our liability management program;

• 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;

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

INDUSTRY AND MARKET INFORMATION

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Holdings Corp.

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2011 and 2010, 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, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and financial statement schedule are the responsibility of EFH Corp.'s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 Holdings Corp. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Notes 1 and 3 to the consolidated financial statements, EFH Corp. adopted amended consolidation accounting standards related to variable interest entities, and as also discussed in Notes 1 and 9 to the consolidated financial statements, EFH Corp. adopted amended guidance regarding transfers of financial assets effective January 1, 2010, on a prospective basis.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EFH Corp.'s internal control over financial reporting as of December 31, 2011, 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 20, 2012 expressed an unqualified opinion on EFH Corp.'s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Dallas, Texas

February 20, 2012

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME (LOSS) (Millions of Dollars)
	Year Ended December 31,
	2011			2010			2009
Operating revenues	$	7,040		$	8,235		$	9,546
Fuel, purchased power costs and delivery fees	(3,396		)	(4,371		)	(2,878		)
Net gain from commodity hedging and trading activities	1,011			2,161			1,736
Operating costs	(924		)	(837		)	(1,598		)
Depreciation and amortization	(1,499		)	(1,407		)	(1,754		)
Selling, general and administrative expenses	(742		)	(751		)	(1,068		)
Franchise and revenue-based taxes	(96		)	(106		)	(359		)
Impairment of goodwill (Note 5)	—			(4,100		)	(90		)
Other income (Note 8)	118			2,051			204
Other deductions (Note 8)	(553		)	(31		)	(97		)
Interest income	2			10			45
Interest expense and related charges (Note 22)	(4,294		)	(3,554		)	(2,912		)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries	(3,333		)	(2,700		)	775
Income tax (expense) benefit (Note 7)	1,134			(389		)	(367		)
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2)	286			277			—
Net income (loss)	(1,913		)	(2,812		)	408
Net (income) attributable to noncontrolling interests	—			—			(64		)
Net income (loss) attributable to EFH Corp.	$	(1,913	)	$	(2,812	)	$	344

See Notes to Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) (Millions of Dollars)
	Year Ended December 31,
	2011			2010			2009
Net income (loss)	$	(1,913	)	$	(2,812	)	$	408
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax (expense) benefit of $(24), $8 and $20) (Note 20)	45			(13		)	(40		)
Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of $—, $— and $10)	—			—			(20		)
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $10, $31 and $72)	19			59			130
Net decrease in fair value of derivatives held by unconsolidated subsidiary (net of tax benefit of $13, $— and $—) (Note 2)	(23		)	—			—
Total effect of cash flow hedges	(4		)	59			110
Total other comprehensive income	41			46			70
Comprehensive income (loss)	(1,872		)	(2,766		)	478
Comprehensive (income) loss attributable to noncontrolling interests	—			—			(64		)
Comprehensive income (loss) attributable to EFH Corp.	$	(1,872	)	$	(2,766	)	$	414

See Notes to Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (Millions of Dollars)
	Year Ended December 31,
	2011			2010			2009
Cash flows — operating activities
Net income (loss)	$	(1,913	)	$	(2,812	)	$	408
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization	1,743			1,689			2,099
Deferred income tax expense (benefit) – net	(1,219		)	604			253
Unrealized net gain from mark-to-market valuations of commodity positions	(58		)	(1,221		)	(1,225		)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps (Note 10)	812			207			(696		)
Amortization of debt related costs, discounts, fair value discounts and losses on dedesignated cash flow hedges (Note 22)	267			280			406
Equity in earnings of unconsolidated subsidiaries	(286		)	(277		)	—
Distributions of earnings from unconsolidated subsidiaries	116			169			—
Accretion expense related to asset retirement and mining reclamation obligations	48			57			59
Impairment of goodwill (Note 5)	—			4,100			90
Impairment of emission allowances intangible assets (Note 4)	418			—			—
Debt extinguishment gains (Note 10)	(51		)	(1,814		)	(87		)
Interest expense on toggle notes payable in additional principal (Notes 10 and 22)	219			446			524
Impairment of assets related to mining operations (Note 4)	9			—			—
Third-party fees related to debt amendment and extension transactions (reported as financing) (Note 10)	100			—			—
Gain on termination of long-term power sales contract (Note 8)	—			(116		)	—
Bad debt expense (Note 9)	56			108			113
Net gain on sales of assets	(3		)	(81		)	(5		)
Stock-based incentive compensation expense	13			19			14
Reversal of reserves recorded in purchase accounting (Note 8)	—			—			(44		)
Impairment of land	—			—			34
Write off of regulatory assets (Note 8)	—			—			25
Other, net	(6		)	8			(4		)
Changes in operating assets and liabilities:
Accounts receivable – trade	176			258			(125		)
Impact of accounts receivable securitization program (Note 9)	—			(383		)	(33		)
Inventories	(23		)	(6		)	(59		)
Accounts payable – trade	(120		)	(93		)	(141		)
Payables due to unconsolidated subsidiary	(78		)	—			—
Commodity and other derivative contractual assets and liabilities	(31		)	(44		)	(64		)
Margin deposits – net	540			132			248
Deferred advanced metering system revenues	—			—			57
Other – net assets	(7		)	21			(192		)
Other – net liabilities	119			(145		)	56
Cash provided by operating activities	$	841		$	1,106		$	1,711

110

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (Millions of Dollars)
	Year Ended December 31,
	2011			2010			2009
Cash flows — financing activities
Issuances of long-term debt (Note 10)	$	1,750		$	853		$	522
Repayments/repurchases of long-term debt (Note 10)	(1,431		)	(1,351		)	(396		)
Net short-term borrowings under accounts receivable securitization program (Note 9)	8			96			—
Increase (decrease) in other short-term borrowings (Note 10)	(455		)	172			332
Decrease in note payable to unconsolidated subsidiary	(39		)	(37		)	—
Contributions from noncontrolling interests	16			32			48
Distributions paid to noncontrolling interests	—			—			(56		)
Debt amendment, exchange and issuance costs and discounts, including third party fees expensed	(857		)	(62		)	(49		)
Other, net	(6		)	33			21
Cash provided by (used in) financing activities	$	(1,014	)	$	(264	)	$	422
Cash flows — investing activities
Capital expenditures	(552		)	(838		)	(2,348		)
Nuclear fuel purchases	(132		)	(106		)	(197		)
Reduction of restricted cash related to letter of credit facility (Note 10)	188			—			115
Other changes in restricted cash	(96		)	(33		)	9
Proceeds from sales of assets	52			147			42
Proceeds from sales of environmental allowances and credits	10			12			19
Purchases of environmental allowances and credits	(17		)	(30		)	(19		)
Proceeds from sales of nuclear decommissioning trust fund securities	2,419			974			3,064
Investments in nuclear decommissioning trust fund securities	(2,436		)	(990		)	(3,080		)
Investment redeemed/(posted) with derivative counterparty (Note 16)	—			400			(400		)
Money market fund redemptions	—			—			142
Other, net	29			(4		)	20
Cash used in investing activities	$	(535	)	$	(468	)	$	(2,633	)
Net change in cash and cash equivalents	(708		)	374			(500		)
Effect of deconsolidation of Oncor Holdings	—			(29		)	—
Cash and cash equivalents — beginning balance	1,534			1,189			1,689
Cash and cash equivalents — ending balance	$	826		$	1,534		$	1,189

See Notes to Financial Statements.

111

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Millions of Dollars)
	December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents (Note 1)	$	826		$	1,534
Restricted cash (Note 22)	129			33
Trade accounts receivable — net (includes $524 and $612 in pledged amounts related to a VIE (Notes 3 and 9))	767			999
Inventories (Note 22)	418			395
Commodity and other derivative contractual assets (Note 16)	3,025			2,732
Margin deposits related to commodity positions	56			166
Other current assets	82			60
Total current assets	5,303			5,919
Restricted cash (Note 22)	947			1,135
Receivable from unconsolidated subsidiary (Note 20)	1,235			1,463
Investments in unconsolidated subsidiary (Note 2)	5,720			5,544
Other investments (Note 17)	709			697
Property, plant and equipment — net (Note 22)	19,427			20,366
Goodwill (Note 5)	6,152			6,152
Identifiable intangible assets — net (Note 5)	1,845			2,400
Commodity and other derivative contractual assets (Note 16)	1,552			2,071
Other noncurrent assets, principally unamortized debt amendment and issuance costs	1,187			641
Total assets	$	44,077		$	46,388
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (includes $104 and $96 related to a VIE (Notes 3 and 10))	$	774		$	1,221
Long-term debt due currently (Note 10)	47			669
Trade accounts payable	574			681
Payables due to unconsolidated subsidiary (Note 20)	177			254
Commodity and other derivative contractual liabilities (Note 16)	1,950			2,283
Margin deposits related to commodity positions	1,061			631
Accumulated deferred income taxes (Note 7)	54			11
Accrued interest	480			411
Other current liabilities	497			442
Total current liabilities	5,614			6,603
Accumulated deferred income taxes (Note 7)	3,989			5,350
Commodity and other derivative contractual liabilities (Note 16)	1,692			869
Notes or other liabilities due to unconsolidated subsidiary (Note 20)	363			384
Long-term debt, less amounts due currently (Note 10)	35,360			34,226
Other noncurrent liabilities and deferred credits (Note 22)	4,816			4,867
Total liabilities	51,834			52,299
Commitments and Contingencies (Note 11)
Equity (Note 12):
Common stock (shares outstanding 2011 — 1,679,539,245; 2010 — 1,671,812,118)	2			2
Additional paid-in capital	7,947			7,937
Retained earnings (deficit)	(15,579		)	(13,666		)
Accumulated other comprehensive loss	(222		)	(263		)
EFH Corp. shareholders' equity	(7,852		)	(5,990		)
Noncontrolling interests in subsidiaries	95			79
Total equity	(7,757		)	(5,911		)
Total liabilities and equity	$	44,077		$	46,388

See Notes to Financial Statements.

112

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED EQUITY (Millions of Dollars)
	Year Ended December 31,
	2011			2010			2009
Common stock stated value of $0.001 effective May 2009 (number of authorized shares — 2,000,000,000):
Balance as of beginning of period	$	2		$	2		$	—
Effects of shareholder actions related to stated value of common stock	—			—			2
Balance as of end of period (number of shares outstanding: 2011 — 1,679,539,245; 2010 — 1,671,812,118; 2009 — 1,668,065,133)	2			2			2
Additional paid-in capital:
Balance as of beginning of period	7,937			7,914			7,904
Effects of stock-based incentive compensation plans	11			24			11
Effects of shareholder actions related to stated value of common stock	—			—			(2		)
Common stock repurchases	—			(2		)	—
Other	(1		)	1			1
Balance as of end of period	7,947			7,937			7,914
Retained earnings (deficit):
Balance as of beginning of period	(13,666		)	(10,854		)	(11,198		)
Net income (loss) attributable to EFH Corp.	(1,913		)	(2,812		)	344
Balance as of end of period	(15,579		)	(13,666		)	(10,854		)
Accumulated other comprehensive loss, net of tax effects:
Pension and other postretirement employee benefit liability adjustments:
Balance as of beginning of period	(194		)	(181		)	(141		)
Change in unrecognized gains (losses) related to pension and other retirement benefit costs	45			(13		)	(40		)
Balance as of end of period	(149		)	(194		)	(181		)
Amounts related to cash flow hedges:
Balance as of beginning of period	(69		)	(128		)	(238		)
Change during the period	(4		)	59			110
Balance as of end of period	(73		)	(69		)	(128		)
Total accumulated other comprehensive loss as of end of period	(222		)	(263		)	(309		)
EFH Corp. shareholders' equity as of end of period (Note 12)	(7,852		)	(5,990		)	(3,247		)
Noncontrolling interests in subsidiaries (Note 13):
Balance as of beginning of period	79			1,411			1,355
Net income attributable to noncontrolling interests	—			—			64
Effect of deconsolidation of Oncor Holdings (Notes 1 and 3)	—			(1,363		)	—
Investments by noncontrolling interests	16			32			48
Distributions to noncontrolling interests	—			—			(56		)
Other	—			(1		)	—
Noncontrolling interests in subsidiaries as of end of period	95			79			1,411
Total equity as of end of period	$	(7,757	)	$	(5,911	)	$	(1,836	)

See Notes to Financial Statements.

113

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

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

EFH Corp., a Texas corporation, is a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. EFCH and its direct subsidiary, TCEH, are wholly-owned. 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. EFIH is wholly-owned and indirectly holds an approximately 80% equity interest in Oncor. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Effective January 1, 2010, Oncor (and its majority owner, Oncor Holdings) are not consolidated in EFH Corp.'s financial statements in accordance with consolidation accounting standards related to variable interest entities (VIEs) (see Note 3).

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

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

We have two reportable segments: the Competitive Electric segment, consisting largely of TCEH, and the Regulated Delivery segment, consisting largely of our investment in Oncor. See Note 21 for further information concerning reportable business segments.

Basis of Presentation

The consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in EFH Corp.'s Annual Report on Form 10-K for the year ended December 31, 2010. See Note 3 for discussion of the prospective adoption of amended guidance regarding consolidation accounting standards related to VIEs that resulted in the deconsolidation of Oncor Holdings effective January 1, 2010 and Note 9 for discussion 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 effective January 1, 2010. Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Notes 2 and 3). All intercompany items and transactions have been eliminated in consolidation. All acquisitions of outstanding debt for cash, including notes that had been issued in lieu of cash interest, are presented in the financing activities section of the statement of cash flows. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

Use of Estimates

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

114

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of electricity, natural gas, coal 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 14 and 16 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.

As of December 31, 2011 and 2010, there were no derivative positions accounted for as cash flow or fair value hedges. Accumulated other comprehensive income includes amounts related to interest rate swaps previously designated as cash flow hedges that are being reclassified to net income as the hedged transactions impact net income (see Note 10).

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

Revenue Recognition

We record revenue from electricity sales and delivery service under the accrual method of accounting. Revenues are recognized when electricity or delivery services are 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).

115

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 4 for discussion of impairments of emission allowances intangible assets and mining-related assets in 2011.

We evaluate investments in unconsolidated subsidiaries for impairment when factors indicate that a decrease in the value of the investment has occurred that is not temporary. Indicators that should be evaluated for possible impairment of investments include recurring operating losses of the investee or fair value measures that are less than carrying value. Any impairment recognition is based on fair value that is not reflective of temporary conditions. Fair value is determined primarily by discounted long-term cash flows, supported by available market valuations, if applicable.

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 5 for additional information.

Goodwill and Intangible Assets with Indefinite Lives

We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually (as of December 1). See Note 5 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations and goodwill impairments recorded in 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.

Defined Benefit Pension Plans and Other Postretirement Employee Benefit Plans

We offer pension benefits based on either a traditional defined benefit formula or a cash balance formula and also offer 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. The pension and OPEB accrued benefit obligations reported in the balance sheet are in accordance with accounting standards related to employers' accounting for defined benefit pension and other postretirement plans. See Notes 18 and 20 for additional information regarding pension and OPEB plans.

116

Stock-Based Incentive Compensation

Our 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 19 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

We file a consolidated federal income tax return, and federal income taxes are calculated for our subsidiaries substantially as if the entities file separate corporate income tax returns. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Oncor is a partnership for US federal income tax purposes, and we provide deferred income taxes on the difference between the book and tax basis of our investment in Oncor. Investment tax credits related to Oncor's regulated operations are deferred and amortized over the lives of the related properties in accordance with regulatory treatment. Certain provisions of the accounting guidance for income taxes allow regulated enterprises to recognize deferred taxes as regulatory tax assets or tax liabilities if it is probable that such amounts will be recovered from, or returned to, customers in future rates.

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

Accounting for Contingencies

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

Cash and Cash Equivalents

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

Restricted Cash

The terms of certain agreements require the restriction of cash for specific purposes. As of December 31, 2011, $947 million of cash was restricted to support letters of credit and $129 million of margin deposits was restricted pursuant to contractual terms. See Notes 10 and 22 for more details regarding restricted cash.

117

Property, Plant and Equipment

As a result of purchase accounting, carrying amounts of property, plant and equipment related to unregulated businesses 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 for unregulated properties is calculated on a component asset-by-asset basis. As is common in the industry for regulated operations, Oncor's depreciation expense is calculated using composite depreciation rates that reflect blended estimates of the lives of major asset groups. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives or, in the case of Oncor, as set by PUCT orders. See Note 22.

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 22.

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 22.

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 4 for details of impairment amounts recorded in 2011.

Investments

Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method. See Note 2 for discussion of equity method investments and Note 3 for discussion of VIEs.

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 17 for discussion of these and other investments.

Noncontrolling Interests

See Note 13 for discussion of accounting for noncontrolling interests in subsidiaries.

118

2. EQUITY METHOD INVESTMENTS

Oncor Holdings

Investment in unconsolidated subsidiary totaled $5.720 billion and $5.544 billion as of December 31, 2011 and 2010, respectively, and consists of our interest in Oncor Holdings (100% owned), which we have accounted for under the equity method since January 1, 2010 (see Note 3). Oncor Holdings owns approximately 80% of Oncor, which is engaged in regulated electricity transmission and distribution operations in Texas. Revenues from distribution services provided to TCEH's retail operations represented 33%, 36% and 38% of Oncor Holdings' consolidated operating revenues for the years ended December 31, 2011, 2010 and 2009, respectively.

Distributions from Oncor Holdings —The boards of directors of each of Oncor and Oncor Holdings can withhold distributions to the extent the boards determine that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings. Oncor's distributions to us totaled $116 million, $169 million and $216 million in the years ended December 31, 2011, 2010 and 2009, respectively. Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor's cumulative net income determined in accordance with US GAAP, subject to certain defined adjustments. Such adjustments include deducting a $46 million after-tax refund to customers in 2008, net accretion of fair value adjustments resulting from purchase accounting and funds spent as part of a $100 million commitment for additional demand-side management or other energy efficiency initiatives, which totaled $48 million after tax through December 31, 2011, and removing the effects of the $860 million goodwill impairment charge in 2008. As of December 31, 2011, $327 million was available for distribution to Oncor's members under the cumulative net income restriction, of which approximately 80% relates to EFH Corp.'s ownership interest in Oncor.

Oncor's distributions are further limited by an agreement with the PUCT that its regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. As of December 31, 2011, Oncor's regulatory capitalization ratio was 59.7% debt and 40.3% equity. The PUCT has the authority to determine what types of debt and equity are included in a utility's debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes bonds issued by Oncor Electric Delivery Transition Bond Company, which were issued in 2003 and 2004 to recover specific generation-related regulatory asset stranded and other qualified costs. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization). As of December 31, 2011, $45 million was available for distribution under the capital structure restriction, of which approximately 80% relates to our ownership interest in Oncor.

Oncor Holdings Financial Statements—Condensed statements of consolidated income of Oncor Holdings and its subsidiaries for the years ended December 31, 2011, 2010 and 2009 are presented below:

	Year Ended December 31,
	2011			2010			2009
Operating revenues	$	3,118		$	2,914		$	2,690
Operation and maintenance expenses	(1,097		)	(1,009		)	(962		)
Write off of regulatory assets	—			—			(25		)
Depreciation and amortization	(719		)	(673		)	(557		)
Taxes other than income taxes	(400		)	(384		)	(385		)
Other income	30			36			49
Other deductions	(9		)	(8		)	(14		)
Interest income	32			38			43
Interest expense and related charges	(359		)	(347		)	(346		)
Income before income taxes	596			567			493
Income tax expense	(236		)	(220		)	(173		)
Net income	360			347			320
Net income attributable to noncontrolling interests	(74		)	(70		)	(64		)
Net income attributable to Oncor Holdings	$	286		$	277		$	256

119

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

	December 31,
	2011		2010
ASSETS
Current assets:
Cash and cash equivalents	$	12	$	33
Restricted cash	57		53
Trade accounts receivable — net	303		254
Trade accounts and other receivables from affiliates	179		182
Income taxes receivable from EFH Corp.	—		72
Inventories	71		96
Accumulated deferred income taxes	73		10
Prepayments and other current assets	74		80
Total current assets	769		780
Restricted cash	16		16
Receivable from TCEH related to nuclear plant decommissioning	225		206
Other investments	73		78
Property, plant and equipment — net	10,569		9,676
Goodwill	4,064		4,064
Note receivable due from TCEH	138		178
Regulatory assets — net	1,505		1,782
Other noncurrent assets	73		58
Total assets	$	17,432	$	16,838
LIABILITIES
Current liabilities:
Short-term borrowings	$	392	$	377
Long-term debt due currently	494		113
Trade accounts payable — nonaffiliates	197		125
Income taxes payable to EFH Corp.	2		—
Accrued taxes other than income	151		133
Accrued interest	108		108
Other current liabilities	112		109
Total current liabilities	1,456		965
Accumulated deferred income taxes	1,688		1,516
Investment tax credits	28		32
Long-term debt, less amounts due currently	5,144		5,333
Other noncurrent liabilities and deferred credits	1,832		1,996
Total liabilities	$	10,148	$	9,842

120

3. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. We adopted amended accounting standards on January 1, 2010 that require consolidation of a VIE if we have (a) the power to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (primary beneficiary). Our VIEs consist of equity investments in certain of our subsidiaries. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.

As discussed below, our balance sheet includes assets and liabilities of VIEs that meet the amended consolidation standards. Oncor Holdings, which holds an approximate 80% interest in Oncor, was deconsolidated from EFH Corp.'s financial statements on a prospective basis effective January 1, 2010 because the structural and operational "ring-fencing" measures discussed in Note 1 prevent us from having power to direct the significant activities of Oncor Holdings or Oncor. We account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, because, while we do not have the power to direct Oncor's significant activities, we do have the ability to exercise significant influence (as defined by US GAAP) over its activities. Our maximum exposure to loss from our variable interests in VIEs does not exceed our carrying value. See Note 2 for additional information about equity method investments including condensed income statement and balance sheet data for Oncor Holdings.

Consolidated VIEs

See discussion in Note 9 regarding the VIE related to our accounts receivable securitization program that is consolidated under the amended accounting standards on a prospective basis effective January 1, 2010.

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 13).

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

	December 31,					December 31,
Assets:	2011		2010		Liabilities:	2011		2010
Cash and cash equivalents	$	10	$	9	Short-term borrowings	$	104	96
Accounts receivable	525		612		Trade accounts payable	1		3
Property, plant and equipment	132		112		Other current liabilities	9		1
Other assets, including $2 million of current assets in both periods	6		8
Total assets	$	673	$	741	Total liabilities	$	114	100

The assets of our consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of our consolidated VIEs do not have recourse to our general credit.

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Non-Consolidated VIEs

The adoption of the amended accounting standards resulted in the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor, and the reporting of our investment in Oncor Holdings under the equity method on a prospective basis effective January 1, 2010.

In reaching the conclusion to deconsolidate, we conducted an extensive analysis of Oncor Holdings' underlying governing documents and management structure. Oncor Holdings' unique governance structure was adopted in conjunction with the Merger, when the Sponsor Group, EFH Corp. and Oncor agreed to implement structural and operational measures to "ring-fence" (the Ring-Fencing Measures) Oncor Holdings and Oncor as discussed in Note 1. The Ring-Fencing Measures were designed to prevent, among other things, (i) increased borrowing costs at Oncor due to the attribution to Oncor of debt from any of our other subsidiaries, (ii) the activities of our unregulated operations following the Merger resulting in the deterioration of Oncor's business, financial condition and/or investment in infrastructure, and (iii) Oncor becoming substantively consolidated into a bankruptcy proceeding involving any member of the Texas Holdings Group. The Ring-Fencing Measures effectively separated the daily operational and management control of Oncor Holdings and Oncor from EFH Corp. and its other subsidiaries. By implementing the Ring-Fencing Measures, Oncor maintained its investment grade credit rating following the Merger, and we reaffirmed Oncor's independence from our unregulated businesses to the PUCT.

We determined the most significant activities affecting the economic performance of Oncor Holdings (and Oncor) are the operation, maintenance and growth of Oncor's electric transmission and distribution assets and the preservation of its investment grade credit profile. The boards of directors of Oncor Holdings and Oncor have ultimate responsibility for the management of the day-to-day operations of their respective businesses, including the approval of Oncor's capital expenditure and operating budgets and the timing and prosecution of Oncor's rate cases. While both boards include members appointed by EFH Corp., a majority of the board members are independent in accordance with rules established by the New York Stock Exchange, and therefore, we concluded for purposes of applying the amended accounting standards that EFH Corp. does not have the power to control the activities deemed most significant to Oncor Holdings' (and Oncor's) economic performance.

In assessing EFH Corp.'s ability to exercise control over Oncor Holdings and Oncor, we considered whether it could take actions to circumvent the purpose and intent of the Ring-Fencing Measures (including changing the composition of Oncor Holdings' or Oncor's board) in order to gain control over the day-to-day operations of either Oncor Holdings or Oncor. We also considered whether (i) EFH Corp. has the unilateral power to dissolve, liquidate or force into bankruptcy either Oncor Holdings or Oncor, (ii) EFH Corp. could unilaterally amend the Ring-Fencing Measures contained in the underlying governing documents of Oncor Holdings or Oncor, and (iii) EFH Corp. could control Oncor's ability to pay distributions and thereby enhance its own cash flow. We concluded that, in each case, no such opportunity exists.

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4. 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 require 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 excess SO₂ emission allowances under the Clean Air Act's existing acid rain cap-and-trade program, and market values of such allowances are estimated to be de minimis based on Level 3 fair value estimates, which are described in Note 14. 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.

Finally, employee severance charges totaling $49 million were accrued in the third quarter 2011 based upon our existing severance policy. The charges were associated with the probable elimination of approximately 500 positions as a result of the actions we determined would be necessary with respect to our generation and mining operations discussed above.

In August 2011, we petitioned the EPA to reconsider the CSAPR provisions and stay the effectiveness of those provisions, in each case as applied to Texas. In September 2011, we filed a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) challenging the CSAPR as it applies to Texas. In that legal proceeding, we also filed a motion to stay the effective date of the CSAPR as applied to Texas.

On December 30, 2011, the D.C. Circuit Court granted our motion and all other motions for a judicial stay of the CSAPR in its entirety, including as applied to Texas. The D.C. Circuit Court's order does not invalidate the CSAPR but stays the implementation of its emissions reduction programs until a final ruling regarding the CSAPR's validity is issued by the D.C. Circuit Court. The D.C. Circuit Court's order states that the EPA is expected to continue administering the Clean Air Interstate Rule (the predecessor rule to the CSAPR) pending the court's resolution of the petitions for review. The D.C. Circuit Court has scheduled oral argument in the lawsuit for April 13, 2012.

In light of the stay, we did not idle the two Monticello generation units, and we have continued mining lignite at the mines that serve the Big Brown and Monticello generation facilities. While the legal challenge to the CSAPR is in process, we intend to continue evaluating the CSAPR, including the revisions discussed below, alternatives for compliance and the expected effects on our operations, liquidity and financial results.

As a result of the legal proceedings, in the fourth quarter 2011 we reversed the $49 million severance accrual on the basis that the severance actions were no longer probable. The emission allowances and other impairments are not reversible under accounting rules and are reported in other deductions in the results of the Competitive Electric segment.

In February 2012, the EPA released a final rule (Final Revisions) and a direct-to-final rule (Direct Final 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. As compared to the proposed revisions issued by the EPA in October 2011, these recent rules 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. Because the CSAPR is currently stayed by the D.C. Circuit Court, the Final Revisions and the Direct Final Rule do not impose any immediate legal or compliance requirements on us, the State of Texas, or other affected parties. We cannot predict whether, when, or in what form the CSAPR, the Final Revisions, or the Direct Final Rule will take effect.

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5. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides the goodwill balances as of December 31, 2011 and 2010, and the changes in such balances in the year ended December 31, 2010. There were no changes to the goodwill balance in the year ended December 31, 2011. With the deconsolidation of Oncor (including its $4.064 billion goodwill balance) effective January 1, 2010, the amounts below relate only to the Competitive Electric segment. An $860 million goodwill impairment charge related to the Regulated Delivery segment was recorded in 2008. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges	$	18,342
Accumulated impairment charges through 2009 (a)	(8,090		)
Balance as of January 1, 2010	10,252
Additional impairment charge in 2010	(4,100		)
Balance as of December 31, 2011 and 2010 (b)	$	6,152

___________

(a) Includes $90 million in 2009 ($20 million of which was recorded in Corporate and Other results) and $8.0 billion in 2008.

(b) Net of accumulated impairment charges totaling $12.190 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 the Competitive Electric segment likely 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 our Competitive Electric segment 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.

In preparation for the December 1, 2011 goodwill impairment test, we considered the decline in natural gas prices in the fourth quarter of 2011, including the fact that the decline continued through the end of 2011. Accordingly, we performed the impairment testing as of December 31, 2011 and completed the testing steps as described above. Key inputs into our goodwill impairment testing as of December 31, 2011 were as follows.

• The carrying value of the Competitive Electric segment exceeded its estimated enterprise value by approximately 20%.

• Enterprise value was estimated using a two-thirds weighting of values 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 companies.

• The discount rate applied to internally developed cash flow projections was 9.5%. The discount rate represents the weighted average cost of capital consistent with the risk inherent in future cash flows, taking into account overall economic trends, industry specific variables and comparable company volatility.

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• Internally developed cash flow projections were based on a 60% weighting of estimated cash flows under the CSAPR environmental requirements issued in July 2011 and a 40% weighting of cash flows under the EPA's proposed revisions to the CSAPR issued in October 2011 (see Note 4).

• The cash flow projections assume rising wholesale power prices reflecting higher forward natural gas prices as well as increasing market heat rates due to the anticipated decline in reserve margins in the ERCOT market. Reserve margin is the difference between system generation capability and anticipated peak load.

• Enterprise value based on internally developed cash flow projections reflected annual estimates through 2017, 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.

The results of this testing indicated that implied goodwill exceeded recorded goodwill by a small amount, and accordingly no goodwill impairment charge was recorded. While the estimated enterprise value of the Competitive Electric segment declined from previous estimates, the estimated fair values of its generation assets also declined, thus mitigating the effect of lower natural gas prices on implied goodwill.

The issuance of the CSAPR by the EPA resulted in an evaluation of its effects and the development of a plan of action to meet the rule's requirements. These actions were expected to have material financial effects, including significant environmental capital expenditures, lower wholesale revenues and higher operating costs. The EPA's issuance of the CSAPR in the third quarter 2011 triggered an impairment test of the carrying value of the Competitive Electric segment's goodwill. We completed the goodwill impairment testing steps as described above and determined that the implied goodwill amount exceeded recorded goodwill. Accordingly, no goodwill impairment was recorded. See discussion of the CSAPR, including recent developments and effects on the financial statements, in Note 4.

In the third quarter 2010, we recorded a $4.1 billion noncash goodwill impairment charge related to the Competitive Electric segment. The impairment charge reflected the estimated effect of lower wholesale power prices on the enterprise value of the Competitive Electric segment, 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 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 an initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter 2008 and consisted of an estimated impairment of $8.0 billion related to the Competitive Electric segment and $860 million related to the Regulated Delivery segment. A $90 million increase in the charge, largely related to the Competitive Electric segment, was recorded in the first quarter 2009. The impairment charge primarily reflected the dislocation in the capital markets during the fourth quarter 2008 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. The calculation involved the same steps as those discussed above for the 2010 impairment. The total $8.950 billion 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 businesses and the fair values of their 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 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 14). Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

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Identifiable Intangible Assets

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

	As of December 31, 2011						As of December 31, 2010
Identifiable Intangible Asset:	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	344	$	119	$	463	$	293	$	170
Favorable purchase and sales contracts	548		288		260		548		257		291
Capitalized in-service software	318		137		181		278		97		181
Environmental allowances and credits (a)	582		375		207		986		304		682
Mining development costs (a)	140		55		85		47		17		30
Total intangible assets subject to amortization	$	2,051	$	1,199	852		$	2,322	$	968	1,354
Trade name (not subject to amortization)					955						955
Mineral interests (not currently subject to amortization) (b)					38						91
Total intangible assets					$	1,845					$	2,400

___________

(a) Amounts impaired have been removed from the table as of the impairment date (see Note 4).

(b) In 2011, we sold certain mineral interests for $43 million in cash net of closing-related costs. No gain or loss was recorded on the transaction.

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

Identifiable Intangible Asset:	Income Statement Line	Segment	Useful lives as of December 31, 2011 (weighted average in years)	Year Ended December 31,
				2011		2010		2009
Retail customer relationship	Depreciation and amortization	Competitive Electric	6	$	51	$	78	$	85
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	Competitive Electric	11	31		35		125
Capitalized in-service software	Depreciation and amortization	All (a)	5	40		35		53
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	Competitive Electric	26	71		92		91
Land easements	Depreciation and amortization	Regulated Delivery (a)	N/A	—		—		3
Mining development costs	Depreciation and amortization	Competitive Electric	4	38		11		3
Total amortization expense				$	231	$	251	$	360

___________

(a) See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010.

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Separately identifiable and previously unrecognized intangible assets acquired and recorded as part of purchase accounting for the Merger are described as follows:

• Retail Customer Relationship – Retail customer relationship intangible asset represents the estimated 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, based on observable prices or estimates, of commodity contracts for which: (i) we have 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 22).

• Trade name – The trade name intangible asset represents the estimated 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, based on observable prices or estimates, 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.

See discussion in Note 4 regarding impairment of emission allowances and accelerated depreciation and amortization expenses related to mine assets, including mining development costs intangible assets, recorded in 2011.

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:	Amortization Expense
2012	$	138
2013	$	118
2014	$	102
2015	$	93
2016	$	76

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6. 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.

We 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 our income tax returns for the years ending prior to January 1, 2007 are complete, but the tax years 1997 to 2006 remain in appeals with the IRS. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002.

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

In 2010, we engaged in negotiations with the IRS regarding the 2002 worthlessness loss associated with our discontinued Europe business as well as other matters. Accordingly, we have adjusted the liability for uncertain tax positions to reflect the most likely settlement of the issues. The adjustment resulted in a net reduction of the liability for uncertain tax positions totaling $162 million. This reduction consisted of a $225 million reversal of accrued interest ($146 million after tax), reported as a reduction of income tax expense, principally related to the discontinued Europe business, partially offset by $63 million in adjustments related to several other positions that have been accounted for as reclassifications to net deferred tax liabilities. The conclusion of all issues contested from the 1997 through 2002 audit, including IRS Joint Committee review, could occur before the end of 2012. Upon such conclusion, we expect to further reduce the liability for uncertain tax positions by approximately $700 million with an offsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes. Any cash income tax liability related to the conclusion of the 1997 through 2002 audit is expected to be immaterial.

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 $18 million in 2011, a benefit of $115 million in 2010 and an expense of $42 million in 2009 (all amounts after tax).

Noncurrent liabilities included a total of $193 million and $164 million in accrued interest as of December 31, 2011 and 2010, 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, 2011, 2010 and 2009:

	Year Ended December 31,
	2011			2010			2009
Balance as of January 1, excluding interest and penalties (a)	$	1,642		$	1,566		$	1,583
Additions based on tax positions related to prior years	81			312			71
Reductions based on tax positions related to prior years	(6		)	(308		)	(82		)
Additions based on tax positions related to the current year	62			72			66
Balance as of December 31, excluding interest and penalties	$	1,779		$	1,642		$	1,638

___________

(a) 2010 reflects the deconsolidation of Oncor Holdings, which had a balance of $72 million, as of January 1, 2010.

Of the balance as of December 31, 2011, $1.559 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 we sustain such positions on income tax returns previously filed, tax liabilities recorded would be reduced by $220 million, and accrued interest would be reversed resulting in a $32 million after-tax benefit, resulting in increased net income and a favorable impact on the effective tax rate.

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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.

7. INCOME TAXES

The components of our income tax expense (benefit) applicable to continuing operations are as follows:

	Year Ended December 31,
	2011			2010			2009
Current:
US Federal	$	46		$	(256	)	$	64
State	39			41			51
Total current	85			(215		)	115
Deferred:
US Federal	(1,222		)	590			256
State	3			14			1
Total deferred	(1,219		)	604			257
Amortization of investment tax credits	—			—			(5		)
Total	$	(1,134	)	$	389		$	367

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

	Year Ended December 31,
	2011			2010			2009
Income (loss) before income taxes	$	(3,333	)	$	(2,700	)	$	775
Income taxes at the US federal statutory rate of 35%	$	(1,167	)	$	(945	)	$	271
Nondeductible goodwill impairment	—			1,435			32
Texas margin tax, net of federal benefit	27			34			30
Interest accrued for uncertain tax positions, net of tax	18			(115		)	42
Nondeductible interest expense	15			11			13
Lignite depletion allowance	(23		)	(21		)	(18		)
Amortization (under regulatory accounting) of statutory rate changes	—			—			5
Medicare subsidy — retiree benefits	—			—			(7		)
Amortization of investment tax credits, net of tax	—			—			(5		)
Nondeductible losses (earnings) on benefit plans	—			—			(1		)
Deferred tax charge for effect of health care legislation	—			8			—
Reversal of previously disallowed interest resulting from debt exchanges	(3		)	(21		)	—
Other, including audit settlements	(1		)	3			5
Income tax expense (benefit)	$	(1,134	)	$	389		$	367
Effective tax rate	34.0		%	(14.4		)%	47.4		%

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Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect as of December 31, 2011 and 2010 balance sheet dates are as follows:

	December 31,
	2011						2010
	Total		Current		Noncurrent		Total		Current		Noncurrent
Deferred Income Tax Assets
Alternative minimum tax credit carryforwards	$	382	$	—	$	382	$	406	$	—	$	406
Employee benefit obligations	207		—		207		216		25		191
Net operating loss (NOL) carryforwards	699		—		699		833		—		833
Unfavorable purchase and sales contracts	231		—		231		240		—		240
Debt extinguishment gains	560		—		560		—		—		—
Accrued interest	210		—		210		157		—		157
Other	318		—		318		317		2		315
Total	2,607		—		2,607		2,169		27		2,142
Deferred Income Tax Liabilities
Property, plant and equipment	4,239		—		4,239		4,321		—		4,321
Commodity contracts and interest rate swaps	1,391		31		1,360		1,692		31		1,661
Employee benefit obligations	16		16		—		—		—		—
Identifiable intangible assets	631		—		631		846		—		846
Debt fair value discounts	323		—		323		126		—		126
Debt extinguishment gains	—		—		—		503		—		503
Other	50		7		43		42		7		35
Total	6,650		54		6,596		7,530		38		7,492
Net Deferred Income Tax Liability	$	4,043	$	54	$	3,989	$	5,361	$	11	$	5,350

As of December 31, 2011 we had $382 million of alternative minimum tax credit carryforwards (AMT) available to offset future tax payments. The AMT credit carryforwards have no expiration date. As of December 31, 2011, we had net operating loss (NOL) carryforwards for federal income tax purposes of $2.0 billion that expire between 2029 and 2031. 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 as of December 31, 2011 and 2010 totaled a net deferred tax asset of $119 million and $141 million, respectively.

See Note 6 for discussion regarding accounting for uncertain tax positions.

Effect of Health Care Legislation — The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act enacted in March 2010 reduces, effective in 2013, the amount of OPEB costs deductible for federal income tax purposes by the amount of the Medicare Part D subsidy we receive. Under income tax accounting rules, deferred tax assets related to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in the first quarter 2010, EFH Corp.'s and Oncor's deferred tax assets were reduced by $50 million. Of this amount, $8 million was recorded as a charge to income tax expense and $42 million was recorded in receivables from unconsolidated subsidiary, reflecting a regulatory asset recorded by Oncor (before gross-up for liability in lieu of deferred income taxes) as the additional income taxes are expected to be recoverable in Oncor's future rates.

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8. OTHER INCOME AND DEDUCTIONS

	Year Ended December 31,
	2011		2010		2009
Other income:
Debt extinguishment gains (Note 10) (a)	$	51	$	1,814	$	87
Office space rental income (a)	12		12		—
Settlement of counterparty bankruptcy claims (b) (c)	21		—		—
Property damage claim (c)	7		—		—
Franchise tax refund (c)	6		—		—
Sales tax refunds	5		5		5
Gain on termination of long-term power sales contract (c) (d)	—		116		—
Gain on sale of land/water rights (c)	—		44		—
Gain on sale of interest in natural gas gathering pipeline business (c)	—		37		—
Insurance/litigation settlements (c)	—		6		—
Mineral rights royalty income (c)	3		1		6
Reversal of reserves recorded in purchase accounting (e)	—		—		44
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting (f)	—		—		39
Fee received related to interest rate swap/commodity hedge derivative agreement (Note 16) (c)	—		—		6
Other	13		16		17
Total other income	$	118	$	2,051	$	204
Other deductions:
Impairment of emission allowances (Note 4) (c)	$	418	$	—	$	—
Impairment of assets related to mining operations (Note 4) (c)	9		—		—
Net third-party fees paid in connection with the amendment and extension of the TCEH Senior Secured Facilities (Note 10) (g)	100		—		—
Ongoing pension and OPEB expense related to discontinued businesses (a)	13		7		—
Impairment of land (c)	—		—		34
Write-off of regulatory assets (f)	—		—		25
Professional fees incurred related to the Merger (h)	—		5		—
Net charges related to cancelled development of generation facilities (c)	2		3		6
Severance charges related to facility closures (c)	—		3		7
Costs related to 2006 cities rate settlement (f)	—		—		2
Litigation/regulatory settlements	—		—		3
Other	11		13		20
Total other deductions	$	553	$	31	$	97

___________

(a) Reported in Corporate and Other segment, except for $687 million of debt extinguishment gain in 2010 reported in Competitive Electric segment.

(b) 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.

(c) Reported in Competitive Electric segment.

(d) 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.

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(e) Includes $23 million for reversal of a use tax accrual, related to periods prior to the Merger, due to a state ruling in 2009 (reported in Competitive Electric segment) and $21 million for reversal of excess exit liabilities recorded in connection with the termination of outsourcing arrangements (see Note 22) (reported in Competitive Electric ($11 million) and Regulated Delivery segments ($10 million)).

(f) Reported in Regulated Delivery segment. Write off of regulatory assets reflects amounts for which the PUCT denied recovery in its 2009 final order in an Oncor rate review.

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

(h) Includes post-Merger consulting expenses related to optimizing business performance. Reported in Corporate and Other activities.

9. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

TXU Energy participates in EFH Corp.'s accounts receivable securitization program with financial institutions (the funding entities). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is an entity created for the special purpose of purchasing receivables from the originator and is a consolidated, wholly-owned, bankruptcy-remote, direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. In accordance with accounting standards effective January 1, 2010, the trade accounts receivable amounts under the program are reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to the January 1, 2010 effective date of the amended accounting standard, the activity was accounted for as a sale of accounts receivable, which resulted in the funding being recorded as a reduction of accounts receivable.

In June 2010, the accounts receivable securitization program was amended. The amendments, among other things, reduced the maximum funding amount under the program to $350 million from $700 million. Program funding increased from $96 million as of December 31, 2010 to $104 million as of December 31, 2011. Under the terms of the program, available funding as of December 31, 2011 was reduced by $38 million of customer deposits held by the originator because TCEH's credit ratings were lower than Ba3/BB-.

All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Ongoing changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued a subordinated note payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The subordinated note issued by TXU Receivables Company is subordinated to the undivided interests of the funding entities in the purchased receivables. The balance of the subordinated note payable, which is eliminated in consolidation, totaled $420 million and $516 million as of December 31, 2011 and 2010, respectively.

The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees consist primarily of interest costs on the underlying financing. Consistent with the change in balance sheet presentation of the funding discussed above, effective January 1, 2010, the program fees are reported as interest expense and related charges; program fees were previously reported as losses on sale of receivables in SG&A expense. The discount also funds a servicing fee, which is reported as SG&A expense, paid by TXU Receivables Company to EFH Corporate Services Company (Service Co.), a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.

Program fee amounts were as follows:

	Year Ended December 31,
	2011			2010			2009
Program fees	$	9		$	10		$	12
Program fees as a percentage of average funding (annualized)	6.4		%	3.8		%	2.4		%

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Activities of TXU Receivables Company were as follows:

	Year Ended December 31,
	2011			2010			2009
Cash collections on accounts receivable	$	5,080		$	6,334		$	6,125
Face amount of new receivables purchased	(4,992		)	(6,100		)	(6,287		)
Discount from face amount of purchased receivables	11			12			14
Program fees paid to funding entities	(9		)	(10		)	(12		)
Servicing fees paid to Service Co. for recordkeeping and collection services	(2		)	(2		)	(2		)
Increase (decrease) in subordinated notes payable	(96		)	53			195
Cash flows used by (provided to) originator under the program	$	(8	)	$	287		$	33

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

The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or Service Co. defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than Service Co., any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of December 31, 2011, there were no such events of termination.

Upon termination of the program, liquidity would be reduced as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. We expect that the level of cash flows would normalize in approximately 16 to 30 days.

Trade Accounts Receivable

	December 31,
	2011			2010
Wholesale and retail trade accounts receivable, including $524 and $612 in pledged retail receivables	$	794		$	1,063
Allowance for uncollectible accounts	(27		)	(64		)
Trade accounts receivable — reported in balance sheet	$	767		$	999

Gross trade accounts receivable as of December 31, 2011 and 2010 included unbilled revenues of $269 million and $297 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Year Ended December 31,
	2011			2010			2009
Allowance for uncollectible accounts receivable as of beginning of period (a)	$	64		$	81		$	70
Increase for bad debt expense	56			108			113
Decrease for account write-offs	(67		)	(125		)	(99		)
Reversal of reserve related to counterparty bankruptcy (Note 9)	(26		)	—			—
Other	—			—			(1		)
Allowance for uncollectible accounts receivable as of end of period	$	27		$	64		$	83

___________

(a) The beginning balance in 2010 is reduced by $2 million reflecting the deconsolidation of Oncor (see Note 3).

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10. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

As of 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 discussed in Note 9.

As of December 31, 2010, outstanding short-term borrowings totaled $1.221 billion, which included $1.125 billion under the TCEH Revolving Credit Facility at a weighted average interest rate of 3.80%, excluding certain customary fees, and $96 million under the accounts receivable securitization program.

Credit Facilities

Credit facilities with cash borrowing and/or letter of credit availability as of December 31, 2011 are presented below. The facilities are all senior secured facilities of TCEH.

		As of December 31, 2011
Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)	October 2013	$	645	$	—	$	211	$	434
TCEH Revolving Credit Facility (a)	October 2016	1,409		—		459		950
TCEH Letter of Credit Facility (b)	October 2017	1,062		—		1,062		—
Subtotal TCEH		$	3,116	$	—	$	1,732	$	1,384
TCEH Commodity Collateral Posting Facility (c)	December 2012	Unlimited		$	—	$	—	Unlimited

___________

(a) Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. As of December 31, 2011, borrowings under the facility maturing October 2013 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility. As of December 31, 2011, borrowings under the facility maturing October 2016 bear interest at LIBOR plus 4.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 1.00% of the average daily unused portion of the facility.

(b) Facility, $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 eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility have been retained as restricted cash that supports issuances of letters of credit and are classified as long-term debt. As of December 31, 2011, the restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009. During 2011, the facility limit was reduced by $188 million; the equivalent amount of borrowings were repaid from proceeds of a debt issuance (see "Issuance of TCEH 11.5% Senior Secured Notes" below), and subsequently that amount was removed from restricted cash and used to repay borrowings under the TCEH Revolving Credit Facility. Letters of credit totaling $778 million issued as of December 31, 2011 are supported by the restricted cash, and the remaining letter of credit availability totals $169 million.

(c) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 65 million MMBtu as of December 31, 2011. As of December 31, 2011, there were no borrowings under this facility.

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Long-Term Debt

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

	December 31,
	2011			2010
EFH Corp. (parent entity)
9.75% Fixed Senior Secured First Lien Notes due October 15, 2019	$	115		$	115
10.000% Fixed Senior Secured First Lien Notes due January 15, 2020	1,061			1,061
10.875% Fixed Senior Notes due November 1, 2017 (a)	196			359
11.25 / 12.00% Senior Toggle Notes due November 1, 2017 (a)	438			571
5.550% Fixed Senior Notes Series P due November 15, 2014 (b)	326			434
6.500% Fixed Senior Notes Series Q due November 15, 2024 (b)	740			740
6.550% Fixed Senior Notes Series R due November 15, 2034 (b)	744			744
8.820% Building Financing due semiannually through February 11, 2022 (c)	61			68
Unamortized fair value premium related to Building Financing (c)(d)	14			15
Capital lease obligations	1			4
Unamortized premium	6			—
Unamortized fair value discount (d)	(430		)	(476		)
Total EFH Corp.	3,272			3,635
EFIH
9.75% Fixed Senior Secured First Lien Notes due October 15, 2019	141			141
10.000% Fixed Senior Secured First Lien Notes due December 1, 2020	2,180			2,180
11.00% Senior Secured Second Lien Notes due October 1, 2021	406			—
Total EFIH	2,727			2,321
EFCH
9.580% Fixed Notes due in annual installments through December 4, 2019	41			46
8.254% Fixed Notes due in quarterly installments through December 31, 2021	43			46
1.229% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (e)	1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037	8			8
Unamortized fair value discount (d)	(8		)	(10		)
Total EFCH	85			91
TCEH
Senior Secured Facilities:
3.776% TCEH Term Loan Facilities maturing October 10, 2014 (e)(f)(g)	3,809			19,929
3.796% TCEH Letter of Credit Facility maturing October 10, 2014 (e)	42			1,250
0.214% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (h)	—			—
4.776% TCEH Term Loan Facilities maturing October 10, 2017 (e)(f)(i)	15,351			—
4.796% TCEH Letter of Credit Facility maturing October 10, 2017 (e)	1,020			—
11.50% Senior Secured Notes due October 1, 2020	1,750			—
15.00% Senior Secured Second Lien Notes due April 1, 2021	336			336
15.00% Senior Secured Second Lien Notes due April 1, 2021, Series B	1,235			1,235
10.25% Fixed Senior Notes due November 1, 2015 (j)	1,833			1,873
10.25% Fixed Senior Notes due November 1, 2015, Series B (j)	1,292			1,292
10.50 / 11.25% Senior Toggle Notes due November 1, 2016	1,568			1,406
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	39			39
7.700% Fixed Series 1999A due April 1, 2033	111			111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (k)	16			16
7.700% Fixed Series 1999C due March 1, 2032	50			50

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	December 31,
	2011			2010
8.250% Fixed Series 2001A due October 1, 2030	71			71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (k)	—			217
8.250% Fixed Series 2001D-1 due May 1, 2033	171			171
0.093% Floating Series 2001D-2 due May 1, 2033 (l)	97			97
0.248% Floating Taxable Series 2001I due December 1, 2036 (m)	62			62
0.093% Floating Series 2002A due May 1, 2037 (l)	45			45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (k)	44			44
6.300% Fixed Series 2003B due July 1, 2032	39			39
6.750% Fixed Series 2003C due October 1, 2038	52			52
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (k)	31			31
5.000% Fixed Series 2006 due March 1, 2041	100			100
Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021	51			51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011 (k)	—			91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011 (k)	—			107
5.200% Fixed Series 2001C due May 1, 2028	70			70
5.800% Fixed Series 2003A due July 1, 2022	12			12
6.150% Fixed Series 2003B due August 1, 2022	45			45
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028	14			14
Unamortized fair value discount related to pollution control revenue bonds (d)	(120		)	(132		)
Other:
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015	28			42
7.000% Fixed Senior Notes due March 15, 2013	5			5
Capital lease obligations	63			76
Other	3			3
Unamortized discount	(11		)	—
Unamortized fair value discount (d)	(1		)	(2		)
Total TCEH	29,323			28,848
Total EFH Corp. consolidated	35,407			34,895
Less amount due currently	(47		)	(669		)
Total long-term debt	$	35,360		$	34,226

___________

(a) Amounts exclude $1.591 billion and $1.428 billion of EFH Corp. 10.875% Notes and $2.784 billion and $2.296 billion of EFH Corp. Toggle Notes as of December 31, 2011 and 2010, respectively, that are held by EFIH and eliminated in consolidation.

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

(c) This financing is the obligation of a subsidiary of EFH Corp. (parent entity) and is secured and will be serviced with cash drawn by the beneficiary of a letter of credit.

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

(e) Interest rates in effect as of December 31, 2011.

(f) Interest rate swapped to fixed on $18.65 billion principal amount to October 2014 and up to an aggregate $12.6 billion principal amount from October 2014 through October 2017.

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

(h) Interest rate in effect as of December 31, 2011, excluding a quarterly maintenance fee of $11 million. See "Credit Facilities" above for more information.

(i) December 31, 2011 amount excludes $19 million held by EFH Corp. and eliminated in consolidation.

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(j) Amounts exclude $213 million and $173 million of the TCEH Senior Notes as of December 31, 2011 and 2010, respectively, and $150 million of the TCEH Senior Notes, Series B, as of both December 31, 2011 and 2010 that are held either by EFH Corp. or EFIH and eliminated in consolidation.

(k) 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. We repurchased the $415 million principal amount subject to mandatory tender and remarketing in November 2011.

(l) Interest rates in effect as of December 31, 2011. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(m) Interest rate in effect as of December 31, 2011. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

Debt-Related Activity in 2012

Issuance of EFIH 11.750% Senior Secured Second Lien Notes — In February 2012, EFIH and EFIH Finance issued $800 million principal amount of 11.750% Senior Secured Second Lien Notes due 2022 (EFIH 11.75% Notes). A discount of $12 million was recorded on the issuance and will be amortized over the life of the notes. The net proceeds will be used for general corporate purposes, including the payment of a $650 million dividend to EFH Corp., which was used to repay a portion of the demand notes payable by EFH Corp. to TCEH.

The EFIH 11.75% Notes mature in March 2022, with interest payable in cash semiannually in arrears on March 1 and September 1, beginning September 1, 2012, at a fixed rate of 11.75% per annum. The EFIH 11.75% Notes are secured on a second-priority basis by the EFIH Collateral, essentially EFIH's interest in Oncor Holdings, described in the discussion of the EFH Corp. 10% Senior Secured Notes below and have substantially the same covenants as the EFIH 11% Notes. The holders of the EFIH 11.75% Notes will generally vote as a single class with the holders of the EFIH 11% Notes.

Until March 1, 2015, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFIH 11.75% Notes from time to time at a redemption price of 111.750% of the aggregate principal amount of the notes being redeemed, plus accrued interest. EFIH may redeem the notes at any time prior to March 1, 2017 at a price equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. EFIH may also redeem the notes, in whole or in part, at any time on or after March 1, 2017, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture), EFIH must offer to repurchase the notes at 101% of their principal amount, plus accrued interest.

The EFIH 11.75% Notes were issued in private placements and are not registered under the Securities Act. EFIH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFIH 11.75% Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the EFIH 11.75% Notes. If the registration statement has not been filed and declared effective within 365 days after the original issue date (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter, the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.

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 the year 2011 totaled $1.431 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), $20 million of repurchases ($47 million principal amount as discussed below) and $16 million of contractual payments under capitalized lease obligations. In addition, short-term borrowings of $455 million under the TCEH Revolving Credit Facility were repaid.

During 2011, EFH Corp. issued, through the payment-in-kind (PIK) election, $43 million principal amount of its 11.25%/12.00% Senior Toggle Notes due November 2017 (EFH Corp. Toggle Notes) (excluding $312 principal amount issued to EFIH as holder of EFH Corp. Toggle Notes that are eliminated in consolidation), and TCEH issued, through the PIK election, $162 million principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes), in each case, in lieu of making cash interest payments.

137

Amendment and Extension ofTCEH Senior Secured Facilities —Borrowings under the TCEH Senior Secured Facilities totaled $20.892 billion as of December 31, 2011. In April 2011, (i) the Credit Agreement governing the TCEH Senior Secured Facilities was amended, (ii) the maturity dates of approximately 80% of the borrowings under the term loans (initial term loans and delayed draw term loans) and deposit letter of credit loans under the TCEH Senior Secured Facilities and approximately 70% of the commitments under the TCEH Revolving Credit Facility were extended, (iii) borrowings totaling $1.604 billion under the TCEH Senior Secured Facilities were repaid from proceeds of issuance of $1.750 billion principal amount of TCEH 11.5% Senior Secured Notes as discussed below and (iv) the amount of commitments under the TCEH Revolving Credit Facility was reduced by $646 million.

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

As amended, the maximum ratios for the secured debt to Adjusted EBITDA financial maintenance covenant are 8.00 to 1.00 for test periods 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 intercompany loans to EFH Corp. payable to TCEH on demand that arise from cash loaned for (i) debt principal and interest payments (P&I Note) and (ii) other general corporate purposes of EFH Corp. (SG&A Note). TCEH also agreed in the Amendment:

• not to make any further loans to EFH Corp. under the SG&A Note (as of December 31, 2011, 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 (as of December 31, 2011, the outstanding balance of the P&I Note was $1.359 billion), and

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

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

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

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

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

• the maturity of $15.351 billion principal amount of first lien term loans held by accepting lenders was extended from October 10, 2014 to October 10, 2017 and the interest rate with respect to the extended term loans was increased from LIBOR plus 3.50% to LIBOR plus 4.50%;

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

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

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

Each of the extended loans described above includes a "springing maturity" provision pursuant to which (i) in the event that more than $500 million aggregate principal amount of the TCEH 10.25% Notes due in 2015 (other than notes held by EFH Corp. or its controlled affiliates as of March 31, 2011 to the extent held as of the determination date 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 as of March 31, 2011 to the extent held as of 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 unconditionally guaranteed jointly and severally on a senior secured basis by EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US subsidiary of TCEH. The TCEH Senior Secured Facilities, along with the TCEH Senior Secured Notes and certain commodity hedging transactions and the interest rate swaps described under "TCEH Interest Rate Swap Transactions" below, are secured on a first priority basis by (i) substantially all of the current and future assets of TCEH and TCEH's subsidiaries who are guarantors of such facilities and (ii) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013 with respect to $645 million of commitments and until October 2016 with respect to $1.409 billion of commitments; such amounts borrowed totaled $211 million and $459 million, respectively, as of December 31, 2011. The TCEH Commodity Collateral Posting Facility will mature in December 2012.

In August 2009, the TCEH Senior Secured Facilities were amended to reduce the existing first lien capacity under the TCEH Senior Secured Facilities by $1.25 billion in exchange for the ability for TCEH to issue up to an additional $4 billion of secured notes or loans ranking junior to TCEH's first lien obligations, provided that:

• such notes or loans mature later than the latest maturity date of any of the initial term loans under the TCEH Senior Secured Facilities, and

• any net cash proceeds from any such issuances are used (i) in exchange for, or to refinance, repay, retire, refund or replace indebtedness of TCEH or (ii) to acquire, directly or indirectly, all or substantially all of the property and assets or business of another person or to finance the purchase price, cost of design, acquisition, construction, repair, restoration, replacement, expansion, installation or improvement of certain fixed or capital assets.

In addition, the amended facilities permit TCEH to, among other things:

• issue new secured notes or loans, which may include, in each case, debt secured on a pari passu basis with the obligations under the TCEH Senior Secured Facilities, so long as, in each case, among other things, the net cash proceeds from any such issuance are used to prepay certain loans under the TCEH Senior Secured Facilities at par;

• upon making an offer to all lenders within a particular series, agree with lenders of that series to extend the maturity of their term loans or extend or refinance their revolving credit commitments under the TCEH Senior Secured Facilities, and pay increased interest rates or otherwise modify the terms of their loans or revolving commitments in connection with such an extension, and

• exclude from the financial maintenance covenant under the TCEH Senior Secured Facilities any new debt issued that ranks junior to TCEH's first lien obligations under the TCEH Senior Secured Facilities.

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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.

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 $100 million were expensed (see Note 8).

The transactions were determined to be a significant modification of debt for federal income tax purposes, resulting in taxable cancellation of debt income of approximately $2.5 billion. The income will be reversed as deductions in future years (through 2017), and consequently a deferred tax asset has been recorded. The effect of the income on federal income taxes payable related to 2011 is expected to be largely offset by current year deductions, including the impact of bonus depreciation, and utilization of approximately $600 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);

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

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

• fund $99 million of the $799 million of total transaction costs associated with the amendment and extension of the TCEH Senior Secured Facilities discussed above, with the remainder of the transaction costs paid with cash on hand.

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

The TCEH Senior Secured Notes were issued in a private placement and are not registered under the Securities Act. The notes are a senior obligation and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured and second-priority debt of TCEH to the extent of the value of the TCEH Collateral and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

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The guarantees of the TCEH Senior Secured Notes by the Guarantors are effectively senior to any unsecured and second-priority debt of the Guarantors to the extent of the value of the TCEH Collateral. The guarantees are effectively subordinated to all debt of the Guarantors secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt.

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

• make restricted payments, including certain investments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets, and

• engage in certain transactions with affiliates.

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

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

Issuance of EFIH 11% Senior Secured Second Lien Notes in Exchange for EFH Corp. Debt — In April 2011, EFIH and EFIH Finance issued $406 million principal amount of 11% Senior Secured Second Lien Notes due 2021 in exchange for $428 million of EFH Corp. debt consisting of $163 million principal amount of EFH Corp. 10.875% Notes due 2017, $229 million principal amount of EFH Corp. Toggle Notes due 2017 and $36 million principal amount of EFH Corp. 5.55% Series P Senior Notes due 2014. The transaction resulted in a debt extinguishment gain of $25 million (reported as other income). EFIH intends to hold the exchanged securities as an investment.

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

The EFIH 11% Notes were issued in private placements and are not registered under the Securities Act. The notes are a senior obligation of EFIH and EFIH Finance and rank equally in right of payment with all senior indebtedness of EFIH and are effectively senior in right of payment to all existing or future unsecured debt of EFIH to the extent of the value of the EFIH Collateral. The notes are effectively subordinated to all debt of EFIH that is either (i) secured by a lien on the EFIH Collateral that is senior to the second-priority liens securing the EFIH 11% Notes or (ii) secured by assets other than the EFIH Collateral, to the extent of the value of the collateral securing that debt. Furthermore, the EFIH 11% Notes are (i) structurally subordinated to all indebtedness and other liabilities of EFIH's subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries, any of EFIH's future foreign subsidiaries and any other unrestricted subsidiaries and (ii) senior in right of payment to any future subordinated indebtedness of EFIH.

The indenture governing the EFIH 11% Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFIH's and its restricted subsidiaries' ability to:

• make restricted payments, including certain investments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets, and

• engage in certain transactions with affiliates.

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The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur under the indenture, the trustee or the holders of at least 30% of the aggregate principal amount of all outstanding EFIH 11% Notes may declare the principal amount on all such notes to be due and payable immediately. The holders of the EFIH 11% Notes will generally vote as a single class with the holders of the EFIH 11.75% Notes under the terms of the indenture.

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

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

Issuance of New EFH Corp. Toggle Notes in Exchange for EFH Corp. Series P Notes — In a private exchange in October 2011, EFH Corp. issued $53 million principal amount of new EFH Corp. 11.25%/12.00% Toggle Notes due 2017 in exchange for $65 million principal amount of EFH Corp. 5.55% Series P Senior Notes due 2014 (EFH Corp. 5.55% Notes), which EFH Corp. retired. The new EFH Corp. Toggle Notes have substantially the same terms and conditions and are subject to the same indenture as the existing EFH Corp. Toggle Notes. A premium totaling $6 million was recorded on the transaction and is being amortized to interest expense over the life of the new notes. Concurrent with the exchange, EFIH issued a dividend to EFH Corp. of $53 million principal amount of EFH Corp. Toggle Notes, which EFH Corp. retired. EFIH had previously held the EFH Corp. Toggle Notes as an investment, which was eliminated in consolidation.

2011 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 is holding the TCEH 10.25% Notes as an investment, which is eliminated in consolidation. The transactions resulted in debt extinguishment gains totaling $26 million (reported as other income).

Debt-Related Activity in 2010

Repayments of long-term debt in 2010 totaling $309 million included $205 million of principal payments at scheduled maturity dates as well as other repayments totaling $104 million principally related to capitalized leases. See "2010 Debt Exchanges, Repurchases and Issuances" below for discussion of $6.904 billion principal amount of debt acquired in debt exchanges and repurchases completed in the year ended December 31, 2010.

During 2010, EFH Corp. issued, through the payment-in-kind (PIK) election, $194 million principal amount of EFH Corp. Toggle Notes, and TCEH issued, through the PIK election, $205 million principal amount of TCEH Toggle Notes, in each case, in lieu of making cash interest payments.

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2010 Debt Exchanges, Repurchases and Issuances — Debt exchanges and repurchases completed in 2010 resulted in acquisitions of $6.904 billion aggregate principal amount of outstanding EFH Corp. and TCEH debt with due dates largely 2017 or earlier in exchange for $3.962 billion aggregate principal amount of new debt and $1.042 billion in cash. The new debt issued in exchange transactions consisted of $2.180 billion aggregate principal amount of EFIH 10% Notes due 2020, $561 million aggregate principal amount of EFH Corp. 10% Notes due 2020, $336 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 and $885 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 (Series B). EFH Corp. also issued $500 million principal amount of EFH Corp. 10% Notes due 2020 for cash, and TCEH issued $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021 for cash. A discussion of these transactions and descriptions of the EFIH 10% Notes, EFH Corp. 10% Notes and TCEH 15% Senior Secured Second Lien Notes are presented below.

Transactions completed in the year ended December 31, 2010 were as follows:

• In November, TCEH and TCEH Finance issued $885 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021 in exchange for $850 million aggregate principal amount of TCEH 10.25% Notes and $420 million aggregate principal amount of TCEH Toggle Notes.

• In October, TCEH and TCEH Finance issued $336 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 in exchange for $423 million aggregate principal amount of TCEH 10.25% Notes (plus accrued interest paid in cash) and $55 million aggregate principal amount of TCEH Toggle Notes (together, the TCEH Senior Notes).

• In October, TCEH and TCEH Finance issued $350 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021, and used the $343 million of net proceeds to repurchase $240 million principal amount of TCEH 10.25% Notes (including $14 million from EFH Corp.) and $283 million principal amount of TCEH Toggle Notes (including $83 million from EFH Corp.) and paid accrued interest from cash on hand. TCEH paid $53 million of the net proceeds for the TCEH notes held by EFH Corp., which were retired.

• In a debt exchange transaction in August, EFIH and EFIH Finance issued $2.180 billion aggregate principal amount of EFIH 10% Notes due 2020 and paid $500 million in cash, plus accrued interest, in exchange for $2.166 billion aggregate principal amount of EFH Corp. Toggle Notes and $1.428 billion aggregate principal amount of EFH Corp. 10.875% Notes (together, the EFH Corp. Senior Notes).

• Between April and July, EFH Corp. issued $527 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $549 million principal amount of EFH Corp. 5.55% Notes, $110 million principal amount of EFH Corp. Toggle Notes, $25 million principal amount of EFH Corp. 10.875% Notes, $13 million principal amount of TCEH 10.25% Notes and $17 million principal amount of TCEH Toggle Notes.

• In March, EFH Corp. issued $34 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $20 million principal amount of EFH Corp. Toggle Notes and $27 million principal amount of TCEH Toggle Notes.

• In January, EFH Corp. issued $500 million aggregate principal amount of EFH Corp. 10% Notes due 2020, with the proceeds intended to be used for general corporate purposes including debt exchanges and repurchases.

• In addition, from time to time in 2010, EFH Corp. repurchased $124 million principal amount of EFH Corp. Toggle Notes, $19 million principal amount of EFH Corp. 10.875% Notes, $181 million principal amount of TCEH 10.25% Notes, $32 million principal amount of TCEH Toggle Notes and $20 million principal amount of initial term loans under the TCEH Senior Secured Facilities for $252 million in cash plus accrued interest.

These transactions resulted in debt extinguishment gains totaling $1.814 billion (reported as other income).

In connection with the debt exchange transactions, EFH Corp. received the requisite consents from holders of the EFH Corp. Senior Notes and EFH Corp. 5.55% Notes applicable to certain amendments to the respective indentures governing such notes. These amendments, among other things, eliminated substantially all of the restrictive covenants, eliminated certain events of default, modified covenants regarding mergers and consolidations and modified or eliminated certain other provisions in such indentures.

The EFH Corp. notes acquired by EFIH and the majority of the TCEH notes and initial term loans under the TCEH Senior Secured Facilities acquired by EFH Corp. were held as investments by EFIH and EFH Corp., and eliminated in consolidation. All other securities acquired in the above transactions were cancelled.

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Maturities — Long-term debt maturities as of December 31, 2011, excluding amounts held by EFH Corp. and EFIH as investments and eliminated in consolidation, are as follows:

Year:
2012	$	33
2013	91
2014 (a)	4,265
2015	3,301
2016	1,742
Thereafter (a)	26,461
Unamortized premiums	20
Unamortized discounts	(570		)
Capital lease obligations	64
Total	$	35,407

___________

(a) Long-term debt maturities for EFH Corp. (parent entity) total $8.049 billion, including $371 million in 2014 and $7.678 billion after 2016, as well as $4.429 billion held by EFIH that is not included above.

Information Regarding Other Significant Outstanding Debt

TCEH 10.25% Senior Notes (including Series B) and 10.50/11.25% Senior Toggle Notes (collectively, the TCEH Senior Notes)— The TCEH 10.25% Notes mature in November 2015, with interest payable in cash semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.25% per annum. The 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. For any interest period until November 2012, TCEH may elect to pay interest on the Toggle Notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.

The TCEH Senior Notes had a total principal amount as of December 31, 2011 of $4.693 billion (excluding $362 million principal amount held by EFH Corp. and EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH's direct parent, EFCH (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.

TCEH may redeem the TCEH Toggle Notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. TCEH may redeem the TCEH 10.25% Notes and TCEH Toggle Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, 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.

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TCEH 15% Senior Secured Second Lien Notes(including Series B)— These notes mature in April 2021, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1 at a fixed rate of 15% per annum. The notes are unconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH that guarantees the TCEH Senior Secured Credit 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 Credit 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.

As of December 31, 2011, there were $1.571 billion total principal amount of TCEH Senior Secured Second Lien Notes. The TCEH Senior Secured Second Lien Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured 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 Credit Facilities 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.

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.

The TCEH Senior Secured Second Lien Notes were initially issued in private placements and have not been registered under the Securities Act. In September and October 2011, TCEH satisfied certain transferability conditions with respect to the TCEH Senior Secured Second Lien Notes. As a result of the satisfaction of these conditions, the notes are now freely transferable without restriction by persons that are not affiliates of TCEH under the Securities Act.

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

As of December 31, 2011, there were $1.061 billion total principal amount of EFH Corp. 10% Notes. The EFH Corp. 10% Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of EFH Corp. and are senior in right of payment to any future subordinated indebtedness of EFH Corp. These notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.'s non-guarantor subsidiaries.

The guarantees of the EFH Corp. 10% Notes are the general senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantee from EFIH is effectively senior to all unsecured indebtedness of EFIH to the extent of the value of the EFIH Collateral. The guarantees are effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the EFIH Collateral to the extent of the value of the assets securing such indebtedness and are structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.'s subsidiaries that are not guarantors.

The indenture for the EFH Corp. 10% Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFH Corp.'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.

These notes and indenture also contain 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 these notes and the indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payable immediately.

Until January 15, 2013, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFH Corp. 10% Notes from time to time at a redemption price of 110.000% of the aggregate principal amount of the notes being redeemed, plus accrued and unpaid interest. EFH Corp. may redeem the notes at any time prior to January 15, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after January 15, 2015, at specified redemption prices, plus accrued and unpaid interest. Upon the occurrence of a change of control (as described in the indenture), EFH Corp. must offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest.

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

The EFH Corp. Senior Notes had a total principal amount as of December 31, 2011 of $634 million (excluding $4.375 billion principal amount held by EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by EFCH and EFIH.

EFH Corp. may redeem these notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the related indenture. EFH Corp. may also redeem these notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFH Corp., EFH Corp. must offer to repurchase the EFH Corp. Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

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

EFH Corp. 9.75% Notes and EFIH 9.75% Notes — The EFH Corp. 9.75% Notes and EFIH 9.75% Notes mature in October 2019, with interest payable in cash semi-annually in arrears on April 15 and October 15 at a fixed rate of 9.75% per annum. The EFH Corp. 9.75% Notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH. The guarantee from EFIH is secured by the pledge of the EFIH Collateral. The guarantee from EFCH is not secured. The EFIH 9.75% Notes are secured by the EFIH Collateral on an equal and ratable basis with the EFIH 10% Notes and EFIH's guarantee of the EFH Corp. 10% Notes and the EFH Corp. 9.75% Notes.

As of December 31, 2011, there were $115 million and $141 million total principal amount of EFH Corp. 9.75% Notes and EFIH 9.75% Notes, respectively. The EFH Corp. 9.75% Notes and EFIH 9.75% Notes are senior obligations of each issuer and rank equally in right of payment with all senior indebtedness of each issuer and are senior in right of payment to any future subordinated indebtedness of each issuer. The EFH Corp. 9.75% Notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.'s non-guarantor subsidiaries. The EFIH 9.75% Notes are effectively senior to all unsecured indebtedness of EFIH, to the extent of the value of the EFIH Collateral, and will be effectively subordinated to any indebtedness of EFIH secured by assets of EFIH other than the EFIH Collateral, to the extent of the value of the assets securing such indebtedness. Furthermore, the EFIH 9.75% Notes will be structurally subordinated to all indebtedness and other liabilities of EFIH's subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries.

The guarantees of the EFH Corp. 9.75% Notes are the general senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantee from EFIH is effectively senior to all unsecured indebtedness of EFIH to the extent of the value of the EFIH Collateral. The guarantee will be effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the EFIH Collateral to the extent of the value of the assets securing such indebtedness and will be structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.'s subsidiaries that are not guarantors.

The indentures for the EFH Corp. 9.75% Notes and EFIH 9.75% Notes contain a number of covenants that, among other things, restrict, subject to certain exceptions, the issuers' and their 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.

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

There currently are no restricted subsidiaries under the indenture related to the EFIH 9.75% Notes (other than EFIH Finance, which has no assets). Oncor Holdings, the immediate parent of Oncor, and its subsidiaries are unrestricted subsidiaries under the EFIH indenture and, accordingly, are not subject to any of the restrictive covenants in the indenture.

The respective issuers may redeem the EFH Corp. 9.75% Notes and EFIH 9.75% Notes, in whole or in part, at any time on or after October 15, 2014, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before October 15, 2012, the respective issuers may redeem up to 35% of the aggregate principal amount of each series of the notes from time to time at a redemption price of 109.750% of the aggregate principal amount of such series of notes, plus accrued and unpaid interest, if any, with the net cash proceeds of certain equity offerings. The respective issuers may also redeem each series of the notes at any time prior to October 15, 2014 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. Upon the occurrence of a change of control (as described in the indenture), the respective issuers may be required to offer to repurchase each series of the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

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

As of December 31, 2011, there were $2.180 billion total principal amount of EFIH 10% Notes. The EFIH 10% Notes are senior obligations of EFIH and rank equally in right of payment with all existing and future senior indebtedness of EFIH (including the EFIH 9.75% Notes and EFIH's guarantees of the EFH Corp. Senior Secured Notes). The EFIH 10% Notes are effectively senior to all unsecured indebtedness of EFIH, to the extent of the value of the EFIH Collateral, and are effectively subordinated to any indebtedness of EFIH secured by assets of EFIH other than the EFIH Collateral, to the extent of the value of the assets securing such indebtedness. Furthermore, the EFIH 10% Notes are (i) structurally subordinated to all indebtedness and other liabilities of EFIH's subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries, any of EFIH's future foreign subsidiaries and any other unrestricted subsidiaries and (ii) senior in right of payment to any future subordinated indebtedness of the Issuers.

The indenture for the EFIH 10% Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFIH's and its restricted subsidiaries' ability to:

• make restricted payments, including certain investments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets, and

• engage in certain transactions with affiliates.

The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes or the guarantees when due. If certain events of default occur and are continuing under the notes and the indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payable immediately. Currently, there are no restricted subsidiaries under the indenture (other than EFIH Finance, which has no assets). Oncor Holdings, Oncor and their respective subsidiaries are unrestricted subsidiaries under the EFIH 10% Notes and the indenture and, accordingly, are not subject to any of the restrictive covenants in the notes and the related indenture.

Until December 1, 2013, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFIH 10% Notes from time to time at a redemption price of 110% of the aggregate principal amount of the notes being redeemed, plus accrued and unpaid interest, if any. EFIH may redeem the EFIH 10% Notes, in whole or in part, at any time prior to December 1, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest, if any, and the applicable premium as defined in the indenture. EFIH may redeem any of the EFIH 10% Notes, in whole or in part, at any time on or after December 1, 2015, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control (as defined in the indenture), EFIH may be required to offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

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Intercreditor Agreement — In October 2007, TCEH entered into an intercreditor agreement with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). In connection with the August 2009 amendment to the TCEH Secured Facilities described above, the intercreditor agreement was amended and restated (as amended and restated, the Intercreditor Agreement) to take 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 — In October 2010, TCEH 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.

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TCEHInterest Rate Swap Transactions

TCEH employs interest rate swaps to hedge exposure to its variable rate senior secured debt. As reflected in the table below, as of December 31, 2011, 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 2012 through October 2014	$18.65 billion (a)
6.8% — 9.0%	October 2015 through October 2017	$12.60 billion (b)

___________

(a) Includes swaps entered into in 2011 related to an aggregate $5.45 billion principal amount of debt growing to $10.58 billion over time, generally as existing swaps expire. Swaps related to an aggregate $2.60 billion principal amount of debt expired or were terminated in 2011.

(b) These swaps were all entered into in 2011 and are effective from October 2014 through October 2017. The $12.6 billion notional amount of swaps includes $3 billion that expires in October 2015 and the remainder in October 2017.

TCEH has also entered into interest rate basis swap transactions that further reduce the fixed (through swaps) borrowing costs. Basis swaps in effect at December 31, 2011 related to an aggregate $17.75 billion principal amount of senior secured debt through 2014, an increase of $2.55 billion from December 31, 2010 reflecting new and expired swaps. A forward-starting basis swap was entered into in 2011 related to an aggregate $1.42 billion principal amount of senior secured debt effective for a 21-month period beginning February 2012.

The interest rate swap counterparties are proportionately secured 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,
	2011			2010			2009
Realized net loss	$	(684	)	$	(673	)	$	(684	)
Unrealized net gain (loss)	(812		)	(207		)	696
Total	$	(1,496	)	$	(880	)	$	12

The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.231 billion and $1.419 billion as of December 31, 2011 and 2010, respectively, of which $76 million and $105 million (both pre-tax), respectively, was reported in accumulated other comprehensive income.

See Note 16 for discussion of collateral investments in 2009 related to certain of these interest rate swaps.

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11. COMMITMENTS AND CONTINGENCIES

Contractual Commitments

As of December 31, 2011, we had noncancellable commitments under energy-related contracts, leases and other agreements as follows:

	Coal purchase agreements and coal transportation agreements		Pipeline transportation and storage reservation fees		Capacity payments under power purchase agreements (a)		Nuclear Fuel  Contracts		Other Contracts
2012	$	361	$	29	$	75	$	247	$	38
2013	377		1		—		148		26
2014	343		—		—		114		24
2015	225		—		—		179		25
2016	72		—		—		133		25
Thereafter	—		—		—		700		137
Total	$	1,378	$	30	$	75	$	1,521	$	275

___________

(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 $463 million, $445 million and $316 million for the years ended December 31, 2011, 2010 and 2009, respectively.

As of December 31, 2011, future minimum lease payments under both capital leases and operating leases are as follows:

	Capital Leases		Operating Leases (a)
2012	$	17	$	48
2013	10		43
2014	6		41
2015	4		38
2016	4		37
Thereafter	33		197
Total future minimum lease payments	74		$	404
Less amounts representing interest	10
Present value of future minimum lease payments	64
Less current portion	14
Long-term capital lease obligation	$	50

___________

(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 $91 million, $89 million and $92 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Commitment to Fund Demand Side Management Initiatives

In connection with the Merger, Texas Holdings committed to spend $100 million on demand side management or other energy efficiency initiatives over a five-year period ending in 2012. As of December 31, 2011, we had spent more than 60% of this commitment. This commitment is expected to be funded by EFH Corp. and/or its subsidiaries other than Oncor. This commitment is in addition to approximately $340 million expected to be invested by Oncor for similar initiatives.

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Guarantees

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

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

See Note 10 for discussion of guarantees and security for certain of our debt.

Letters of Credit

As of December 31, 2011, TCEH had outstanding letters of credit under its credit facilities totaling $778 million as follows:

• $363 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);

• $76 million to support TCEH's REP's financial requirements with the PUCT, and

• $131 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 seek a reversal of the TCEQ's order and a remand back to the TCEQ for further proceedings. In addition to this administrative appeal, in November 2010, two other petitions were filed in Travis County, Texas District Court by Sustainable Energy and Economic Development Coalition and Paul and Lisa Rolke, respectively, who were non-parties to the administrative hearing before the State Office of Administrative Hearings, challenging the TCEQ's decision to renew and amend Oak Grove's TPDES permit and asking the District Court to remand the matter to the TCEQ for further proceedings. In January 2012, the petition filed by Paul and Lisa Rolke was dismissed. Although we cannot predict the outcome of these proceedings, we believe that the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and that the application for and the processing of Oak Grove's TPDES permit renewal and amendment by the TCEQ were in accordance with applicable law. There can be no assurance that the outcome of these matters would not result in a material impact on our results of operations, liquidity or financial condition.

In January 2012, the Sierra Club filed a petition in Travis County, Texas District Court challenging the TCEQ's decision to issue permit amendments imposing limits on emissions during planned startup, shutdown and maintenance activities at Luminant's Big Brown, Monticello, Martin Lake and Sandow Unit 4 generation facilities. Although we cannot predict the outcome of this proceeding, we believe that the permit amendments are protective of the environment and in accordance with applicable law. There can be no assurance that the outcome of this matter would not result in a material impact on our results of operations, liquidity or financial condition.

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In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violations of the Clean Air Act at Luminant's Martin Lake generation facility. While we are unable to estimate any possible loss or predict the outcome of the litigation, we believe that the Sierra Club's claims are without merit, and we intend to vigorously defend this litigation. The litigation is currently stayed by the court. In addition, in February 2010, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Big Brown generation facility. Subsequently, in December 2010, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Monticello generation facility. In October 2011, the Sierra Club again informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Big Brown and Monticello generation facilities. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

See Note 4 for discussion of our petition for review in the D.C. Circuit Court challenging the CSAPR and a motion to stay the effective date of the CSAPR, in each case as applied to Texas.

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

Other Matters

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

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, new 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 new four-year labor agreement was reached covering bargaining unit personnel engaged in natural gas-fueled generation operations. In October 2010, new 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. In August 2010, a new 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.

Environmental Contingencies

See Note 4 for discussion of the federal Clean Air Act, as amended, and the CSAPR issued 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. In addition, all air pollution control provisions of the 1999 legislation that restructured the electric utility industry in Texas to provide for retail competition have been satisfied.

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.

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The costs to comply with environmental regulations can 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 in Note 4 and the EPA's MATS rule for coal and oil-fueled generation units to replace the federal Clean Air Mercury Rule (CAMR) as a result of similar court rulings, and

• the identification of sites requiring clean-up or the filing of other complaints in which we may be asserted to be potential responsible parties.

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).

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.

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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.

12. EQUITY

Equity Issuances and Repurchases

Changes in common stock shares outstanding for each of the last three years are reflected (in millions of shares) in the table below. Essentially all shares issued and purchased were as a result of stock-based compensation transactions for the benefit of certain officers, directors and employees. See Note 19 for discussion of stock-based compensation.

	Year Ended December 31,
	2011	2010		2009
Shares outstanding as of beginning of year	1,671.8	1,668.1		1,667.2
Shares issued (a)	7.7	3.9		1.5
Shares repurchased	—	(0.2	)	(0.6	)
Shares outstanding as of end of year	1,679.5	1,671.8		1,668.1

____________

(a) Includes share awards granted to directors and other nonemployees (see Note 19). 2011 and 2010 issuances also included 0.2 million and 1.2 million shares of previously issued restricted or deferred stock units that vested in 2011 and 2010, respectively.

Dividend Restrictions

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

The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our common stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or on a pro forma basis, after giving effect to such distribution, EFH Corp.'s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, "consolidated leverage ratio" is defined as the ratio of consolidated total debt (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. EFH Corp.'s consolidated leverage ratio was 9.7 to 1.0 as of December 31, 2011.

In addition, the indentures governing the EFIH Notes generally restrict EFIH from making any cash distribution to EFH Corp. for the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend, EFIH's consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indentures governing the EFIH Notes, the term "consolidated leverage ratio" is defined as the ratio of EFIH's consolidated total debt (as defined in the indentures) to EFIH's Adjusted EBITDA on a consolidated basis (including Oncor's Adjusted EBITDA). EFIH's consolidated leverage ratio was 5.3 to 1.0 as of December 31, 2011.

The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. As of December 31, 2011, the ratio was 8.7 to 1.0.

In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and TCEH Senior Secured Second Lien Notes generally restrict TCEH's ability to make distributions or loans to any of its parent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and the indentures governing such notes. See discussion in Note 10 regarding amendments to the TCEH Senior Secured Facilities affecting intercompany loans from TCEH to EFH Corp.

In addition, under applicable law, we are 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.

155

Shareholder Actions

In May 2009, the shareholders of EFH Corp. approved the change of the stated capital of EFH Corp.'s common stock, no par value per share, to an amount equal to $0.001 for each outstanding share of common stock, resulting in total stated value of outstanding common stock of $2 million. Also in May 2009, EFH Corp.'s board of directors approved a decrease in additional paid-in capital of the same amount and the allocation of $0.001 per share to stated value of common stock upon issuance of any authorized but unissued shares of common stock that may occur from time to time, with the remainder of any amounts received for such shares allocated to additional paid-in capital.

Common Stock Registration Rights

The Sponsor Group and certain other investors entered into a registration rights agreement with EFH Corp. upon closing of the Merger. Pursuant to this agreement, in certain instances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.'s common stock owned directly or indirectly by them under the Securities Act. In certain instances, the Sponsor Group and certain other investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.'s common stock under the Securities Act that it may undertake.

See Note 19 for discussion of stock-based compensation plans.

13. NONCONTROLLING INTERESTS

As of December 31, 2011, ownership of Oncor's membership interests was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor's management and board of directors and 19.75% held by Texas Transmission. See Notes 1 and 3 for discussion of the deconsolidation of Oncor effective January 1, 2010.

As discussed in Note 3, we consolidate a joint venture formed in 2009 for the purpose of developing two new nuclear generation units, which results in a noncontrolling interests component of equity. Net loss attributable to the noncontrolling interests was immaterial for the years ended December 31, 2011, 2010 and 2009.

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14. FAIR VALUE MEASUREMENTS

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

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

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

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

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

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.

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

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With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

As of December 31, 2011, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification(b)		Total
Assets:
Commodity contracts	$	395	$	3,915	$	124	$	1	$	4,435
Interest rate swaps	—		142		—		—		142
Nuclear decommissioning trust – equity securities (c)	208		124		—		—		332
Nuclear decommissioning trust – debt securities (c)	—		242		—		—		242
Total assets	$	603	$	4,423	$	124	$	1	$	5,151
Liabilities:
Commodity contracts	$	446	$	727	$	71	$	1	$	1,245
Interest rate swaps	—		2,397		—		—		2,397
Total liabilities	$	446	$	3,124	$	71	$	1	$	3,642

___________

(a) Level 3 assets and liabilities consist primarily of a complex wind generation purchase contract, physical power call options, congestion revenue rights transactions as discussed below and ancillary service agreements, each due to unobservable inputs in the valuation.

(b) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c) The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 17.

See Note 18 for fair value measurements related to pension and OPEB plan assets.

158

As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification(b)		Total
Assets:
Commodity contracts	$	727	$	3,575	$	401	$	2	$	4,705
Interest rate swaps	—		98		—		—		98
Nuclear decommissioning trust – equity securities (c)	192		121		—		—		313
Nuclear decommissioning trust – debt securities (c)	—		223		—		—		223
Total assets	$	919	$	4,017	$	401	$	2	$	5,339
Liabilities:
Commodity contracts	$	875	$	672	$	59	$	2	$	1,608
Interest rate swaps	—		1,544		—		—		1,544
Total liabilities	$	875	$	2,216	$	59	$	2	$	3,152

___________

(a) Level 3 assets and liabilities consist primarily of a complex wind generation purchase contract, certain natural gas positions (collars) in the natural gas price hedging program, physical power call options, congestion revenue rights transactions as discussed below and ancillary service agreements, each due to unobservable inputs in the valuation.

(b) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c) The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 17.

In conjunction with ERCOT's transition to a nodal wholesale market structure effective December 2010, we have entered into certain derivative transactions (primarily congestion revenue rights transactions) that are valued at illiquid pricing locations (unobservable inputs), thus requiring classification as Level 3 assets or liabilities. As the nodal market matures and more transaction and pricing information becomes available for these pricing locations, we expect more of the valuation inputs to become observable.

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 16 for further discussion regarding the company's use of derivative instruments.

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 10 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2011 and 2010. See the table below for discussion of transfers between Level 2 and Level 3 in the year ended December 31, 2011.

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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, 2011, 2010 and 2009:

	Year Ended December 31,
	2011			2010			2009
Balance as of beginning of period	$	342		$	81		$	(72	)
Total realized and unrealized gains (losses):
Included in net income (loss)	(1		)	266			115
Included in other comprehensive income	—			—			(30		)
Purchases, issuances and settlements (a):
Purchases	117			68			137
Issuances	(15		)	(31		)	(86		)
Settlements	(41		)	(11		)	—
Transfers into Level 3 (b)	—			(12		)	2
Transfers out of Level 3 (b)	(349		)	(19		)	15
Net change (c)	(289		)	261			153
Balance as of end of period	$	53		$	342		$	81
Net change in unrealized gains (losses) included in net income relating to instruments held as of end of period	$	17		$	111		$	105

___________

(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. For 2011 and 2010, in accordance with new accounting guidance issued by the FASB in January 2010, transfers in and out occur at the end of each quarter, which is when the assessments are performed. Prior period transfers in were assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter. Significant transfers out occurred during the first quarter 2011 for natural gas collars for 2014; these derivatives are now categorized as Level 2 due to an increase in option market trading activity in forward periods. Significant transfers out occurred during the third quarter 2011 for 2014 coal contracts, these derivatives are now categorized as Level 2 due to increased liquidity in forward periods.

(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.

15. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

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

	December 31, 2011				December 31, 2010
	Carrying Amount		Fair Value (a)		Carrying Amount		Fair Value (a)
On balance sheet liabilities:
Long-term debt (including current maturities) (b)	$	35,343	$	23,402	$	34,815	$	26,594
Off balance sheet liabilities:
Financial guarantees	$	—	$	3	$	—	$	9

___________

(a) Fair value determined in accordance with accounting standards related to the determination of fair value as discussed in Note 14. We obtain security pricing from a vendor who uses broker quotes and third-party pricing services to determine fair values, which are validated through subscription services such as Bloomberg where relevant.

(b) Excludes capital leases.

See Notes 14 and 16 for discussion of accounting for financial instruments that are derivatives.

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16. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term commodity hedging program and the hedging of interest costs on our long-term debt. See Note 14 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 significant portion of electricity price exposure related to expected lignite/coal- and nuclear-fueled generation for this period. Changes in the fair value of the instruments under the natural gas price hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 10 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 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 as of December 31, 2011 and 2010:

December 31, 2011
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	2,883		$	142	$	—		$	—		$	3,025
Noncurrent assets	1,552			—		—			—			1,552
Current liabilities	(1		)	—		(1,162		)	(787		)	(1,950		)
Noncurrent liabilities	—			—		(82		)	(1,610		)	(1,692		)
Net assets (liabilities)	$	4,434		$	142	$	(1,244	)	$	(2,397	)	$	935

December 31, 2010
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	2,637		$	95	$	—		$	—		$	2,732
Noncurrent assets	2,068			3		—			—			2,071
Current liabilities	(2		)	—		(1,542		)	(739		)	(2,283		)
Noncurrent liabilities	—			—		(64		)	(805		)	(869		)
Net assets (liabilities)	$	4,703		$	98	$	(1,606	)	$	(1,544	)	$	1,651

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As of December 31, 2011 and 2010, there were no derivative positions accounted for as cash flow or fair value hedges.

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $1.006 billion and $479 million in net liabilities as of December 31, 2011 and 2010, respectively. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

In 2009, we entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which we elected to enter into as a cash management measure, EFH Corp. (parent) posted $400 million in cash and TCEH posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. In accordance with the agreements, the counterparties returned the collateral, along with accrued interest, in March 2010.

The following table presents the pre-tax effect on net income of derivatives not under hedge accounting, including realized and unrealized effects:

	Year Ended December 31,
Derivative (Income statement presentation)	2011			2010			2009
Commodity contracts (Net gain from commodity hedging and trading activities) (a)	$	1,139		$	2,162		$	1,741
Commodity contracts (Other income) (b)	—			116			—
Interest rate swaps (Interest expense and related charges) (c)	(1,496		)	(880		)	12
Net gain (loss)	$	(357	)	$	1,398		$	1,753

___________

(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 8).

(c) Includes amounts reported as unrealized mark-to-market net gain (loss) as well as the net effect on interest paid/accrued, both reported in "Interest Expense and Related Charges" (see Note 22).

The following table presents the pre-tax effect on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges. There were no amounts recognized in OCI for the years ended December 31, 2011 or 2010. In the year ended December 31, 2009, $30 million of losses were recognized in OCI related to the effective portion of commodity contract hedges.

Derivative Type (income statement presentation of loss reclassified from accumulated OCI into income)
	Year Ended December 31,
	2011			2010			2009
Interest rate swaps (interest expense and related charges)	$	(27	)	$	(87	)	$	(184	)
Interest rate swaps (depreciation and amortization)	(2		)	(2		)	—
Commodity contracts (fuel, purchased power costs and delivery fees)	—			—			(16		)
Commodity contracts (operating revenues)	—			(1		)	(2		)
Total	$	(29	)	$	(90	)	$	(202	)

There were no transactions designated as cash flow hedges during the years ended December 31, 2011 and 2010. There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the year ended December 31, 2009.

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Accumulated other comprehensive income related to cash flow hedges (excluding Oncor's interest rate hedge) as of December 31, 2011 and 2010 totaled $50 million and $69 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $7 million of net losses (after-tax) related to cash flow hedges included in accumulated other comprehensive income as of December 31, 2011 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes as of December 31, 2011 and 2010:

	December 31,
	2011		2010
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed	$	32,955	$	17,500	Million US dollars
Basis (a)	$	19,167	$	15,200	Million US dollars
Natural gas:
Natural gas price hedge forward sales and purchases (b)	1,602		2,681		Million MMBtu
Locational basis swaps	728		1,092		Million MMBtu
All other	841		887		Million MMBtu
Electricity	105,673		143,776		GWh
Congestion Revenue Rights (c)	142,301		15,782		GWh
Coal	23		6		Million tons
Fuel oil	51		109		Million gallons
Uranium	480		—		Thousand pounds

___________

(a) Includes $1.417 billion notional amount of swaps entered into as of December 31, 2011 but not effective until February 2012.

(b) Represents gross notional forward sales, purchases and options transactions in the natural gas price hedging program. The net amount of these transactions was approximately 700 million MMBtu and 1.0 billion MMBtu as of December 31, 2011 and 2010, respectively.

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

Credit Risk-Related Contingent Features of Derivatives

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

As of December 31, 2011 and 2010, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $364 million and $408 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $78 million and $65 million as of December 31, 2011 and 2010, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of December 31, 2011 and 2010, the remaining related liquidity requirement would have totaled $7 million and $18 million, respectively, after reduction for net accounts receivable and derivative assets under netting arrangements.

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In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of December 31, 2011 and 2010, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $2.816 billion and $1.865 billion, respectively, before consideration of the amount of assets under the liens. No cash collateral or letters of credit were posted with these counterparties as of December 31, 2011 and 2010 to reduce the liquidity exposure. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of December 31, 2011 and 2010, the remaining related liquidity requirement after reduction for derivative assets under netting arrangements but before consideration of the amount of assets under the liens would have totaled $1.183 billion and $674 million, respectively. See Note 10 for a description of other obligations that are supported by asset liens.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $3.180 billion and $2.273 billion as of December 31, 2011 and 2010, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.

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

Concentrations of Credit Risk Related to Derivatives

TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of December 31, 2011, total credit risk exposure to all counterparties related to derivative contracts totaled $4.7 billion (including associated accounts receivable). The net exposure to those counterparties totaled $825 million as of December 31, 2011 after taking into effect master netting arrangements, setoff provisions and collateral. The net exposure assuming setoff provisions in the event of default across all EFH Corp. consolidated subsidiaries totaled $580 million. As of December 31, 2011, the credit risk exposure to the banking and financial sector represented 92% of the total credit risk 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 $245 million. Taking into account setoff provisions in the event of a default across all EFH Corp. consolidated subsidiaries did not materially affect this counterparty exposure.

Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because a significant majority of this exposure is with counterparties with credit ratings of "A-" or better. However, this concentration increases the risk that a default by any of these counterparties would have a material 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 netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material 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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17. OTHER INVESTMENTS

The other investments balance consists of the following:

	December 31,
	2011		2010
Nuclear plant decommissioning trust	$	574	$	536
Assets related to employee benefit plans, including employee savings programs, net of distributions	90		117
Land	41		41
Miscellaneous other	4		3
Total other investments	$	709	$	697

Nuclear Plant Decommissioning Trust

Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding change in receivables from/payables due to unconsolidated subsidiary, reflecting changes in Oncor's regulatory asset/liability (see Note 20). A summary of investments in the fund follows:

	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
	December 31, 2010
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	221	$	6	$	(4	)	$	223
Equity securities (c)	213		115		(15		)	313
Total	$	434	$	121	$	(19	)	$	536

___________

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

(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.38% and 4.61% and an average maturity of 6.3 years and 8.8 years as of December 31, 2011 and 2010, respectively.

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

Debt securities held as of December 31, 2011 mature as follows: $98 million in one to five years, $53 million in five to ten years and $91 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,
	2011			2010			2009
Realized gains	$	1		$	1		$	1
Realized losses	$	(3	)	$	(2	)	$	(6	)
Proceeds from sales of securities	$	2,419		$	974		$	3,064
Investments in securities	$	(2,436	)	$	(990	)	$	(3,080	)

165

Assets Related to Employee Benefit Plans

The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. We pay the premiums and are the beneficiary of these life insurance policies.

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

EFH Corp. is the plan sponsor of the EFH Retirement Plan (Retirement Plan), which provides benefits to eligible employees of subsidiaries (participating employers), including Oncor. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.

Effective October 1, 2007, all new employees, with the exception of employees hired by Oncor, are not eligible to participate in the Retirement Plan. New hires at Oncor are eligible to participate in the Cash Balance Formula of the Retirement Plan. It is our policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.

We also have 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.

We 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.

Regulatory Recovery of Pension and OPEB Costs

PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor's own employees consists largely of active and retired personnel engaged in TCEH's activities, related to service of those additional personnel prior to the deregulation and disaggregation of our businesses effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs reflected in Oncor's tariffs as approved by the PUCT and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. As of December 31, 2011 and 2010, Oncor had recorded regulatory assets totaling $884 million and $1.048 billion, respectively, related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.

Pension and OPEB Costs Recognized as Expense

	Year Ended December 31,
	2011			2010			2009
Pension costs	$	141		$	100		$	44
OPEB costs	94			80			70
Total benefit costs	$	235		$	180		$	114
Less amounts expensed by Oncor (and not consolidated)	(37		)	(37		)	—
Less amounts deferred principally as a regulatory asset or property by Oncor	(130		)	(93		)	(66		)
Net amounts recognized as expense by EFH Corp. and consolidated subsidiaries	$	68		$	50		$	48

166

We use the calculated value method to determine the market-related value of the assets held in trust. We include 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.

Detailed Information Regarding Pension Benefits

The following information is based on December 31, 2011, 2010 and 2009 measurement dates (includes amounts related to Oncor):

	Year Ended December 31,
	2011			2010			2009
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate	5.50		%	5.90		%	6.90		%
Expected return on plan assets	7.70		%	8.00		%	8.25		%
Rate of compensation increase	3.74		%	3.71		%	3.75		%
Components of Net Pension Cost:
Service cost	$	45		$	42		$	38
Interest cost	162			160			159
Expected return on assets	(157		)	(160		)	(166		)
Amortization of prior service cost	1			1			1
Amortization of net actuarial loss	90			57			12
Net periodic pension cost	$	141		$	100		$	44
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net loss	$	54		$	27		$	45
Amortization of net gain	(29		)	(19		)	—
Total loss (income) recognized in other comprehensive income	$	25		$	8		$	45
Total recognized in net periodic benefit cost and other comprehensive income	$	166		$	108		$	89
Assumptions Used to Determine Benefit Obligations:
Discount rate	5.00		%	5.50		%	5.90		%
Rate of compensation increase	3.81		%	3.74		%	3.71		%

167

	Year Ended December 31,
	2011			2010
Change in Pension Obligation:
Projected benefit obligation as of beginning of year	$	3,072		$	2,742
Service cost	46			42
Interest cost	165			160
Actuarial loss	181			253
Benefits paid	(133		)	(125		)
Settlements	—			—
Projected benefit obligation as of end of year	$	3,331		$	3,072
Accumulated benefit obligation as of end of year	$	3,130		$	2,863
Change in Plan Assets:
Fair value of assets as of beginning of year	$	2,185		$	2,004
Actual return on assets	178			261
Employer contributions	179			45
Benefits paid	(133		)	(125		)
Fair value of assets as of end of year	$	2,409		$	2,185
Funded Status:
Projected pension benefit obligation	$	(3,331	)	$	(3,072	)
Fair value of assets	2,409			2,185
Funded status as of end of year	$	(922	)	$	(887	)
Amounts Recognized in the Balance Sheet Consist of:
Other noncurrent assets (a)	$	23		$	10
Other current liabilities	(5		)	(5		)
Other noncurrent liabilities	(940		)	(892		)
Net liability recognized	$	(922	)	$	(887	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss	$	286		$	261
Amounts Recognized by Oncor as Regulatory Assets Consist of:
Net loss	$	659		$	616
Prior service cost	—			—
Net amount recognized	$	659		$	616

___________

(a) Amounts represent overfunded plans.

The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.

	December 31,
	2011		2010
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations	$	3,327	$	3,067
Accumulated benefit obligation	$	3,126	$	2,858
Plan assets	$	2,394	$	2,170

168

Pension Plan Investment Strategy and Asset Allocations

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Equity securities are held to achieve returns in excess of passive indexes by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging international markets. Fixed income securities include primarily corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. Our investment strategy for fixed income investments is to maintain a high grade portfolio of securities which assist us in managing the volatility and magnitude of plan contributions and expense while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses.

The target asset allocation ranges of pension plan investments by asset category are as follows:

Asset Category:	Target Allocation Ranges
US equities	12% - 34%
International equities	10% - 26%
Fixed income	40% - 70%
Other	0% - 10%

Fair Value Measurement of Pension Plan Assets

As of December 31, 2011, pension plan assets measured at fair value (see Note 14) on a recurring basis consisted of the following:

Asset Category:	Level 1		Level 2		Level 3		Total
Interest-bearing cash	$	—	$	94	$	—	$	94
Equity securities:
US	411		84		—		495
International	238		78		—		316
Fixed income securities:
Corporate bonds (a)	—		1,341		—		1,341
US Treasuries	—		53		—		53
Other (b)	—		96		—		96
Preferred securities	—		—		14		14
Total assets	$	649	$	1,746	$	14	$	2,409

___________

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

(b) Other consists primarily of US agency securities.

169

As of December 31, 2010, pension plan assets measured at fair value on a recurring basis consisted of the following:

Asset Category:	Level 1		Level 2		Level 3		Total
Interest-bearing cash	$	—	$	69	$	—	$	69
Equity securities:
US	422		94		—		516
International	248		84		—		332
Fixed income securities:
Corporate bonds (a)	—		1,137		—		1,137
US Treasuries	—		21		—		21
Other (b)	—		96		—		96
Preferred securities	—		—		14		14
Total assets	$	670	$	1,501	$	14	$	2,185

___________

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

(b) Other consists primarily of US agency securities.

There was no significant change in the fair values of Level 3 assets in the periods presented.

Detailed Information Regarding Postretirement Benefits Other Than Pensions

The following OPEB information is based on December 31, 2011, 2010 and 2009 measurement dates (includes amounts related to Oncor):

	Year Ended December 31,
	2011			2010			2009
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate	5.55		%	5.90		%	6.85		%
Expected return on plan assets	7.10		%	7.60		%	7.64		%
Components of Net Postretirement Benefit Cost:
Service cost	$	14		$	13		$	10
Interest cost	65			61			61
Expected return on assets	(14		)	(15		)	(13		)
Amortization of net transition obligation	1			1			1
Amortization of prior service cost/(credit)	(1		)	(1		)	(1		)
Amortization of net actuarial loss	29			21			12
Net periodic OPEB cost	$	94		$	80		$	70
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Prior service credit	$	(77	)	$	—		$	—
Net (gain) loss	(15		)	14			15
Amortization of net gain	(2		)	(1		)	—
Total loss recognized in other comprehensive income	$	(94	)	$	13		$	15
Total recognized in net periodic benefit cost and other comprehensive income	$	—		$	93		$	85
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate	4.95		%	5.55		%	5.90		%

170

	Year Ended December 31,
	2011			2010
Change in Postretirement Benefit Obligation:
Benefit obligation as of beginning of year	$	1,191		$	1,063
Service cost	14			13
Interest cost	65			61
Participant contributions	17			17
Medicare Part D reimbursement	7			4
Plan amendments	(204		)	—
Actuarial (gain) loss	(112		)	98
Benefits paid	(62		)	(65		)
Benefit obligation as of end of year	$	916		$	1,191
Change in Plan Assets:
Fair value of assets as of beginning of year	$	211		$	211
Actual return on assets	8			24
Employer contributions	26			24
Participant contributions	17			17
Benefits paid	(62		)	(65		)
Fair value of assets as of end of year	$	200		$	211
Funded Status:
Benefit obligation	$	(916	)	$	(1,191	)
Fair value of assets	200			211
Funded status as of end of year	$	(716	)	$	(980	)
Amounts Recognized on the Balance Sheet Consist of:
Other current liabilities	$	(5	)	$	(7	)
Other noncurrent liabilities	(711		)	(973		)
Net liability recognized	$	(716	)	$	(980	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Prior service credit	$	(77	)	$	—
Net loss	19			36
Net amount recognized	$	(58	)	$	36
Amounts Recognized by Oncor as Regulatory Assets Consist of:
Net loss	$	178		$	296
Prior service credit	(131		)	(5		)
Net transition obligation	1			3
Net amount recognized	$	48		$	294

171

The following tables provide information regarding the assumed health care cost trend rates.

	December 31,
	2011		2010
Assumed Health Care Cost Trend Rates-Not Medicare Eligible :
Health care cost trend rate assumed for next year	9.00	%	9.00	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2022		2021
Assumed Health Care Cost Trend Rates-Medicare Eligible :
Health care cost trend rate assumed for next year	8.00	%	8.00	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2022		2021

	1-Percentage  Point Increase		1-Percentage Point Decrease
Sensitivity Analysis of Assumed Health Care Cost Trend Rates :
Effect on accumulated postretirement obligation	$	102	$	(87	)
Effect on postretirement benefits cost	$	6	$	(5	)

OPEB Plan Investment Strategy and Asset Allocations

Our investment objective for the OPEB plan primarily follows the objectives of the Retirement Plan discussed above, while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses. The actual amounts as of December 31, 2011 provided below are consistent with the company's asset allocation targets.

Fair Value Measurement of OPEB Plan Assets

As of December 31, 2011, OPEB plan assets measured at fair value on a recurring basis consisted of the following:

Asset Category:	Level 1		Level 2		Level 3		Total
Interest-bearing cash	$	—	$	10	$	—	$	10
Equity securities:
US	53		4		—		57
International	23		3		—		26
Fixed income securities:
Corporate bonds (a)	—		55		—		55
US Treasuries	—		2		—		2
Other (b)	46		3		—		49
Preferred securities	—		—		1		1
Total assets	$	122	$	77	$	1	$	200

___________

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

(b) Other consists primarily of US agency securities.

172

As of December 31, 2010, OPEB plan assets measured at fair value on a recurring basis consisted of the following:

Asset Category:	Level 1		Level 2		Level 3		Total
Interest-bearing cash	$	—	$	11	$	—	$	11
Equity securities:
US	62		4		—		66
International	27		4		—		31
Fixed income securities:
Corporate bonds (a)	—		55		—		55
US Treasuries	—		1		—		1
Other (b)	42		4		—		46
Preferred securities	—		—		1		1
Total assets	$	131	$	79	$	1	$	211

___________

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

(b) Other consists primarily of US agency securities.

There was no significant change in the fair values of Level 3 assets in the periods presented.

Expected Long-Term Rate of Return on Assets Assumption

The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.

Retirement Plan
Asset Class:	Expected Long-Term Rate of Return
US equity securities	8.2	%
International equity securities	9.7	%
Fixed income securities	4.4	%
Weighted average	7.4	%

OPEB Plan
Plan Type:	Expected Long-Term Returns
401(h) accounts	7.4	%
Life Insurance VEBA	6.8	%
Union VEBA	6.8	%
Non-Union VEBA	3.1	%
Weighted average	6.8	%

VEBA refers to Voluntary Employee Beneficiary Association, a form of trust fund permitted under federal tax laws with the sole purpose of providing employee benefits.

173

Significant Concentrations of Risk

The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.

Assumed Discount Rate

We selected the assumed discount rate using the Aon Hewitt AA Above Median yield curve, which is based on actual corporate bond yields and as of December 31, 2011 consisted of 261 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings.

Amortization in 2012

In 2012, we estimate amortization of the net actuarial loss and prior service cost for the defined benefit pension plan from accumulated other comprehensive income into net periodic benefit cost will be $110 million and $0.2 million, respectively. We estimate amortization of the net actuarial loss, prior service credit, and transition obligation for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will be $15 million, a $31 million credit and $1 million, respectively.

Contributions in 2012 and 2011

Estimated funding for calendar year 2012 totals $124 million for the Retirement Plan and $24 million for the OPEB plan, including approximately $140 million to be funded by Oncor. We made pension and OPEB contributions of $176 million and $26 million, respectively, in 2011, of which $190 million was contributed by Oncor.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:

	2012			2013		2014		2015		2016		2017-21
Pension benefits	$	154		$	165	$	169	$	179	$	190	$	1,118
OPEB	$	57		$	50	$	53	$	56	$	59	$	321
Medicare Part D subsidies	$	(7	)	$	—	$	—	$	—	$	—	$	—

Thrift Plan

Our employees may participate in a qualified savings plan (the 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 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 $20 million, $19 million and $28 million in the years ended December 31, 2011, 2010 and 2009, respectively.

174

19. STOCK-BASED COMPENSATION

EFH Corp. 2007 Stock Incentive Plan

In December 2007, we established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007 SIP). 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. The 2007 SIP permits the grant of awards for 72 million shares of common stock, subject to adjustments under applicable laws for certain events, such as a change in control, and no such grants may be issued after December 26, 2017. Shares related to grants that are forfeited, terminated, cancelled, expire unexercised, withheld to satisfy tax withholding obligations, or are repurchased by the Company are available for new grants under the 2007 SIP.

Stock-based compensation expense recorded in the years ended December 31, 2011, 2010 and 2009 was as follows:

	Year Ended December 31,
Type of award	2011		2010		2009
Restricted stock units granted to employees	$	3	$	—	$	—
Stock options granted to employees	7		17		10
Other share and share-based awards	3		2		4
Total compensation expense	$	13	$	19	$	14

Restricted Stock Units — Restricted stock unit activity, all of which occurred in 2011, consisted of the issuance of 20.5 million units in exchange for stock options as discussed below, grants of 4.7 million units and forfeitures of 1.0 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. As of December 31, 2011, there was approximately $17.9 million of unrecognized compensation expense related to nonvested restricted stock units expected to be recognized through September 2014.

Stock Options — Options to purchase 3.8 million and 14.7 million shares of EFH Corp. common stock were granted to certain management employees in 2010 and 2009, respectively. No options were granted in 2011. Of the options granted in 2010 and 2009, 1.6 million and 9.2 million, respectively, were granted in exchange for previously granted options. 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 $3 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 3.1 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.

175

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 eligible employees accepted the offer, which resulted in the issuance of 9.4 million restricted stock units in exchange for 16.1 million time-based options (including 5.2 million that were vested) and 2.8 million performance-based options (including 2.0 million that were vested).

In 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 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 11.1 million restricted stock units in exchange for 16.7 million time-based options (including 6.2 million that were vested) and 5.5 million performance-based options (including 3.5 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 are 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 as of the grant date.

The weighted average grant-date fair value of the Time-Based Options granted in 2010 and 2009 was $1.16 and $1.32 per option, respectively. The weighted-average grant-date fair value of the Performance-Based Options granted in 2009 ranged from $1.16 to $1.91 depending upon the performance period.

Assumptions supporting the fair values were as follows:

	Year Ended December 31,
	2010	2009	2009
Assumptions:	Time-Based Options		Performance-Based Options
Expected volatility	30% – 35%	30%	30%
Expected annual dividend	—	—	—
Expected life (in years)	6.1 – 7.3	6.4 – 7.4	5.3 – 7.6
Risk-free rate	2.69% – 3.20%	2.54% – 3.14%	2.51% – 3.25%

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. As of December 31, 2011, there was approximately $12.4 million of unrecognized compensation expense related to nonvested Time-Based Options, which is expected to be recognized ratably over a remaining weighted-average period of approximately one to three years. The exchange of time-based options for restricted stock units was considered a modification of the option award for accounting purposes.

176

A summary of Time-Based Options activity is presented below:

Time-Based Options Activity in 2011:	Options (millions)		Weighted Average Exercise Price
Total outstanding as of beginning of period	37.2		$	4.31
Granted	—		$	—
Exercised	—		$	—
Forfeited	(2.9	)	$	4.01
Exchanged	(32.8	)	$	4.32
Total outstanding as of end of period (weighted average remaining term of 6 – 10 years)	1.5		$	4.67
Exercisable as of end of period (weighted average remaining term of 6 – 10 years)	—		$	—
Expected forfeitures	(1.5	)	$	4.67
Expected to vest as of 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 as of beginning of period	35.6		$	4.42
Granted	3.8		$	3.41
Exercised	—		$	—
Forfeited	(2.2	)	$	4.53
Total outstanding as of end of period (weighted average remaining term of 7 – 10 years)	37.2		$	4.31
Exercisable as of end of period (weighted average remaining term of 7 – 10 years)	(4.8	)	$	4.71
Expected forfeitures	(0.1	)	$	5.00
Expected to vest as of end of period (weighted average remaining term of 7 – 10 years)	32.3		$	4.25

Time-Based Options Activity in 2009:	Options (millions)		Weighted Average Exercise Price
Total outstanding as of beginning of period	24.6		$	5.00
Granted	13.9		$	3.50
Exercised	—		$	—
Forfeited	(2.9	)	$	5.00
Total outstanding as of end of period (weighted average remaining term of 8 – 10 years)	35.6		$	4.42
Exercisable as of end of period (weighted average remaining term of 8 – 10 years)	(4.7	)	$	5.00
Expected forfeitures	(0.3	)	$	5.00
Expected to vest as of end of period (weighted average remaining term of 8 – 10 years)	30.6		$	4.32

	2011				2010				2009
Nonvested Time-Based Options Activity:	Options (millions)		Weighted Average Grant- Date Fair Value		Options (millions)		Weighted Average Grant- Date Fair Value		Options (millions)		Weighted Average Grant- Date Fair Value
Total nonvested as of beginning of period	23.0		$	1.59	26.2		$	1.67	19.9		$	2.05
Granted	—		$	—	3.8		$	1.16	13.9		$	1.32
Vested	—		$	—	(4.8	)	$	1.63	(4.7	)	$	1.86
Forfeited	(1.6	)	$	1.24	(2.2	)	$	1.70	(2.9	)	$	1.85
Exchanged	(21.4	)	$	1.54	—		$	—	—		$	—
Total nonvested as of end of period	—		$	—	23.0		$	1.59	26.2		$	1.67

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.

177

As of December 31, 2011, 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 4.8 million of the 2008 and 2.0 million of the 2009 Performance-Based Options had vested.

A summary of Performance-Based Options activity is presented below:

Performance-Based Options Activity in 2011:	Options (millions)		Weighted Average Exercise Price
Outstanding as of beginning of period	11.1		$	4.89
Granted	—		$	—
Exercised	—		$	—
Forfeited	(1.0	)	$	5.00
Exchanged	(8.3	)	$	4.89
Total outstanding as of end of period (weighted average remaining term of 6 – 8 years)	1.8		$	5.00
Exercisable as of end of period (weighted average remaining term of 6 – 8 years)	—		$	—
Expected forfeitures	(1.8	)	$	5.00
Expected to vest as of end of period (weighted average remaining term of 6 – 8 years)	—		$	—

Performance-Based Options Activity in 2010:	Options (millions)		Weighted Average Exercise Price
Outstanding as of beginning of period	12.5		$	4.90
Granted	—		$	—
Exercised	—		$	—
Forfeited	(1.4	)	$	5.00
Exchanged	—		$	—
Total outstanding as of end of period (weighted average remaining term of 7 – 10 years)	11.1		$	4.89
Exercisable as of end of period (weighted average remaining term of 7 – 10 years)	(2.0	)	$	5.00
Expected forfeitures	—		$	—
Expected to vest as of end of period (weighted average remaining term of 7 – 10 years)	9.1		$	4.87

Performance-Based Options Activity in 2009:	Options (millions)		Weighted Average Exercise Price
Outstanding as of beginning of period	23.9		$	5.00
Granted	0.8		$	3.50
Exercised	—		$	—
Forfeited	(3.0	)	$	5.00
Exchanged	(9.2	)	$	5.00
Total outstanding as of end of period (weighted average remaining term of 8 – 10 years)	12.5		$	4.90
Exercisable as of end of period (weighted average remaining term of 8 – 10 years)	(4.8	)	$	5.00
Expected forfeitures	(0.3	)	$	5.00
Expected to vest as of end of period (weighted average remaining term of 8 – 10 years)	7.4		$	4.90

	2011				2010				2009
Performance-Based Nonvested Options Activity:	Options (millions)		Grant-Date Fair Value		Options (millions)		Grant-Date Fair Value		Options (millions)		Grant-Date Fair Value
Total nonvested as of beginning of period	4.3		$1.16 – 2.11		7.7		$1.16 – 2.11		23.9		$1.73 – 2.21
Granted	—		$	—	—		$	—	0.8		$1.16 – 1.91
Vested	—		$	—	(2.0	)	$1.62 – 1.87		(4.8	)	$1.73 – 2.21
Forfeited	(1.0	)	$1.66 – 2.01		(1.4	)	$1.60 – 1.87		(3.0	)	$1.73 – 2.21
Exchanged	(2.8	)	$1.16 – 2.11		—		$	—	(9.2	)	$	—
Total nonvested as of end of period	0.5		$1.92 – 2.01		4.3		$1.16 – 2.11		7.7		$1.16 – 2.11

178

Other Share and Share-Based Awards — In 2008, we granted 2.4 million deferred share awards, each of which represents the right to receive one share of EFH Corp. stock, to certain 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. An additional 1.2 million deferred share awards were granted to certain management employees in 2008, approximately half of which are payable in cash or stock and the balance payable in stock; all of these awards have since vested or have been surrendered upon termination of employment. Expenses recognized in 2011, 2010 and 2009 related to these grants totaled $0.1 million, $0.4 million and $3.7 million, respectively. Deferred share awards that are payable in cash or stock are accounted for as liability awards; therefore, the effects of changes in the estimated value of EFH Corp. shares are recognized in earnings. As a result of the decline in estimated value of EFH Corp. shares, share-based compensation expense in 2011, 2010, and 2009 was reduced by $3.5 million, $3.3 million and $3.6 million, respectively.

Directors and other nonemployees were granted 7.5 million shares of EFH Corp. stock in 2011, 2.7 million shares in 2010 and 1.5 million shares in 2009. The shares vest over periods of one to two years, and a portion may be settled in cash. Expense recognized in 2011, 2010 and 2009 related to these grants totaled $6.8 million, $4.7 million and $4.0 million, respectively.

179

20. RELATED–PARTY TRANSACTIONS

The following represent our significant related-party transactions.

• We pay an annual management fee under the terms of a management agreement with the Sponsor Group, which we reported in SG&A expense totaling $37 million, $37 million and $36 million for the years ended December 31, 2011, 2010 and 2009, respectively.

• In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with us and/or provided financial advisory services to us, in each case in the normal course of business, and participated on terms similar to nonaffiliated lenders in the April 2011 amendment and extension of the TCEH Senior Secured Facilities discussed in Note 10.

• In February 2012, Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, acted as a joint book-running manager and initial purchaser in the issuance of $800 million principal amount of EFIH 11.750% Senior Secured Second Lien Notes (see Note 5) for which it received fees totaling $4 million. An affiliate of KKR served as a co-manager and initial purchaser and an affiliate of TPG Capital, L.P. served as an advisor in the transaction, for which they each received $1 million.

In the year ended December 31, 2011, fees paid to Goldman related to debt issuances and exchanges 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 discussed in Note 10 and received fees totaling $17 million; (ii) Goldman also acted as a joint book-running manager and initial purchaser in the issuance of $1.750 billion principal amount of TCEH Senior Secured Notes as part of the April 2011 amendment and extension and received fees totaling $9 million. Affiliates of KKR and TPG Capital, L.P. served as advisers to these transactions and each received $5 million as compensation for their services.

In the year ended December 31, 2010, fees paid to Goldman related to debt issuances and exchanges totaled $11 million, described as follows: (i) Goldman acted as an initial purchaser in the issuance of $500 million principal amount of EFH Corp. 10% Notes in January 2010 for which it received fees totaling $3 million; (ii) Goldman acted as a dealer manager and solicitation agent in EFH Corp. and EFIH debt exchange offers completed in August 2010 for which it received fees totaling $7 million; (iii) Goldman also acted as an initial purchaser in the issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) in October 2010 and received fees totaling $1 million.

In the year ended December 31, 2009, fees paid to affiliates of the Sponsor Group participating in debt exchange offers completed in November 2009 by EFH Corp., EFIH and EFIH Finance to exchange new senior secured notes for certain EFH Corp. and TCEH notes totaled $1 million. Goldman and KKR Capital Markets LLC, an affiliate of KKR, acted as dealer managers and TPG Capital, L.P. served as an adviser in the exchange offers.

• Affiliates of GS Capital Partners are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

• Affiliates of the Sponsor Group have, and in the future may, sell or acquire debt or debt securities issued by us in open market transactions or through loan syndications.

• TCEH has made loans to EFH Corp. in the form of demand notes that have been pledged as collateral under the TCEH Senior Secured Facilities for (i) debt principal and interest payments and (ii) other general corporate purposes for EFH Corp. The demand notes are eliminated in consolidation in these consolidated financial statements. The notes, which totaled $1.592 billion and $1.921 billion as of December 31, 2011 and 2010, respectively, and approximately $960 million as of February 15, 2012, are guaranteed by both EFCH and EFIH (see Note 10).

180

• As part of EFH Corp.'s liability management program, EFH Corp. and EFIH have purchased, or received in exchanges, certain debt securities of EFH Corp. and TCEH, which are held as investments. Principal and interest payments received by EFH Corp. and EFIH on these investments are used, in part, to service outstanding debt. These investments are eliminated in consolidation in these consolidated financial statements. As of December 31, 2011, EFIH held $4.429 billion principal amount of EFH Corp. (parent entity) debt and $79 million principal amount of TCEH debt. As of December 31, 2011, EFH Corp. (parent entity) held $302 million principal amount of TCEH debt. See Note 10.

The following transactions reflect the deconsolidation of Oncor Holdings effective January 1, 2010 as discussed in Notes 1 and 3.

• TCEH's retail operations pay electricity delivery fees to Oncor. Amounts expensed for these fees totaled $1.0 billion and $1.1 billion for the years ended December 31, 2011 and 2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheet as of December 31, 2011 and 2010 reflects amounts due currently to Oncor totaling $138 million and $143 million, respectively, (included in payables due to unconsolidated subsidiary), primarily related to these electricity delivery fees.

• Oncor's bankruptcy-remote financing subsidiary has issued securitization bonds to recover generation-related regulatory assets through a transition surcharge to its customers. Oncor's incremental income taxes related to the transition surcharges it collects are being reimbursed by TCEH. Therefore, the balance sheet reflects a noninterest bearing note payable maturing in 2016 to Oncor of $179 million ($41 million current portion included in payables due to unconsolidated subsidiary) and $217 million ($39 million current portion included in payables due to unconsolidated subsidiary) as of December 31, 2011 and 2010, respectively. TCEH's payments on the note totaled $39 million and $37 million for the years ended December 31, 2011 and 2010, respectively.

• TCEH reimburses Oncor for interest expense on Oncor's bankruptcy-remote financing subsidiary's securitization bonds. This interest expense, which is paid on a monthly basis, totaled $32 million and $37 million for the years ended December 31, 2011 and 2010, respectively.

• Oncor pays EFH Corp. subsidiaries for financial and other administrative services and shared facilities at cost. Such amounts reduced reported selling, general and administrative expense by $38 million and $40 million for the years ended December 31, 2011 and 2010, respectively.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in other investments on the balance sheet, is funded by a delivery fee surcharge billed to REPs by Oncor and remitted monthly to TCEH, with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported in noncurrent liabilities on the balance sheet. The delivery fee surcharges remitted to TCEH totaled $17 million and $16 million in the years ended December 31, 2011 and 2010, respectively. Income and expenses associated with the trust fund and the decommissioning liability incurred by us are offset by a net change in the intercompany receivable/payable between Oncor and TCEH, which in turn results in a change in Oncor's net regulatory asset/liability. As of December 31, 2011 and 2010, the excess of the trust fund balance over the decommissioning liability resulted in a payable to Oncor totaling $225 million and $206 million, respectively, included in noncurrent liabilities due to unconsolidated subsidiary in the balance sheet.

• We file a consolidated federal income tax return; however, under a tax sharing agreement, Oncor Holdings' federal income tax and Texas margin tax expense and related balance sheet amounts, including our income taxes payable to or receivable from Oncor Holdings, are recorded as if Oncor Holdings files its own corporate income tax return. Our current amount receivable from Oncor Holdings related to income taxes totaled $2 million as of December 31, 2011, and amounts payable to Oncor Holdings related to income taxes, primarily due to timing of payments, totaled $72 million as of December 31, 2010. EFH Corp. issued net income tax refunds to Oncor Holdings totaling $89 million (net of $20 million in tax payments from Oncor Holdings) in the year ended December 31, 2011 and received net income tax payments from Oncor Holdings totaling $107 million in the year ended December 31, 2010.

• Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP's obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH's credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, as of December 31, 2011 and 2010, TCEH had posted letters of credit in the amount of $12 million and $14 million, respectively, for the benefit of Oncor.

181

• EFH Corp. and Oncor are jointly and severally liable for the funding of the EFH Corp. pension plan and a portion of the OPEB plan obligations. EFH Corp. is liable for the majority of the OPEB plan obligations. Oncor has contractually agreed to reimburse EFH Corp. with respect to certain pension plan and OPEB liabilities. Accordingly, as of December 31, 2011 and 2010, the balance sheet of EFH Corp. reflects unfunded liabilities related to these obligations and a corresponding receivable from Oncor in the amount of $1.235 billion and $1.463 billion, respectively, classified as noncurrent. This amount represents the obligations reported by Oncor in its balance sheet, which are recoverable by Oncor under regulatory rate-setting provisions.

• Receivables from unconsolidated subsidiary are measured at historical cost and consist of Oncor's obligation under the EFH Corp. pension and OPEB plans. EFH Corp. reviews Oncor's credit quality to assess the overall collectability of its affiliated receivables, which totaled $1.235 billion and $1.463 billion as of December 31, 2011 and 2010, respectively. There were no credit loss allowances as of December 31, 2011.

• 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.

182

21. SEGMENT INFORMATION

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

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

The Regulated Delivery segment consists largely of our investment in Oncor. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary. See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings and its subsidiaries effective as of January 1, 2010. See Note 20 for discussion of material transactions with Oncor, including payment to Oncor of electricity delivery fees, which are based on rates regulated by the PUCT.

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

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. We evaluate performance based on net income (loss). We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices or regulated rates.

	Year Ended December 31,
	2011		2010		2009
Operating revenues
Competitive Electric	$	7,040	$	8,235	$	7,911
Regulated Delivery	—		—		2,690
Corp. and Other	—		—		20
Eliminations	—		—		(1,075		)
Consolidated	$	7,040	$	8,235	$	9,546
Regulated revenues — included in operating revenues
Competitive Electric	$	—	$	—	$	—
Regulated Delivery	—		—		2,690
Corp. and Other	—		—		—
Eliminations	—		—		(1,051		)
Consolidated	$	—	$	—	$	1,639
Affiliated revenues — included in operating revenues
Competitive Electric	$	—	$	—	$	8
Regulated Delivery	—		—		1,051
Corp. and Other	—		—		16
Eliminations	—		—		(1,075		)
Consolidated	$	—	$	—	$	—
Depreciation and amortization
Competitive Electric	$	1,471	$	1,380	$	1,172
Regulated Delivery	—		—		557
Corp. and Other	28		27		25
Eliminations	—		—		—
Consolidated	$	1,499	$	1,407	$	1,754

183

	Year Ended December 31,
	2011			2010			2009
Equity in earnings (losses) of unconsolidated subsidiaries (net of tax)
Competitive Electric	$	—		$	—		$	(7	)
Regulated Delivery	286			277			(2		)
Corp. and Other	—			—			(3		)
Eliminations	—			—			12
Consolidated	$	286		$	277		$	—
Interest income
Competitive Electric	$	87		$	91		$	64
Regulated Delivery	—			—			43
Corp. and Other	139			151			147
Eliminations	(224		)	(232		)	(209		)
Consolidated	$	2		$	10		$	45
Interest expense and related charges
Competitive Electric	$	3,830		$	2,957		$	1,946
Regulated Delivery	—			—			346
Corp. and Other	688			829			829
Eliminations	(224		)	(232		)	(209		)
Consolidated	$	4,294		$	3,554		$	2,912
Income tax expense (benefit)
Competitive Electric	$	(963	)	$	359		$	407
Regulated Delivery	—			—			173
Corp. and Other	(171		)	30			(213		)
Eliminations	—			—			—
Consolidated	$	(1,134	)	$	389		$	367
Net income (loss)
Competitive Electric	$	(1,825	)	$	(3,463	)	$	631
Regulated Delivery	286			277			320
Corp. and Other	(374		)	374			(543		)
Eliminations	—			—			—
Consolidated	$	(1,913	)	$	(2,812	)	$	408
Investment in equity investees
Competitive Electric	$	—		$	—		$	42
Regulated Delivery	5,720			5,544			—
Corp. and Other	—			—			—
Eliminations	—			—			—
Consolidated	$	5,720		$	5,544		$	42
Total assets
Competitive Electric	$	37,409		$	39,202		$	43,302
Regulated Delivery	5,720			5,544			16,246
Corp. and Other	4,394			5,045			4,355
Eliminations	(3,446		)	(3,403		)	(4,241		)
Consolidated	$	44,077		$	46,388		$	59,662
Capital expenditures
Competitive Electric	$	529		$	796		$	1,324
Regulated Delivery	—			—			998
Corp. and Other	23			42			26
Eliminations	—			—			—
Consolidated	$	552		$	838		$	2,348

184

22. SUPPLEMENTARY FINANCIAL INFORMATION

Interest Expense and Related Charges

	Year Ended December 31,
	2011			2010			2009
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	3,027		$	2,681		$	2,955
Accrued interest to be paid with additional toggle notes (Note 10)	219			446			524
Unrealized mark-to-market net (gain) loss on interest rate swaps	812			207			(696		)
Amortization of interest rate swap losses at dedesignation of hedge accounting	27			87			184
Amortization of fair value debt discounts resulting from purchase accounting	52			63			82
Amortization of debt issuance, amendment and extension costs and discounts (a)	188			130			140
Capitalized interest	(31		)	(60		)	(277		)
Total interest expense and related charges	$	4,294		$	3,554		$	2,912

___________

(a) Includes write-offs of $16 million of previously deferred fees as a result of the amendment and extension transactions in April 2011 (see Note 10).

Restricted Cash

	December 31, 2011				December 31, 2010
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH's Letter of Credit Facility (See Note 10)	$	—	$	947	$	—	$	1,135
Amounts related to margin deposits held	129		—		33		—
Total restricted cash	$	129	$	947	$	33	$	1,135

Inventories by Major Category

	December 31,
	2011		2010
Materials and supplies	$	177	$	162
Fuel stock	203		198
Natural gas in storage	38		35
Total inventories	$	418	$	395

185

Property, Plant and Equipment

	December 31,
	2011		2010
Competitive Electric:
Generation and mining	$	23,006	$	22,686
Nuclear fuel (net of accumulated amortization of $776 and $610)	320		353
Other assets	41		30
Corporate and Other	212		186
Total	23,579		23,255
Less accumulated depreciation	4,803		3,545
Net of accumulated depreciation	18,776		19,710
Construction work in progress:
Competitive Electric	642		646
Corporate and Other	9		10
Total construction work in progress	651		656
Property, plant and equipment — net	$	19,427	$	20,366

Depreciation expense totaled $1.345 billion, $1.255 billion and $1.454 billion for the years ended December 31, 2011, 2010 and 2009, respectively, including $394 million for the year ended December 31, 2009 related to Oncor.

We began depreciating two newly constructed lignite-fueled generation units in the fourth quarter 2009 and the third new unit in the second quarter 2010.

Assets related to capitalized leases included above totaled $69 million and $82 million as of December 31, 2011 and 2010, respectively, net of accumulated depreciation.

186

Asset Retirement Obligations

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor's rates.

The following table summarizes the changes to the asset retirement liability, reported in other current liabilities and other noncurrent liabilities and deferred credits in the balance sheet, during the years ended December 31, 2011 and 2010:

	Nuclear Plant Decommissioning			Mining Land Reclamation and Other			Total
Liability as of January 1, 2010	$	794		$	154		$	948
Additions:
Accretion	32			25			57
Incremental reclamation costs	—			33			33
Reductions:
Payments	—			(48		)	(48		)
Adjustment for new cost estimate (a)	(497		)	—			(497		)
Liability as of December 31, 2010	329			164			493
Additions:
Accretion	19			29			48
Incremental reclamation costs	—			67			67
Reductions:
Payments	—			(72		)	(72		)
Liability as of December 31, 2011	348			188			536
Less amounts due currently	—			(31		)	(31		)
Noncurrent liability as of December 31, 2011	$	348		$	157		$	505

___________

(a) The adjustment resulted from a new cost estimate completed in 2010. In accordance with regulatory requirements, a new cost estimate is completed every five years. A decline in the liability was driven by lower cost escalation assumptions in the new estimate. The reduction in the liability was offset in part by a reduction in the carrying value of the nuclear facility with the balance offset by an increase in the noncurrent liability to Oncor, which in turn resulted in a regulatory liability on Oncor's balance sheet. (Also see Note 20.)

187

Other Noncurrent Liabilities and Deferred Credits

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

	December 31,
	2011		2010
Uncertain tax positions (including accrued interest) (Note 6)	$	1,972	$	1,806
Retirement plan and other employee benefits (a)	1,664		1,895
Asset retirement and mining reclamation obligations	505		452
Unfavorable purchase and sales contracts	647		673
Other	28		41
Total other noncurrent liabilities and deferred credits	$	4,816	$	4,867

____________

(a) Includes $1.235 billion and $1.463 billion at December 31, 2011 and 2010, respectively, representing pension and OPEB liabilities related to Oncor (see Note 20).

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 as of 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 as of 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 $26 million, $27 million and $27 million in 2011, 2010 and 2009, respectively. Favorable purchase and sales contracts are recorded as intangible assets (see Note 5).

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

Year	Amount
2012	$	27
2013	$	26
2014	$	25
2015	$	25
2016	$	25

Outsourcing Exit Liabilities

In connection with the closing of the Merger, EFH Corp., TCEH and Oncor commenced a review, under the change of control provision, of certain outsourcing arrangements with Capgemini, Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). In 2008, we entered separation agreements with CgE that, among other things, terminated the outsourcing arrangements under which Capgemini had provided outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities. The effects of the termination of the outsourcing arrangements, including an accrued liability of $54 million for incremental costs to exit and transition the services, were included in the final purchase price allocation for the Merger. The following table summarizes the changes to the exit liability:

	Competitive Electric segment			Regulated Delivery segment			Total
Liability for exit activities as of January 1, 2009	$	38		$	16		$	54
Payments recorded against liability	(24		)	(4		)	(28		)
Other adjustments to the liability (a)	(11		)	(10		)	(21		)
Liability for exit activities as of December 31, 2009	$	3		$	2		$	5
Payments recorded against liability	(1		)	(2		)	(3		)
Other adjustments to the liability (a)	(2		)	—			(2		)
Liability for exit activities as of December 31, 2010	$	—		$	—		$	—

___________

(a) Represents reversal of exit liabilities due primarily to a shorter than expected outsourcing services transition period.

188

Supplemental Cash Flow Information

	Year Ended December 31,
	2011			2010			2009
Cash payments (receipts) related to:
Interest paid (a)	$	2,958		$	2,693		$	2,972
Capitalized interest	(31		)	(60		)	(277		)
Interest paid (net of capitalized interest) (a)	2,927			2,633			2,695
Income taxes	37			64			(42		)
Noncash investing and financing activities:
Construction expenditures (b)	67			84			197
Debt exchange transactions (Note 10)	34			1,641			101
Principal amount of toggle notes issued in lieu of cash (Note 10)	206			399			511
Capital leases	1			9			15
Gain on termination of long-term power sales contract (Note 8)	—			(116		)	—

____________

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

(b) Represents end-of-period accruals.

Regulated Versus Unregulated Operations

See discussion in Note 3 regarding deconsolidation of our regulated operations effective January 1, 2010.

	Year Ended December 31, 2009
Operating revenues
Regulated	$	2,690
Unregulated	7,931
Intercompany sales eliminations — regulated	(1,051		)
Intercompany sales eliminations — unregulated	(24		)
Total operating revenues	9,546
Fuel, purchased power and delivery fees — unregulated (a)	(2,878		)
Net gain from commodity hedging and trading activities — unregulated	1,736
Operating costs — regulated	(908		)
Operating costs — unregulated	(690		)
Depreciation and amortization — regulated	(557		)
Depreciation and amortization — unregulated	(1,197		)
Selling, general and administrative expenses — regulated	(194		)
Selling, general and administrative expenses — unregulated	(874		)
Franchise and revenue-based taxes — regulated	(250		)
Franchise and revenue-based taxes — unregulated	(109		)
Impairment of goodwill — unregulated	(90		)
Other income	204
Other deductions	(97		)
Interest income	45
Interest expense and other charges	(2,912		)
Income before income taxes and equity in earnings of unconsolidated subsidiaries	$	775

___________

(a) Includes unregulated cost of fuel consumed of $1.269 billion. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

189

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

None.

Item 9A. CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect as of December 31, 2011. 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.

ENERGY FUTURE HOLDINGS CORP.

MANAGEMENT'S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Energy Future Holdings Corp. 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 Holdings Corp.’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 Holdings Corp. performed an evaluation as of December 31, 2011 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, 2011 Energy Future Holdings Corp.'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 Holdings Corp. has issued an attestation report on Energy Future Holdings Corp.'s internal control over financial reporting.

/s/ JOHN F. YOUNG	/s/ PAUL M. KEGLEVIC
John F. Young, President and	Paul M. Keglevic, Executive Vice President
Chief Executive Officer	and Chief Financial Officer

February 20, 2012

190

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Holdings Corp.

Dallas, Texas

We have audited the internal control over financial reporting of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. EFH Corp.'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 EFH Corp.'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, EFH Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, 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 and financial statement schedule as of and for the year ended December 31, 2011 of EFH Corp. and our report dated February 20, 2012 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

Dallas, Texas

February 20, 2012

191

Item 9B. OTHER INFORMATION

Compensatory Arrangements of Certain Officers

On February 20 2012, in recognition of David A. Campbell's, President and Chief Executive Officer of Luminant, and M.A. McFarland's, Executive Vice President of EFH Corp. and Executive Vice President and Chief Commercial Officer of Luminant, performance in connection with EFH Corp. and its subsidiaries' strategic and operational responses to federal environmental regulations and activities last summer and fall, the O&C Committee approved a discretionary cash bonus in the amount of $500,000 and $150,000, respectively, which bonuses are expected to be paid in March 2012.

192

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors

The names of EFH Corp.'s directors and information about them, as furnished by the directors themselves, are set forth below:

Name	Age	Served As Director Since	Business Experience
Arcilia C. Acosta (1)(4)	46	2008	Arcilia C. Acosta has served as a Director of EFH Corp. since May 2008. Ms. Acosta is the founder, President and CEO of CARCON Industries & Construction, L.L.C. (CARCON) and its subsidiaries. She is also the founder, President and CEO of Southwestern Testing Laboratories, L.L.C. (STL). CARCON's principal business is commercial, institutional and transportation, design and build construction. STL's principal business is geotechnical engineering, construction materials testing and environmental consulting services. Ms. Acosta is a former Chair of the State of Texas Hispanic chambers organization known as the Texas Association of Mexican American Chambers of Commerce (TAMACC) and the Greater Dallas Hispanic Chamber of Commerce. Ms. Acosta serves on the Board of Directors of the Dallas Citizens Council, U.T. Southwestern Board of Visitors, The Texas Tech Alumni Association National Board of Directors and The Dallas Education Foundation.
David Bonderman	69	2007	David Bonderman has served as a Director of EFH Corp. since October 2007. He is a founding partner of TPG Capital, L.P. (TPG). Mr. Bonderman serves on the boards of the following companies: Armstrong World Industries, Inc., Caesars Entertainment Corporation (formerly Harrah's Entertainment), CoStar Group, Inc., General Motors Company, JSC VTB Bank, and Ryanair Holdings plc, for which he serves as Chairman of the Board. During the past five years, Mr. Bonderman also served on the boards of Burger King Corporation, Burger King Holdings, Inc., Gemalto N.V., IASIS Healthcare Corporation, Univision Communications, Inc. and Washington Mutual, Inc.
Donald L. Evans (2)(3)(4)	65	2007	Donald L. Evans has served as a Director and Non-Executive Chairman of EFH Corp. since October 2007. He is also a Senior Partner at Quintana Energy Partners, L.P. He was CEO of the Financial Services Forum from 2005 to 2007, after serving as the 34th secretary of the U.S. Department of Commerce. Before serving as Secretary of Commerce, Mr. Evans was the former CEO of Tom Brown, Inc., a large independent energy company. He also previously served as a member and chairman of the Board of Regents of the University of Texas System.
Thomas D. Ferguson (3)	58	2008	Thomas D. Ferguson has served as a Director of EFH Corp. since December 2008. He is a Managing Director of Goldman, Sachs & Co., having joined the firm in 2002. Mr. Ferguson heads the asset management efforts for the merchant bank's U.S. real estate and infrastructure investment activity. He currently serves on the board of American Golf, for which he serves as the company's non-executive Chairman, Agriculture Company of America, EFIH and Oncor. He formerly held board seats at Associated British Ports, the largest port company in the UK, Carrix, one of the largest private container terminal operators in the world, as well as Red de Carreteras, a toll road concessionaire in Mexico.
Frederick M. Goltz (2)(3)	40	2007	Frederick M. Goltz has served as a Director of EFH Corp. since October 2007. He has been with Kohlberg Kravis Roberts and Co. L.P. (including KKR Asset Management LLC, “KKR") for 16 years. Mr. Goltz has played a significant role in the development of many of the themes pursued by KKR in the energy space, including those related to integrated utilities, merchant generation, and oil and gas exploration and production. He now heads KKR's Mezzanine Fund headquartered in San Francisco. He is a director of EFCH and TCEH. During the past five years, Mr. Goltz also served on the boards of Accuride Corp. and Texas Genco Holdings, Inc.

193

Name	Age	Served As Director Since	Business Experience
James R. Huffines (1)(3)	60	2007	James R. Huffines has served as a Director of EFH Corp. since October 2007. He is President and Chief Operating Officer of PlainsCapital Corporation, a $5.8 billion bank and financial service firm. He previously served as Chairman, Central and South Texas Region, of PlainsCapital Bank and Senior Executive Vice President of Plains Capital Corporation from March 2001 to November 2010, Chairman of the University of Texas System Board of Regents from April 2009 to July 2010, Vice Chairman from November 2007 to April 2009 and Chairman from June 2004 to November 2007. Mr. Huffines is a director of Andrew Harper Travel Publications, Inc., EFIH, PlainsCapital Bank, PlainsCapital Corporation and TCEH.
Scott Lebovitz	36	2007	Scott Lebovitz has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area since 2007 having joined Goldman, Sachs & Co. in 1997. Mr. Lebovitz serves on the boards of both public and private companies, including Cobalt International Energy, Inc., EFCH and TCEH. During the past five years, Mr. Lebovitz also served on the board of CVR Energy, Inc.
Jeffrey Liaw	35	2007	Jeffrey Liaw has served as a Director of EFH Corp. since October 2007. He is a principal of TPG and is active in TPG's energy and industrial investing practice areas. Before joining TPG in 2005, he worked for Bain Capital in its industrials practice. Mr. Liaw serves on the boards of both public and private companies, including American Tire Distributors, Inc., EFIH, Graphic Packaging Holding Company and Oncor.
Marc S. Lipschultz (4)	43	2007	Marc S. Lipschultz has served as a Director of EFH Corp. since October 2007. He joined KKR in 1995 and is the global head of KKR's Energy and Infrastructure business. Mr. Lipschultz serves on KKR's Infrastructure Investment Committee and its Oil & Gas Investment Committee. Currently, he is on the board of Accel-KKR Company. During the past five years, Mr. Lipschultz also served on the boards of Texas Genco Holdings, Inc. and The Boyds Collection, Ltd.
Michael MacDougall (2)(3)	41	2007	Michael MacDougall has served as a Director of EFH Corp. since October 2007. He is a partner of TPG. Mr. MacDougall leads the firm's global energy and natural resources investing efforts. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall is a director of both public and private companies, including Copano Energy, L.L.C., Graphic Packaging Holding Company, Harvester Holdings, LLC and its two subsidiaries, Petro Harvester Oil and Gas, LLC and 2CO Energy Limited, Maverick American Natural Gas, LLC, Nexeo Solutions Holdings, LLC, Northern Tier Energy, LLC, EFCH, and TCEH and is a director of the general partner of Valerus Compression Services, L.P. During the past five years, he also served on the boards of Aleris International, Kraton Performance Polymers Inc. and Texas Genco LLC prior to its sale to NRG Energy, Inc. in February 2006. Mr. MacDougall also serves as the Chairman of the Board of The Opportunity Network and is a member of the Board of the Dwight School Foundation and Islesboro Affordable Property.
Lyndon L. Olson, Jr. (3)	64	2007	Lyndon L. Olson, Jr. has served as a Director of EFH Corp. since October 2007. He is Chairman of Hill+Knowlton Strategies in New York City. Olson was a Senior Advisor with Citigroup Inc. from 2002 to 2008, after serving as United States Ambassador to Sweden from 1998 to 2001. He previously was affiliated with Citigroup from 1990 to 1998, as President and CEO of Travelers Insurance Holdings and the Associated Madison Companies, predecessor companies. Before joining Citigroup, he had been President of the National Group Corporation and CEO of its National Group Insurance Company. Ambassador Olson also is a former Chairman and a member of the Texas 173 State Board of Insurance, former President of the National Association of Insurance Commissioners, and a former member of the Texas House of Representatives. Ambassador Olson also serves on the board of First Acceptance Corporation, Sammons Enterprises and Texas Meter and Device Company.

194

Name	Age	Served As Director Since	Business Experience
Kenneth Pontarelli (2)(4)	41	2007	Kenneth Pontarelli has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He transferred to the Principal Investment Area in 1999 and was promoted to Managing Director in 2004. Mr. Pontarelli serves as a director of both public and private companies, including CCS Corporation, Cobalt International Energy, L.P., EFIH, Expro International Group Ltd. and Kinder Morgan, Inc. During the past five years, he also served on the board of CVR Energy, Inc.
William K. Reilly	72	2007	William K. Reilly has served as a Director of EFH Corp. since October 2007. He is a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water and renewable energy sectors, having previously served as the seventh Administrator of the EPA. Mr. Reilly is a director of the following public companies: E.I DuPont de Nemours and Company, ConocoPhillips and Royal Caribbean International. During the past five years, he also served on the board of Eden Springs, Ltd. of Israel. Before serving as EPA Administrator, Mr. Reilly was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President's Council on Environmental Quality, Associate Director of the Urban Policy Center and the National Urban Coalition and Co-Chairman of the National Commission on Energy Policy. Mr. Reilly was appointed by the President to serve as Co-Chair of the National Commission on the Deepwater Horizon Oil Spill and Offshore Drilling.
Jonathan D. Smidt	39	2007	Jonathan D. Smidt has served as a Director of EFH Corp. since October 2007. He has been with KKR since 2000, where he is a partner and senior member of the firm's Energy and Infrastructure team and leads KKR Natural Resources, the firm's platform to acquire and operate oil and natural gas assets. Currently, he is a director of Laureate Education Inc.
John F. Young (2)(3)	55	2008	John F. Young has served as a Director and President and Chief Executive of EFH Corp. since January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008 including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon Corporation, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. Mr. Young is also a director of EFCH, EFIH, TCEH, Luminant and USAA.
Kneeland Youngblood (1)	56	2007	Kneeland Youngblood has served as a Director of EFH Corp. since October 2007. He is a founding partner of Pharos Capital Group, a private equity firm that focuses on providing growth and expansion capital to businesses in technology, business services and health care services. Mr. Youngblood is a director of the following public companies: Starwood Hotels and Resorts Worldwide, Inc. and Gap Inc. During the last five years, he served on the board of Burger King Holdings, Inc. Mr. Youngblood is a member of the Council on Foreign Relations.

_______________

(1) Member of Audit Committee.

(2) Member of Executive Committee.

(3) Member of Governance and Public Affairs Committee

(4) Member of Organization and Compensation Committee

There is no family relationship between any of the above-named directors.

195

Director Qualifications

In October 2007, David Bonderman, Donald L. Evans, Frederick M. Goltz, James R. Huffines, Scott Lebovitz, Jeffrey Liaw, Marc S. Lipschultz, Michael MacDougall, Lyndon L. Olson, Jr., Kenneth Pontarelli, William K. Reilly, Jonathan D. Smidt, and Kneeland Youngblood were elected to EFH Corp.'s board of directors (the Board). Arcilia C. Acosta, Thomas D. Ferguson and John F. Young joined the Board in 2008. Messrs. Bonderman, Ferguson, Goltz, Lebovitz, Liaw, Lipschultz, MacDougall, Pontarelli, and Smidt are collectively referred to as the "Sponsor Directors." Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly, Young, and Youngblood are collectively referred to as the "Non-Sponsor Directors."

Each of the Sponsor Directors was elected to the Board pursuant to the Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership, the holder of a majority of the outstanding capital stock of EFH Corp. Pursuant to this agreement, Messrs. Goltz, Lipschultz and Smidt were appointed to the Board as a consequence of their relationships with Kohlberg Kravis Roberts & Co.; Messrs. Bonderman, Liaw and MacDougall were appointed to the Board as a consequence of their relationships with TPG Capital, L.P., and Messrs. Ferguson, Lebovitz and Pontarelli were appointed to the Board as a consequence of their relationships with GS Capital Partners.

When considering whether the Board's directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of EFH Corp.'s business and structure, the Board focused primarily on the qualifications summarized in each of the Board member's or nominee's biographical information set forth on the pages above. In addition, EFH Corp. believes that each of its directors possesses high ethical standards, acts with integrity, and exercises careful judgment. Each is committed to employing his/her skills and abilities in the long-term interests of EFH Corp and its stakeholders. Finally, our directors are knowledgeable and experienced in business, governmental, and civic endeavors, further qualifying them for service as members of the Board.

The Sponsor Directors possess experience in owning and managing privately held enterprises and are familiar with corporate finance and strategic business planning activities of highly-leveraged companies such as EFH Corp. Some of the Sponsor Directors also have experience advising and overseeing the operations of large industrial, manufacturing or retail companies similar to our businesses. Finally, several of the Sponsor Directors possess substantial expertise in advising and managing companies in segments of energy industry, including, among others, power generation, oil and gas, and energy infrastructure and transportation.

As a group and individually, the Non-Sponsor Directors possess extensive experience in governmental and civic endeavors and in the business community, in each case, in the markets where our businesses operate.

Mr. Young's employment agreement provides that he will serve as a member of the Board during the time he is employed by EFH Corp. Before joining EFH Corp. as President and Chief Executive Officer, he held various senior management positions at other companies in the energy industry over twenty years, including, most recently, his role as Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation.

Ms. Acosta manages the operations of a large commercial construction company in Texas and has significant experience within the local Hispanic business community, having served as the chair of the Greater Dallas Hispanic Chamber of Commerce and the Texas Association of Mexican American Chambers of Commerce. Mr. Evans has demonstrated ability and achievement in both the private and public sectors, serving as U.S. Secretary of Commerce during the Bush Administration, and both before and after his government service, acting as Chairman and Chief Executive Officer of a publicly-owned energy company, Tom Brown, Inc. Mr. Huffines has demonstrated achievement in both business and academic endeavors, and, given his employment in various senior management positions in the banking industry, has sufficient experience and expertise in financial matters to qualify him to serve as EFH Corp.'s "audit committee financial expert." Mr. Olson possesses substantial experience in both federal and state government through, among other things, his service as the former US Ambassador to Sweden and as a former member of the Texas House of Representatives, and has advised and overseen the operations of large companies, in particular his service in the insurance industry as Chairman and CEO of Travelers Insurance Holdings. Mr. Reilly possesses a distinguished record of public service and extensive policy-making experience as a former administrator of the EPA, lectures extensively on environmental issues facing companies operating in the energy industry and has served as Co-Chairman of the National Commission on Energy Policy. Mr. Youngblood has served on numerous boards for large public companies, has extensive experience managing and advising companies in his capacity as a partner in a private equity firm (not affiliated with the Sponsor Group), is highly knowledgeable of federal and state political matters, and has served on the board of directors of the United States Enrichment Corporation, a company that contracts with the US Department of Energy to produce enriched uranium for use in nuclear power plants.

196

Executive Officers

The names and information regarding EFH Corp.'s executive officers are set forth below:

Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
John F. Young	55	President and Chief Executive Officer of EFH Corp.	January 2008	John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008, including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation.
James A. Burke	43	President and Chief Executive of TXU Energy	August 2005	James A. Burke was elected President and Chief Executive of TXU Energy in August 2005. Previously, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy.
David A. Campbell	43	President and Chief Executive of Luminant	June 2008	David A. Campbell was elected President and Chief Executive of Luminant in June 2008. Mr. Campbell was Executive Vice President and Chief Financial Officer of EFH Corp. from April 2007 to June 2008 having previously served as Acting Chief Financial Officer beginning in March 2006 and as Executive Vice President for Corporate Planning, Strategy & Risk when he joined EFH Corp. in May 2004.
Paul M. Keglevic	58	Executive Vice President and Chief Financial Officer of EFH Corp.	July 2008	Paul M. Keglevic was elected Executive Vice President and Chief Financial Officer of EFH Corp. in July 2008. Before joining EFH Corp., he was an audit partner at PricewaterhouseCoopers. Mr. Keglevic was PricewaterhouseCoopers' Utility Sector Leader from 2002 to 2008 and Clients and Sector Assurance Leader from 2007 to 2008.
Richard J. Landy (1)	66	Executive Vice President of EFH Corp.	February 2010	Richard J. Landy was elected Executive Vice President of EFH Corp. in February 2010 and oversees human resources. Prior to joining EFH Corp., Mr. Landy was owner and consultant of Richard J. Landy, LLC from 2007 to 2009 and Senior Vice President of Exelon Corporation from 2002 to 2007.
M. A. McFarland	42	Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp.	July 2008	M. A. McFarland was elected Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp. in July 2008. Before joining Luminant, Mr. McFarland served as Senior Vice President of Mergers, Acquisitions and Divestitures and as a Vice President in the wholesale marketing and trading division power team at Exelon Corporation.
John D. O'Brien	51	Senior Vice President of EFH Corp.	October 2011	John D. O'Brien was elected Senior Vice President of EFH Corp. in October 2011. Before joining EFH, he served as Senior Vice President of Government and Regulatory Affairs at NRG Energy from 2007 to 2011 and Vice President of Environmental and Regulatory Affairs at Exelon Power, a subsidiary of Exelon Corporation, from 2004 to 2007.

_______________

(1) Mr. Landy has announced his plan to retire from EFH Corp. at the end of the first quarter of 2012. Carrie L. Kirby, Vice President of Human Resources of TXU Energy, has been elected Senior Vice President of EFH Corp. effective April 1, 2012 to fill the vacancy created by Mr. Landy's departure.

197

There is no family relationship between any of the above-named executive officers.

Audit Committee Financial Expert

The Board has determined that James R. Huffines is an "Audit Committee Financial Expert" as defined in Item 407(d)(5) of SEC Regulation S-K and Mr. Huffines is independent under the New York Stock Exchange's audit committee independence requirements for issuers of debt securities.

Code of Conduct

EFH Corp. maintains certain corporate governance documents on EFH Corp's website at www.energyfutureholdings.com. EFH Corp.'s Code of Conduct can be accessed by selecting "Investor Relations" on the EFH Corp. website. EFH Corp.'s Code of Conduct applies to all of its employees, officers (including the Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer) and directors. Any amendments to the Code of Conduct will be posted on EFH Corp.'s website. Printed copies of the corporate governance documents that are posted on EFH Corp.'s website are also available to any investor upon request to the Secretary of EFH Corp. at 1601 Bryan Street, Dallas, Texas 75201-3411

Procedures for Shareholders to Nominate Directors; Arrangement to Serve as Directors

The Amended and Restated Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC, the general partner of Texas Holdings, generally requires that the members of Texas Energy Future Capital Holdings LLC take all necessary action to ensure that the persons who serve as its managers also serve on the EFH Corp. Board. In addition, Mr. John Young's employment agreement provides that he will be elected as a member of the Board during the time he is employed by EFH Corp.

Because of these requirements, together with Texas Holdings' controlling ownership of EFH Corp.'s outstanding common stock, there is no policy or procedure with respect to shareholder recommendations for nominees to the EFH Corp. Board.

198

Item 11. EXECUTIVE COMPENSATION

Organization and Compensation Committee

The Organization and Compensation Committee (the "O&C Committee") of EFH Corp.'s Board of Directors (the "Board") is comprised of four non-employee directors: Arcilia C. Acosta, Donald L. Evans, Marc S. Lipschultz and Kenneth Pontarelli. The primary responsibility of the O&C Committee is to:

• determine and oversee the compensation program of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities), including making recommendations to the Board with respect to the adoption, amendment or termination of compensation and benefits plans, arrangements, policies and practices;

• evaluate the performance of EFH Corp.'s Chief Executive Officer (the "CEO") and the other executive officers of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) (collectively, the "executive officers"), including all of the executive officers named in the Summary Compensation Table (the "Named Executive Officers"), and

• approve executive compensation based on those evaluations.

Executive Summary

Significant Executive Compensation Actions

EFH Corp.'s executive compensation programs are designed to implement our pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk. As a result, our compensation programs balance long-term and short-term objectives and consist of salary, bonus, and equity components. In 2011, following a review of our current capitalization, our businesses' performance in the previous year, external market forces, and an independent consultant's evaluation of our compensation practices, the O&C Committee approved the granting of additional long-term cash incentive awards to our Named Executive Officers and the modification of the long-term equity incentive awards for our Named Executive Officers, with the goal of increasing the performance and retentive value of our executive compensation plans. These adjustments are described more fully herein.

Significant Business Activities in 2011

Liability Management Program

In 2009, we initiated a liability management program to improve our balance sheet by reducing the amount and extending the maturity of our outstanding debt. As part of the program, in April 2011, we amended the TCEH Senior Secured Facilities, resulting 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 the extension of $1.4 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016. Additionally, during 2011 we engaged in debt exchanges, issuances, and repurchase activities as part of the program, as more fully described in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Significant Activities and Events" and Note 10 to Financial Statements in this Form 10-K. Since inception, the program has resulted in the capture of approximately $2 billion of debt discount and the extension of approximately $23.5 billion of debt maturities to 2017-2021.

Extreme Weather

Weather in ERCOT during 2011 was extremely volatile and included record setting heat during the summer and atypical winter weather in February. Although we did experience outages during the February storm, many of our units withstood the harsh weather, particularly Comanche Peak, which operated at 100% reliability. The extreme weather resulted in record electricity consumption during both the winter and summer. During 2011, our coal and gas generation units achieved top decile safety and reliability performance, and we mined the highest amount of lignite in our history.

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Regulatory Environment

2011 was a year of significant environmental regulatory change. During 2011, EFH Corp. was focused on these changes, while balancing Texas' energy requirements. In July 2011, the EPA issued the CSAPR, the final replacement rule for CAIR. The CSAPR diverged from its predecessor by including Texas in its annual SO₂ and NO_x emissions reductions programs, as well as the seasonal NO_x reduction program. In August 2011, we petitioned the EPA to reconsider and stay the effectiveness of the CSAPR, as applied to Texas, and in September 2011, we filed a petition for review in the D.C. Circuit Court challenging the CSAPR and a motion to stay the effective date of the CSAPR, as applied to Texas. In December 2011, the D.C. Circuit Court granted all motions for a judicial stay of the CSAPR, including as applied to Texas. The D.C. Circuit Court's order stays the implementation of the CSAPR's emissions reductions programs until a final ruling regarding its validity is issued. Additionally, in December 2011, the EPA issued MATS. MATS regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases and will require additional control equipment retrofits on our lignite/coal-fueled generation units. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations " and Note 4 to Financial Statements in this Form 10-K for a detailed discussion of CSAPR and MATS.

Compensation Risk Assessment

Our management team initiates EFH Corp.'s internal risk review and assessment process for our compensation policies and practices by assessing, among other things, (1) the mix of cash and equity payouts at various compensation levels; (2) the performance time horizons used by our plans; (3) the use of financial performance metrics that are readily monitored and reviewed; (4) the equity investment that most of our senior and middle management employees have in EFH Corp. common stock; (5) the lack of an active trading market and other impediments to liquidity associated with EFH Corp. common stock; (6) the incorporation of both operational and financial goals and individual performance modifiers; (7) the inclusion of maximum caps and other plan-based mitigants on the amount of certain of our awards; and (8) multiple levels of review and approval of awards (including approval of our O&C Committee with respect to awards to executive officers and awards to other employees that exceed monetary thresholds). Following their assessment, our management team prepares a report, which is provided to EFH Corp.'s Audit Committee for review. After review and adjustment, if any, as determined by EFH Corp.'s Audit Committee, the Audit Committee provides the report to the O&C Committee. EFH Corp.'s management (along with the Audit Committee) has determined that the risks arising from EFH Corp.'s compensation policies and practices are not reasonably likely to have a material adverse effect on EFH Corp.

Compensation Discussion and Analysis

Compensation Philosophy

We have a pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk. In other words, a significant portion of an executive officer's compensation is comprised of variable, at-risk incentive compensation. Our compensation program is intended to compensate executive officers appropriately for their contribution to the attainment of our financial, operational and strategic objectives. In addition, we believe it is important to retain our executive officers and strongly align their interests with EFH Corp.'s stakeholders by emphasizing long-term incentive compensation, including equity-based compensation.

To achieve the goals of our compensation philosophy, we believe that:

• compensation plans should balance both long-term and short-term objectives;

• the overall compensation program should emphasize variable compensation elements that have a direct link to overall corporate performance and stakeholder value, and

• an executive officer's individual compensation level should be based upon an evaluation of the financial and operational performance of that executive officer's business unit or area of responsibility as well as the executive officer's individual performance.

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We believe our compensation philosophy supports our businesses by:

• aligning performance measures with our business objectives to drive the financial and operational performance of EFH Corp. and its business units;

• rewarding business unit and individual performance by providing compensation levels consistent with the level of contribution and degree of accountability;

• attracting and retaining the best performers; and

• strengthening the correlation between the long-term interests of our executive officers and stakeholders.

Elements of Compensation

The material elements of our executive compensation program are:

• a base salary;

• the opportunity to earn an annual performance-based cash bonus based on the achievement of specific corporate, business unit and individual performance goals; and

• long-term incentive awards, primarily in the form of long-term cash incentive awards and restricted stock units ("Restricted Stock Units") under and subject to the terms of the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and Affiliates (the "2007 Stock Incentive Plan").

In addition, executive officers generally have the opportunity to participate in certain of our broad-based employee benefit plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans, and to receive certain perquisites.

Compensation of the CEO

In determining the compensation of the CEO, the O&C Committee annually follows a thorough and detailed process. At the end of each year, the O&C Committee reviews a self-assessment prepared by the CEO regarding his performance and the performance of our businesses and meets (with and without the CEO) to evaluate and discuss his performance and the performance of our businesses.

While the O&C Committee tries to ensure that the bulk of the CEO's compensation is directly linked to his performance and the performance of our businesses, the O&C Committee also seeks to set his compensation in a manner that is competitive for retention purposes.

Compensation of Other Executive Officers

In determining the compensation of each of our executive officers (other than the CEO), the O&C Committee seeks the input of the CEO. At the end of each year, the CEO reviews a self-assessment prepared by each executive officer and assesses the executive officer's performance against business unit (or area of responsibility) and individual goals and objectives. The O&C Committee and the CEO then review the CEO's assessments and, in that context, the O&C Committee approves the compensation for each executive officer.

Assessment of Compensation Elements

We design the majority of our executive officers' compensation to be linked directly to corporate and business unit (or area of responsibility) performance. For example, each executive officer's annual performance-based cash bonus is primarily based on the achievement of certain corporate and business unit financial and operational targets (such as management EBITDA, cost management, generation output, customer satisfaction, etc.). In addition, each executive officer's long-term cash incentive award is based on achievement of certain operational and financial performance metrics. We also try to ensure that our executive compensation program is competitive with our peer companies in order to reduce the risk of losing our executive officers.

The following is a detailed discussion of the principal compensation elements provided to our executive officers and the amendments made thereto in 2011. Additional detail about each of the elements can be found in the compensation tables, including the footnotes and the narrative discussion following certain of the tables.

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Executive Compensation Evaluation and Adjustment

In late 2010, the O&C Committee engaged Pay Governance LLC ("Pay Governance"), an independent compensation consultant, to assist in its evaluation of our executive compensation practices. Pay Governance evaluated the compensation of our Named Executive Officers against a variety of market reference points and competitive data, including the compensation practices of a number of companies that we consider to comprise our peer group, size-adjusted energy services industry survey data and size-adjusted general industry survey data. In early 2011, Pay Governance delivered to the O&C Committee its report, which included market data for a peer group composed of the following companies:

Allegheny Energy, Inc.	Ameren Corp.	American Electric Power Co. Inc
Calpine Corp.	Constellation Energy Group Inc.	Dominion Resources Inc.
Duke Energy Corp.	Edison International	Entergy Corp.
Exelon Corp.	FirstEnergy Corp.	GenOn Energy, Inc.(1)
NextEra Energy, Inc.	NRG Energy, Inc.	PPL Corp.
Progress Energy Inc.	Public Service Enterprise Group Inc.	Southern Co.
Xcel Energy Inc.

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(1) GenOn Energy, Inc. is the surviving entity resulting from a merger between RRI Energy and Mirant. The Pay Governance report preceded the merger and referenced RRI Energy.

After a comprehensive review of the performance of our businesses in 2010, and taking into consideration the sustained decline in ERCOT wholesale power prices (primarily as a result of lower forward natural gas prices), the increased environmental regulatory requirements of the electric generation industry, our position as a highly-leveraged, privately-owned company, and the Pay Governance report, the O&C Committee approved modifications to the long-term incentive compensation for our Named Executive Officers described below in February 2011. The O&C Committee implemented these changes to provide incentives for retention and performance and to maintain a strong alignment between our Named Executive Officers and our stakeholders. We believe these changes are consistent with our compensation philosophy.

Amendment to Long-Term Cash Incentive Awards

In October 2009 (and in February 2010, with respect to Mr. Young), we granted each of our Named Executive Officers a long-term cash incentive award (the "Initial LTI Award") that entitles each Named Executive Officer to receive on September 30, 2012, if such Named Executive Officer remains employed by EFH Corp. on such date (with exceptions in limited circumstances for pro-ration), a one-time, lump-sum cash payment equal to 75% (100% with respect to Mr. Young) of the aggregate Executive Annual Incentive Plan award received by such Named Executive Officer for fiscal years 2009, 2010 and 2011.

In February 2011, the O&C Committee approved the following additional long-term cash incentive awards for the Named Executive Officers:

• an amount for each Named Executive Officer (the "2011 LTI Award") of between $650,000 and $1,300,000 ($750,000 and $1,500,000 with respect to Mr. Young). The amount of the 2011 LTI Award is based on the amount of management EBITDA (as described herein) actually achieved by EFH Corp. as compared to the management EBITDA threshold and target amounts previously set by the O&C Committee for the year ended December 31, 2011. We will pay one-half of the 2011 LTI Award on each of September 30, 2012 and September 30, 2013, respectively, if such Named Executive Officer remains employed by EFH Corp. on such date (with exceptions in limited circumstances); and

• an amount for each Named Executive Officer of between $500,000 and $1,000,000 ($1,350,000 and $2,700,000 with respect to Mr. Young), for each of 2012, 2013, and 2014 (collectively, the "2015 LTI Award"), with the amount of the award for each year to be determined based on the amount of management EBITDA (as described herein) actually achieved by EFH Corp. as compared to the management EBITDA threshold and target amounts set by the O&C Committee, in each case, for the years ended December 31, 2012, 2013, and 2014. We will pay the entire 2015 LTI Award on March 13, 2015, if such Named Executive Officer remains employed by EFH Corp. on such date (with exceptions in limited circumstances).

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We believe these long-term cash incentive awards provide significant retentive value because each of the awards is not paid to a Named Executive Officer unless the Named Executive Officer remains employed with us for a period of time - until September 30, 2012 in connection with the Initial LTI Award, September 30, 2012 and September 30, 2013 in connection with the 2011 LTI Award, and March 13, 2015 in connection with the 2015 LTI Award (in each case with customary exceptions in limited circumstances). In addition, these long-term cash incentive awards provide additional incentive to our Named Executive Officers to achieve top operational and financial performance because the awards are based on either a percentage of the executive officers' annual performance-based cash bonuses or the achievement of management EBITDA targets.

Amendment to Long-Term Equity Awards

In February 2011, the O&C Committee also approved amendments to our executive officers' long-term equity awards. The O&C Committee approved an exchange program, pursuant to which each of our executive officers, including the Named Executive Officers, were entitled to receive a one-time lump sum grant of Restricted Stock Units (the "Exchange RSUs") granted pursuant to our 2007 Stock Incentive Plan that cliff-vest on September 30, 2014, with exceptions in limited circumstances in exchange for forfeiting all rights in respect of any and all options to purchase shares of EFH Corp.'s common stock that had been previously granted to the executive officers under the 2007 Stock Incentive Plan. Each of our Named Executive Officers participated in the exchange, as described below in “Initial Grant of Restricted Stock Units.”

In addition, the O&C Committee approved annual grants of Restricted Stock Units ("Annual RSUs") to each of our Named Executive Officers in each of 2011, 2012 and 2013. Each year, the Annual RSU award consists of 500,000 Restricted Stock Units (666,667 with respect to Mr. Campbell and 1,500,000 with respect to Mr. Young) that will cliff vest on September 30, 2014 (with exceptions in limited circumstances). In February 2011, we approved the grant of the 2011 Annual RSUs for our Named Executive Officers.

We believe these long-term equity incentive awards also provide significant retentive and performance value because the Restricted Stock Units do not vest until 2014 and their value is directly correlated with the performance of the Company.

Amended and Restated Employment Agreements

In 2011, we entered into amended and restated employment agreements, effective July 2011, with each of our executive officers, including our Named Executive Officers. As a general matter, these agreements incorporated the terms of the long-term cash incentive awards and long-term equity incentive awards described above.

Base Salary

Base salary should reward executive officers for the scope and complexity of their position and the level of responsibility required. We believe that a competitive level of base salary is required to attract and retain qualified talent.

The O&C Committee annually reviews base salaries and periodically uses independent compensation consultants to ensure the base salaries are market-competitive. The O&C Committee may also review an executive officer's base salary from time to time during a year, including if the executive officer is given a promotion or if his responsibilities are significantly modified.

We want to ensure our cash compensation is competitive and sufficient to incent executive officers to remain with us, recognizing our high performance expectations across a broad set of operational, financial, customer service and community-oriented goals and objectives and the higher risk levels associated with being a significantly-leveraged company. In connection with their assessment of the compensation of our Named Executive Officers, the O&C Committee determined the base salaries for all Named Executive Officers should remain the same in 2011 as in 2010.

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Annual Performance-Based Cash Bonus - Executive Annual Incentive Plan

The Executive Annual Incentive Plan ("EAIP") provides an annual performance-based cash bonus for the successful attainment of certain annual financial and operational performance targets that are established annually at each of the corporate and business unit levels by the O&C Committee. Under the terms of the EAIP, performance against these targets, which are generally set at levels to incent high performance (while at the same time balancing the needs for safety and investment in our business), drives bonus funding. As a general matter, target level performance is based on EFH Corp.'s board-approved financial and operational plan (the "Financial Plan") for the upcoming year. The O&C Committee's expectation when setting target level performance is that the business will achieve the target level of performance during the upcoming year. Threshold and superior levels are for performance levels that are below or above expectations. Based on the level of attainment of these performance targets, an aggregate EAIP funding percentage amount for all participants is determined.

Our financial performance targets typically include "management" EBITDA, a non-GAAP financial measure. When the O&C Committee reviews management EBITDA for purposes of determining our performance against the applicable management EBITDA target, it includes our earnings before interest, taxes, depreciation and amortization plus transaction, management and/or similar fees paid to the Sponsor Group, together with such adjustments as the O&C Committee shall determine appropriate in its discretion after good faith consultation with our CEO and Chief Financial Officer, including adjustments consistent with those included in the comparable definitions in TCEH's Senior Secured Facilities (to the extent considered appropriate for executive compensation purposes). Our management EBITDA targets are also adjusted for acquisitions, divestitures or major capital investment initiatives to the extent that they were not contemplated in our Financial Plan. The management EBITDA targets are intended to measure achievement of the Financial Plan and the adjustments to management EBITDA described above primarily represent elements of our performance that are either beyond the control of management or were not predictable at the time the Financial Plan was approved. Given our Named Executive Officer's business unit responsibilities, our management EBITDA calculations for Mssrs. Young and Keglevic include Oncor, while management EBITDA calculations for the remaining Named Executive Officers exclude Oncor. Under the terms of the EAIP, the O&C Committee has broad authority to make these or any other adjustments to EBITDA that it deems appropriate in connection with its evaluation and compensation of our executive officers. Management EBITDA is an internal measure used only for performance management purposes, and EFH Corp. does not intend for management EBITDA to be an alternative to any measure of financial performance presented in accordance with GAAP. Management EBITDA is not the same as Adjusted EBITDA, which is disclosed elsewhere in this Form 10-K and defined in the glossary to this Form 10-K.

Financial and Operational Performance Targets

The following table provides a summary of the weight given to the various business unit scorecards, which constitute the performance targets, for each of the Named Executive Officers.

	Weight
Name	EFH Corp. Management EBITDA(2)		EFH Business Services Scorecard Multiplier		Luminant Scorecard Multiplier		TXU Energy Scorecard Multiplier		Luminant Energy Scorecard Multiplier		Total		Payout
John F. Young(1)	50	%	50	%							100	%	120	%
Paul M. Keglevic(1)	50	%	50	%							100	%	120	%
David A. Campbell	25	%			75	%					100	%	120	%
James A. Burke	25	%					75	%			100	%	116	%
M.A. McFarland	25	%	25	%	25	%			25	%	100	%	132	%

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(1) Mr. Young and Mr. Keglevic are measured on EFH Corp. Management EBITDA (including Oncor) while the remaining Named Executive Officers are measured on EFH Corp. Management EBITDA (excluding Oncor).

(2) The targeted EFH Corp. Management EBITDA (including Oncor) for the fiscal year ended December 31, 2011 was $4.9 billion. The targeted EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2011 was $3.285 billion. The actual EFH Corp. Management EBITDA (including Oncor) for the fiscal year ended December 31, 2011 was $4.978 billion, which was above target. The actual EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2011 was $3.297 billion, which was above target.

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The following table provides a summary of the performance targets included in the EFH Business Services Scorecard Multiplier.

EFH Business Services Scorecard Multiplier	Weight		Performance(1)	Payout
EFH Corp. Management EBITDA (excluding Oncor)(2)	20	%	105%	21%
Luminant Scorecard Multiplier(3)	20	%	125%	25%
TXU Energy Scorecard Multiplier(3)	20	%	120%	24%
EFH Corp. (excluding Oncor) Total Spend	20	%	125%	25%
EFH Business Services Costs	20	%	150%	30%
Total	100	%		125%

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(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

(2) The targeted EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2011 was $3.285 billion. The actual EFH Corp. Management EBITDA (excluding Oncor) for the fiscal year ended December 31, 2011 was $3.297 billion, which was above target.

(3) The performance targets included in the Luminant Scorecard Multiplier and the TXU Energy Scorecard Multiplier are summarized below.

The following table provides a summary of the performance targets included in the Luminant Scorecard Multiplier.

Luminant Scorecard Multiplier	Weight		Performance(1)	Payout
Luminant Management EBITDA(2)	35	%	157%	55%
Luminant Available Generation - Coal	20	%	105%	21%
Luminant Available Generation – Nuclear	10	%	70%	7%
Luminant O&M/SG&A	15	%	100%	15%
Luminant Capital Expenditures	10	%	120%	12%
Luminant Fossil Fuel Costs	10	%	150%	15%
Total	100	%		125%

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(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

(2) The target Luminant Management EBITDA for the fiscal year ended December 31, 2011 was $2.395 billion. The actual Luminant Management EBITDA for the fiscal year ended December 31, 2011 was $2.53 billion, which was above target.

The following table provides a summary of the performance targets included in the TXU Energy Scorecard Multiplier.

TXU Energy Scorecard Multiplier	Weight		Performance(1)	Payout
TXU Energy Management EBITDA(2)	40	%	92%	37%
Contribution Margin	15	%	107%	16%
TXU Energy Total Costs	20	%	185%	37%
Residential Customer Count	10	%	30%	3%
Residential Days Meter to Cash	5	%	200%	10%
PUCT Complaints	5	%	200%	10%
Customer Satisfaction	5	%	140%	7%
Total	100	%		120%

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(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

(2) The target TXU Energy Management EBITDA for the fiscal year ended December 31, 2011 was $915 million. The actual TXU Energy Management EBITDA for the fiscal year ended December 31, 2011 was $893 million, which was below target.

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The following table provides a summary of the performance targets included in the Luminant Energy Scorecard Multiplier.

Luminant Energy Scorecard Multiplier	Weight		Performance(1)	Payout
Luminant Management EBITDA(2)	45	%	157%	70%
Luminant Energy SG&A	15	%	200%	30%
Incremental Value Created	30	%	200%	60%
Liquidity Utilization	10	%	128%	13%
Total	100	%		173%

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(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

(2) The target Luminant Management EBITDA for the fiscal year ended December 31, 2011 was $2.395 billion. The actual Luminant Management EBITDA for the fiscal year ended December 31, 2011 was $2.530 billion, which was above target.

Individual Performance Modifier

After approving the actual performance against the applicable targets under the EAIP, the O&C Committee and/or the CEO reviews the performance of each of our executive officers on an individual and comparative basis. Based on this review, which includes an analysis of both objective and subjective criteria, as determined by the O&C Committee in its sole discretion, including the CEO’s recommendations (with respect to all executive officers other than himself), the O&C Committee approves an individual modifier for each executive officer. Under the terms of the EAIP, the individual performance modifier can range from an outstanding rating (150%) to an unacceptable rating (0%). To calculate an executive officer’s final performance-based cash bonus, the executive officer’s corporate/business unit payout percentages are multiplied by the executive officer’s target incentive level, which is computed as a percentage of annualized base salary, and then by the executive officer’s individual performance modifier.

Actual Award

The following table provides a summary of the 2011 performance-based cash bonus for each Named Executive Officer under the EAIP.

Name	Target (% of salary)	Target Award ($ Value)		Actual Award
John F. Young (1)	100%	$	1,200,000	$	1,728,000
Paul M. Keglevic (2)	85%	$	552,500	$	795,600
David A. Campbell (3)	85%	$	595,000	$	892,500
James A. Burke (4)	85%	$	535,500	$	745,416
M.A. McFarland (5)	85%	$	510,000	$	807,840

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(1) Mr. Young's incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier. In 2011, Mr. Young successfully led EFH Corp. and its subsidiaries through the challenges brought by extreme summer heat, a winter weather event, creditor allegations, new environmental regulations, and the continued decline of wholesale power prices. In spite of these challenges, under Mr. Young's leadership, EFH Corp. surpassed its management EBITDA target, exercised financial discipline without sacrificing operational or safety standards, and continued to improve its balance sheet through the liability management program. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. Young's incentive award.

(2) Mr. Keglevic's incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier. .In 2011, Mr. Keglevic continued our liability management initiatives by amending our TCEH Senior Secured Facilities, which resulted in the extention of $16.4 billion in loan maturities and $1.4 billion in commitments, and implemented a company-wide effort to streamline processes, increase efficiency, and generate cost savings. Given these significant accomplishments and other achievements (including his continued focus on liquidity management), the O&C Committee approved an individual performance modifier that increased Mr. Keglevic's incentive award.

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(3) Mr. Campbell's incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for Luminant and an individual performance modifier. In 2011, Mr. Campbell coordinated our efforts to address the operational, regulatory, legal, and public affairs response to the CSAPR and was able to develop optimal operating scenarios, garner support from elected officials, communicate directly with the EPA to advocate increased emissions standards for Texas, and challenge the enforcement of the rule as applied to Texas. Additionally, under Mr. Campbell's direction, Luminant delivered record mining production while maintaining strong safety records. Given these significant accomplishments and other achievements (including his ability to obtain top performance from our fleet during challenges brought about by weather and regulatory uncertainty), the O&C Committee approved an individual performance modifier that increased Mr. Campbell's incentive award.

(4) Mr. Burke's incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for TXU Energy and an individual performance modifier. In 2011, Mr. Burke continued to focus on customer attraction and satisfaction in a competitive retail market through the development of new product offerings and customer support. Even though TXU Energy narrowly missed its management EBITDA target, TXU Energy delivered strong results in customer satisfaction, PUC complaints, and total costs. Given these significant accomplishments and other achievements (including his continued commitment to foster TXU Energy's brand and reputation with its customers and stakeholders), the O&C Committee approved an individual performance modifier that increased Mr. Burke's incentive award.

(5) Mr. McFarland's incentive award is based on the successful achievement of the financial performance targets for EFH Corp., the financial and operational performance targets for Luminant and Luminant Energy and an individual performance modifier. In 2011, Mr. McFarland delivered strong financial results in the face of declining wholesale power prices through generation, while managing the transition to a Nodal market and the ERCOT power supply. Given these significant accomplishments and other achievements (including his strategic contributions to our supply book), the O&C Committee approved an individual performance modifier that increased Mr. McFarland's incentive award.

Long-Term Incentive Awards

Long-Term Cash Incentive

The table below sets forth the Initial LTI Award and 2011 LTI Award earned by each Named Executive Officer and the amounts to be paid on September 30, 2012 and September 30, 2013, respectively, if such Named Executive Officer remains employed by EFH Corp. on such date (with exceptions in limited circumstances):

Name	Initial LTI Award Earned	2011 LTI Award Earned	Amount To Be Distributed 9/30/2012(1)	Amount To Be Distributed 9/30/2013(1)
John F. Young	$5,240,600	$1,500,000	$5,990,600	$750,000
Paul M. Keglevic	$1,795,144	$1,300,000	$2,445,144	$650,000
David A. Campbell	$1,887,638	$1,300,000	$2,537,638	$650,000
James A. Burke	$1,901,293	$1,300,000	$2,551,293	$650,000
M.A. McFarland	$1,832,765	$1,300,000	$2,482,765	$650,000

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(1) The amount to be distributed is subject, in limited circumstances, to pro-ration in the event of the Named Executive Officer's termination without "cause" or resignation for "good reason" (including following a change of control of EFH Corp.), or in the event of such Named Executive Officer's death or disability, as described in greater detail in the Named Executive Officer's employment agreement.

In addition, the Company has awarded each of the Named Executive Officers the 2015 LTI Award, which provides each Named Executive Officer the opportunity to earn between $500,000 and $1,000,000 ($1,350,000 and $2,700,000 with respect to Mr. Young) in each of 2012, 2013, and 2014. Payment of the 2015 LTI Award will be deferred until March 2015 and is conditioned upon the Named Executive Officer's continued employment with EFH Corp. on such date (with exceptions in limited circumstances). Please refer to the Grants of Plan-Based Awards-2011 table, including the footnotes thereto, for additional description of the 2015 LTI Award granted to each of the Named Executive Officers.

In connection with the grant of the 2011 LTI Award and 2015 LTI Award, and in consideration of the retention incentive that the 2011 LTI Award and the 2015 LTI Award provide to our Named Executive Officers, the O&C Committee approved the provision of irrevocable standby letters of credit under the terms of the TCEH Senior Secured Credit Facilities to each Named Executive Officer in the amount of $4,300,000 ($9,600,000 with respect to Mr. Young). These letters of credit support EFH Corp.'s payment obligations under the 2011 LTI Award and 2015 LTI Award.

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Long-Term Equity Incentives

We believe it is important to strongly align the interests of our executive officers and stakeholders through equity-based compensation. In December 2007, our Board approved and adopted our 2007 Stock Incentive Plan. The purpose of the 2007 Stock Incentive Plan is to:

• promote our long-term financial interests and growth by attracting and retaining management and other personnel with the training, experience and ability to make a substantial contribution to our success;

• motivate management and other personnel by means of growth-related incentives to achieve long-range goals; and

• strengthen the correlation between the long-term interests of our stakeholders and the interests of our executive officers through opportunities for stock (or stock-based) ownership in EFH Corp.

Because we are a privately held company, our 2007 Stock Incentive Plan does not contain provisions, and we do not have any equity grant practices in place designed to coordinate the granting of equity awards with the release of material non-public information. Please refer to the outstanding Equity Awards at Fiscal Year-End-2011 table, including the footnotes thereto, for a more detailed description of the outstanding Restricted Stock Units held by each of the Named Executive Officers.

Initial Grant of Restricted Stock Units

In November 2011, each of the Named Executive Officers participated in the exchange program described above and opted to surrender all of his respective existing stock options in exchange for the Restricted Stock Units as set forth below:

Executive Officer	Surrendered Options	Exchange RSUs(1)
John F. Young	9,000,000	4,500,000
Paul M. Keglevic	3,000,000	1,500,000
David A. Campbell	4,800,000	2,400,000
James A. Burke	2,650,000	1,325,000
M.A. McFarland	2,400,000	1,200,000

____________

(1) These Restricted Stock Units are subject to the terms, conditions and restrictions contained in the 2007 Stock Incentive Plan and the Named Executive Officer's Restricted Stock Unit Agreement, including, but not limited to, a provision that if there is a change in control (as that term is defined in the 2007 Stock Incentive Plan) of EFH Corp. prior to September 30, 2014, all such Restricted Stock Units will immediately vest and all forfeiture restrictions related thereto will lapse. If the Named Executive Officer is terminated without "cause," resigns for "good reason," or is terminated due to death or disability, a portion of the Restricted Stock Units, calculated by multiplying the number of Exchange RSUs for such Named Executive Officer by a fraction, the numerator of which is the number of days from February 15, 2011 to such Named Executive Officer's date of termination and the denominator of which is the number of days from February 15, 2011 to September 30, 2014, will vest and all forfeiture restrictions related thereto will lapse.

Annual Grant of Restricted Stock Units:

The O&C Committee approved the Annual RSU grant for 2011 on February 15, 2011, which resulted in each Named Executive Officer receiving 500,000 Restricted Stock Units (666,667 with respect to Mr. Campbell and 1,500,000 with respect to Mr. Young) in September 2011. The award of Annual RSUs for 2012 and 2013 are expected to be made following, and in connection with, such year's February meeting of the O&C Committee. In the future, we may make additional discretionary grants of equity-based compensation to reward high performance or achievement. Please refer to the Grants of Plan-Based Awards - 2011 table, including the footnotes thereto, and the Outstanding Equity Awards at Fiscal Year-End-2011 table, including the footnotes thereto, for a more detailed description of the outstanding Annual RSUs held by each of the Named Executive Officers.

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Other Elements of Compensation

General

Our executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans. Please refer to the footnotes to the Summary Compensation table for a more detailed description of our Thrift Plan, and the narrative that follows the Pension Benefits table for a more detailed description of our Retirement Plan and Supplemental Retirement Plan. Beginning in 2010, our Named Executive Officers were no longer eligible to participate in the Salary Deferral Program.

Perquisites

We provide our executives with certain perquisites on a limited basis. Those perquisites that exist are generally intended to enhance our executive officers’ ability to conduct company business. These benefits include, financial planning, preventive health maintenance, and reimbursement for certain club memberships and certain spousal travel expenses. Expenditures for the perquisites described below are disclosed by individual in footnotes to the Summary Compensation Table. The following is a summary of perquisites offered to our Named Executive Officers that are not available to all employees:

Executive Financial Planning: We pay for our executive officers to receive financial planning services. This service is intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executive officers. Furthermore, we believe that such service helps ensure greater accuracy and compliance with individual tax regulations by our executive officers.

Health Services: We pay for our executive officers to receive annual physical health exams. Also, in 2011, we purchased an annual membership for Messrs. Young and Keglevic to participate in a comprehensive health plan that provides anytime personal and private physician access and health care. The health of our executive officers is important given the vital leadership role they play in directing and operating the company. Our executive officers are important assets of EFH Corp., and these benefits are designed to help ensure their health and long-term ability to serve our stakeholders.

Club Memberships: We reimburse certain of our executives for the cost of golf and social club memberships, provided that the club membership provides for a business-use opportunity, such as client networking and entertainment. The club membership reimbursements are provided to assist the executives in cultivating business relationships.

Spouse Travel Expenses: From time to time, we pay for an executive officer’s spouse to travel with the executive officer when taking a business trip.

Payments Contingent Upon a Change of Control of EFH Corp.

We have entered into employment agreements with each of our Named Executive Officers, which were amended effective July 2011 to reflect the changes implemented by the O&C Committee in February 2011. Each of the employment agreements provides that certain payments and benefits will be paid upon the expiration or termination of the agreement under various circumstances, including termination without cause, resignation for good reason and termination of employment within a fixed period of time following a change in control of EFH Corp. We believe these provisions are important in order to attract and retain the caliber of executive officers that our business requires and provide incentive for our executive officers to fully consider potential changes that are in our and our stakeholders' best interest, even if such changes would result in the executive officers’ termination of employment. For a description of the applicable provisions in the employment agreements of our Named Executive Officers see "Potential Payments upon Termination or Change in Control."

Other

Under the terms of Mr. Young's employment agreement, we have purchased a 10-year term life insurance policy on his life (to be paid to a beneficiary of his choice) in an insured amount equal to $10,000,000. As discussed more fully in the Pension Benefits Table, Mr. Young is not eligible to participate in the Supplemental Retirement Plan, nor is he eligible to receive monthly contribution credits under the cash balance component of our Retirement Plan. Therefore, under the terms of Mr. Young's employment agreement we have agreed to provide a supplemental retirement plan, with a value of $3,000,000 if Mr. Young remains employed by EFH Corp. through December 31, 2014 (with customary exceptions for death, disability and leaving for "good reason" or termination "without cause"). Each of these benefits was included as a part of Mr. Young's compensation package to account for Mr. Young's inability to participate in the EFH Corp. Retirement Plan and Supplemental Retirement Plan (unlike many of his peers who are eligible to participate in the retirement plans of our peer companies).

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Accounting and Tax Considerations

Accounting Considerations

Because our common stock is not registered or publicly traded, the O&C Committee does not generally consider the effect of accounting principles when making executive compensation decisions.

Income Tax Considerations

Section 162(m) of the Code limits the tax deductibility by a publicly held company of compensation in excess of $1 million paid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer. Because EFH Corp. is a privately-held company, Section 162(m) will not limit the tax deductibility of any executive compensation for 2011, and we do not take it into account when making executive compensation decisions.

The O&C Committee administers our compensation programs with the good faith intention of complying with Section 409A of the Code.

Organization and Compensation Committee Report

The O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Form 10-K. Based on this review and discussions, the committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.

Organization and Compensation Committee

Donald L. Evans, Chair

Arcilia C. Acosta

Marc S. Lipschultz

Kenneth Pontarelli

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Summary Compensation Table—2011

The following table provides information for the fiscal years ended December 31, 2011, 2010 and 2009 regarding the aggregate compensation paid to our Named Executive Officers.

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)(6)	Option Awards ($)(7)	Non-Equity Incentive Plan Compensation ($)(8)	Change in Pension  Value and Non-qualified Deferred Compensation Earnings ($)(9)	All  Other Compen-sation ($)(10)(11)	Total ($)
John F. Young(1)President & CEO of EFH Corp.	2011 2010 2009	1,200,000 1,200,000 1,000,000	— — —	5,347,500 — —	— 3,405,000 —	8,468,600 2,043,600 1,469,000	3,123 2,761 —	105,484 210,826 105,291	15,124,707 6,862,187 2,574,291
Paul M. Keglevic(2)EVP & Chief Financial Officer of EFH Corp.	2011 2010 2009	650,000 650,000 600,000	1,050,000 50,000 150,000	1,782,500 — —	— — 1,325,000	3,890,744 933,725 664,200	3,788 3,185 —	73,437 39,416 73,320	7,450,469 1,676,326 2,812,520
David A. Campbell(3)President & CEO of Luminant	2011 2010 2009	700,000 700,000 600,000	— — —	2,728,000 — —	— — 2,120,000	4,080,138 981,750 642,600	118,810 76,485 68,861	40,223 17,911 15,020	7,667,171 1,776,146 3,446,481
James A. Burke(4)President & CEO of TXU Energy	2011 2010 2009	630,000 630,000 600,000	— — —	1,637,250 — —	— — 933,100	3,946,709 932,841 856,800	89,310 76,713 55,931	55,298 17,305 23,885	6,358,567 1,656,859 2,469,716
M.A. McFarland (5)EVP-EFH Corp. & EVP & Chief Commercial Officer of Luminant	2011 2010 2009	600,000 600,000 500,000	350,000 — —	1,519,000 — —	— — 1,060,000	3,940,605 948,090 687,750	— — —	63,602 17,418 7,424	6,473,207 1,565,508 2,255,174

___________

(1) The amounts for 2011 reported as "All Other Compensation" for Mr. Young represent (i) the costs of providing certain perquisites, including $11,250 for an annual membership in a comprehensive personal physician care program, $10,520 for financial planning, $17,185 for insurance premiums in respect of a 10-year term life insurance policy, $25,625 for the cost of his country club membership, and $149 of taxable reimbursements for spouse's meals for business entertainment, (ii) $14,700 for our matching contributions to the EFH Thrift Plan, (iii) $2,267 for the cost of a letter of credit provided to Mr. Young, and (iv) $23,788 for attorney's fees (see footnote 11 to this Summary Compensation Table for additional information relating to such attorney's fees).

(2) Mr. Keglevic's employment agreement provides that we pay him a signing bonus equal to $550,000 as follows: (i) $250,000 payable in July 2008; (ii) $150,000 payable in July 2009 and (iii) $50,000 payable in July 2010, 2011 and 2012. The amount for 2011 reported as "Bonus" for Mr. Keglevic represents the 2011 portion of his signing bonus and a $1,000,000 special award he was granted in connection with his contribution to our liability management program, one half of which was paid in May 2011 and one half of which will be paid in September 2012. The amounts for 2011 reported as "All Other Compensation" for Mr. Keglevic represent (i) the costs of providing certain perquisites, including $13,500 for an annual membership in a comprehensive personal physician care program, $21,661 for the cost of his country club membership, including a pro-rated portion of his initiation fee, and $1,494 of taxable reimbursements for family travel, (ii) $11,979 for our matching contributions to the EFH Thrift Plan, (iii) $1,015 for the cost of a letter of credit provided to Mr. Keglevic, and (iv) $23,788 for attorney's fees (see footnote 11 to this Summary Compensation Table for additional information relating to such attorney's fees).

(3) The amount reported as "All Other Compensation" in 2011 for Mr. Campbell represents (i) the costs of providing certain perquisites, including $10,520 for financial planning, (ii) $4,900 for our matching contributions to the EFH Thrift Plan, (iii) $1,015 for the cost of a letter of credit provided to Mr. Campbell, and (iv) $23,788 for attorney's fees (see footnote 11 to this Summary Compensation Table for additional information relating to such attorney's fees).

(4) The amounts for 2011 reported as “All Other Compensation” for Mr. Burke represent (i) the costs of providing certain perquisites, including $9,230 for financial planning and $820 of taxable reimbursements for spousal travel, (ii) $20,445 for our matching contributions to the EFH Thrift Plan, and (iii) $1,015 for the cost of a letter of credit provided to Mr. Burke, and (iv) $23,788 for attorney's fees (see footnote 11 to this Summary Compensation Table for additional information relating to such attorney's fees).

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(5) The amount for 2011 reported as “Bonus” for Mr. McFarland represents a $350,000 special award in recognition of his significant achievement in connection with our liability management program. The amounts for 2011 reported as “All Other Compensation” for Mr. McFarland represent (i) the costs of providing certain perquisites, including $2,553 for an executive physical and $21,546 for the cost of his country club membership, including a pro-rated portion of his initiation fee, (ii) $14,700 for our matching contributions to the EFH Thrift Plan, (iii) $1,015 for the cost of a letter of credit provided to Mr. McFarland, and (iv) $23,788 for attorney's fees (see footnote 11 to this Summary Compensation Table for additional information relating to such attorney's fees).

(6) The amounts reported as "Stock Awards" represent the grant date fair value of the 2011 Annual RSUs and the incremental expense associated with the grant date fair value for the Exchange RSUs granted in 2011. These awards cliff vest in September of 2014. The expense for these awards will be recognized in accordance with FASB ASC Topic 718.

(7) The amounts reported as “Option Awards” represent the grant date fair value of Stock Option Awards granted in the fiscal year computed for the stock options awarded under the 2007 Stock Incentive Plan in accordance with FASB ASC Topic 718 and do not take into account estimated forfeitures. As described more fully in the "Long Term Equity Incentives" section herein, each of the Named Executive Officers surrendered all of his existing stock options in exchange for the Exchange RSUs, and therefore, none of our Named Executive Officers currently holds any stock options in EFH Corp. The incremental expense associated with the Exchange RSUs is recognized in accordance with FASB ASC Topic 718 and is included in the amounts reported as “Stock Awards”.

(8) The amounts in 2011 reported as “Non-Equity Incentive Plan Compensation” were earned by the executive officers in 2011 under the EAIP, the Initial LTI Award, and the 2011 LTI Award.  The EAIP is expected to be paid in March 2012, the Initial LTI Award is expected to be paid in September 2012, and the first half of the 2011 LTI Award is expected to be paid inSeptember 2012 and the second half of the 2011 LTI Award is expected to be paid in September 2013.  The amounts for each Named Executive Officer are as follows:  (a) for Mr. Young, $1,728,000 for the EAIP, $5,240,600 for the Initial LTI Award, and $1,500,000 for the 2011 LTI Award; (b) for Mr. Keglevic $795,600 for the EAIP, $1,795,144 for the Initial LTI Award, and $1,300,000 for the 2011 LTI Award; (c) for Mr. Campbell,$892,500 for the EAIP, $1,887,638 for the Initial LTI Award, and $1,300,000 for the 2011 LTI Award; (d) for Mr. Burke $745,416 for the EAIP, $1,901,293 for the Initial LTI Award, and $1,300,000 for the 2011 LTI Award; (e) for Mr. McFarland $807,840 for the EAIP, $1,832,765 for the Initial LTI Award, and $1,300,000 for the 2011 LTI Award.  The deferred amounts of the Initial LTI Award and 2011 LTI Award are reported in the table entitled “Nonqualified Deferred Compensation - 2011” under the headings “Registrant Contributions in Last FY” and “Aggregate Balance at Last FYE.”

(9) The amounts in 2011 reported under “Change in Pension Value and Nonqualified Deferred Compensation Earnings” include the aggregate increase in actuarial value of EFH Corp.'s Retirement Plan and Supplemental Retirement Plan. For a more detailed description of EFH Corp.'s retirement plans, including the transfers of certain assets and liabilities from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan, please refer to the narrative that follows the table entitled "Pension Benefits - 2011". There are no above market earnings for nonqualified deferred compensation that is deferred under the Salary Deferral Program.

(10) For purposes of preparing this column, all perquisites are valued on the basis of the actual cost to EFH Corp. As described above, "All Other Compensation" includes amounts associated with our matching contributions to the EFH Thrift Plan. Our Thrift Plan allows participating employees to contribute a portion of their regular salary or wages to the plan. Under the EFH Thrift Plan, EFH Corp. matches a portion of an employee's contributions. This matching contribution is 100% of each Named Executive Officer's contribution up to 6% of the named Executive Officer's salary up to the IRS annual compensation limit. All matching contributions are invested in Thrift Plan investments as directed by the participant.

(11) EFH Corp. paid for the advice of counsel provided to our executive officers, including the Named Executive Officers, in connection with the amended and restated employment agreements entered into in 2011 with each of our executive officers, including our Named Executive Officers. Because our executive officers were represented by the same counsel and most of the amendments applied to all of our named executive officers in a similar manner, we do not have the ability to determine the exact expenses to allocate to each individual executive officer. Therefore, we divided the amount of the attorney's fees pro-rata among each of our executive officers, including our Named Executive Officers. The amount listed for each of the Named Executive Officers as “attorneys fees” under “All Other Compensation” represents that Named Executive Officer's pro-rata amount of the total attorney's fees paid by EFH Corp. in connection with the amended and restated employment agreements.

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Grants of Plan-Based Awards – 2011

The following table sets forth information regarding grants of compensatory awards to our Named Executive Officers during the fiscal year ended December 31, 2011.

			Estimated Possible Payouts Under Non-Equity Incentive Plan Awards			All Other Stock Awards: # of Securities Underlying Options (#)	Grant Date Fair  Value of Stock and Option Awards(6)
Name	Grant Date	Date  of Board Action	Threshold ($)	Target ($)	Max. ($)
John F. Young	2/15/2011(1)2/15/2011(2)2/15/2011(3)9/28/2011 11/4/2011	2/15/2011 2/15/2011	600,000 750,000 4,050,000	1,200,000	2,400,000 1,500,000 8,100,000	1,500,000(4)4,500,000(5)	1,395,000 3,952,500
Paul M. Keglevic	2/15/2011(1)2/15/2011(2)2/15/2011(3)9/28/2011 11/4/2011	2/15/2011 2/15/2011	276,250 650,000 1,500,000	552,500	1,105,000 1,300,000 3,000,000	500,000(4)1,500,000(5)	465,000 1,317,500
David A. Campbell	2/15/2011(1)2/15/2011(2)2/15/2011(3)9/28/2011 11/4/2011	2/15/2011 2/15/2011	297,500 650,000 1,500,000	595,000	1,190,000 1,300,000 3,000,000	666,667(4)2,400,000(5)	620,000 2,108,000
James A. Burke	2/15/2011(1)2/15/2011(2)2/15/2011(3)9/28/2011 11/4/2011	2/15/2011 2/15/2011	267,500 650,000 1,500,000	535,500	1,071,000 1,300,000 3,000,000	500,000(4)1,325,000(5)	465,000 1,172,250
M.A. McFarland	2/15/2011(1)2/15/2011(2)2/15/2011(3)9/28/2011 11/4/2011	2/15/2011 2/15/2011	255,000 650,000 1,500,000	510,000	1,020,000 1,300,000 3,000,000	500,000(4)1,200,000(5)	465,000 1,054,000

___________

(1) Represents the threshold, target and maximum amounts available under the EAIP for each executive officer. The actual awards for the 2011 plan year are expected to be paid in March 2012 and are reported in the Summary Compensation Table under the heading “Non-Equity Incentive Plan Compensation” and described above under the section entitled “Annual Performance Bonus - EAIP”.

(2) Represents the threshold and maximum amounts available under the grant of the 2011 LTI Award for each Named Executive Officer, as described above under the sections entitled “Amendment to Long-Term Cash Incentive Awards” and “Long-Term Cash Incentives.” The actual awards will be paid one half in September 2012 and one half in September 2013, and will be subject to the condition that the Named Executive Officer continues to be employed by EFH Corp. on such date, subject, in limited circumstances, to pro-ration in the event of the Named Executive Officer's termination without “cause” or resignation for “good reason,” or in the event of such Named Executive Officer's death or disability, each as described in greater detail in the Named Executive Officer's employment agreement.

(3) Represents the threshold and maximum amounts available under the grant of the 2015 LTI Award, as described above under sections entitled “Amendment to Long-Term Cash Incentive Awards” and “Long-Term Cash Incentives.” The 2015 LTI Award will be paid in March 2015, and will be subject to the condition that the Named Executive Officer continues to be employed by EFH Corp. on such date, subject, in limited circumstances, to pro-ration in the event of the Named Executive Officer's termination without “cause” or resignation for “good reason,” or in the event of such Named Executive Officer's death or disability, each as described in greater detail in the Named Executive Officer's employment agreement.

(4) Represents grants of Annual RSUs, which cliff vest September 30, 2014, as described above under sections entitled “Amendment to Long-Term Equity Awards” and “Long-Term Equity Incentives.” The vesting of the Annual RSUs is contingent upon the Named Executive Officer's continued employment with EFH Corp. on September 30, 2014, subject, in limited circumstances, to pro-ration in the event of the Named Executive Officer's termination without “cause” or resignation for “good reason,” or in the event of such Named Executive Officer's death or disability, each as described in greater detail in the Named Executive Officer's employment agreement, and complete vesting in the event of a change in control (as that term is defined in the 2007 Stock Incentive Plan) of EFH Corp., such that all ungranted Annual RSUs that would have been granted to the Named Executive Officer in each of 2012 and 2013 will be immediately granted and vested.

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(5) Represents grants of Exchange RSUs, which cliff vest September 30, 2014, in connection with the exchange of stock options for Restricted Stock Units, as described above under the sections entitled “Amendment to Long-Term Equity Awards” and “Long-Term Equity Incentives.” The vesting of the Exchange RSUs is contingent upon the Named Executive Officer's continued employment with EFH Corp. on September 30, 2014, subject, in limited circumstances, to pro-ration in the event of the Named Executive Officer's termination without “cause” or resignation for “good reason,” or in the event of such Named Executive Officer's death or disability, each as described in greater detail in the Named Executive Officer's restricted stock unit agreement, and complete vesting in the event of a change in control (as that term is defined in the 2007 Stock Incentive Plan) of EFH Corp., such that all unvested Exchange RSUs will immediately vest.

(6) The amounts reported under “Grant Date Fair Value of Stock and Option Awards” represent the grant date fair value of restricted stock units related to the grant of Annual RSUs and the incremental [fairvalue] related to the Exchange RSUs in accordance with FASB ASC Topic 718.

For a discussion of certain material terms of the employment agreements with the Named Executive Officers, please see "Assessment of Compensation Elements” and “Potential Payments upon Termination or Change in Control."

Outstanding Equity Awards at Fiscal Year-End– 2011

Name	#  of Shares or  Units of Stock That Have Not Vested	Market Value  of Shares or Units  of Stock That Have Not Vested (3)
John F. Young	4,500,000(1)	$2,250,000
	1,500,000(2)	$750,000
Paul M. Keglevic	1,500,000(1)	$750,000
	500,000(2)	$250,000
David A. Campbell	2,400,000(1)	$1,200,000
	666,667(2)	$333,334
James A. Burke	1,325,000(1)	$662,500
	500,000(2)	$250,000
M.A. McFarland	1,200,000(1)	$600,000
	500,000(2)	$250,000

___________

(1) In February 2011, the O&C Committee approved an exchange program pursuant to which our executive officers, including the Named Executive Officers, had the opportunity to exchange any and all of their outstanding stock option awards for Restricted Stock Units that cliff-vest on September 30, 2014. In November 2011, each of the Named Executive Officers exchanged all of their outstanding stock option awards for such Restricted Stock Units as described above in the sections entitled “Amendment to Long-Term Equity Awards” and “Long-Term Equity Incentives.”

(2) The Annual RSUs granted to each of the Named Executive Officers in 2011 are scheduled to cliff vest on September 30, 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through that date (with exceptions in limited circumstances) as described above in the sections entitled “Amendment to Long-Term Equity Awards” and “Long-Term Equity Incentives.”

(3) There is no established public market for our common stock. Our board of directors values our common stock on an annual basis (in December of each year). The valuation is primarily done to set the exercise or base price of awards granted under the 2007 Stock Incentive Plan. In determining the valuation of our common stock, our Board, with the assistance of third party valuation experts, utilizes several valuation techniques, including discounted cash flow and comparable company analysis. The amount reported above under the heading “Market Value of Shares or Units of Stock That Have Not Vested” reflects the fair market value (as determined by our Board) of our common stock as of December 31, 2011.

Options Exercised and Stock Vested – 2011

The table sets forth information regarding the vesting of equity awards held by the Named Executive Officers during 2011:

	Stock Awards
Name	Number of Shares Acquired  on Vesting	Value Realized on Vesting ($)
Paul M. Keglevic (1)	112,500	$140,625

___________

(1) Pursuant to his amended deferred share agreement, Mr. Keglevic vested in 112,500 shares of EFH Corp. common stock in July 2011. The shares are eligible to be distributed to Mr. Keglevic upon his termination of employment for any reason (or six months and one day following his termination in the event EFH Corp. common stock is publicly traded on an established securities market at such time), unless he becomes entitled to the “Deferred Amount” described below. See the section entitled “Potential Payments Upon Termination or Change of Control” for a discussion of this arrangement.

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Pension Benefits – 2011

The table set forth below illustrates present value on December 31, 2011 of each Named Executive Officer’s Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on their years of service and remuneration through December 31, 2011:

Name	Plan Name	Number of  Years Credited  Service (#)(1)	PV of  Accumulated Benefit ($)
John F. Young	Retirement Plan Supplemental Retirement Plan	—   —	39,197 —
Paul M. Keglevic	Retirement Plan Supplemental Retirement Plan	—   —	51,382 —
David A. Campbell	Retirement Plan Supplemental Retirement Plan	6.5833 9.5000	159,935 180,110
James A. Burke	Retirement Plan Supplemental Retirement Plan	6.1667 6.1667	146,790 148,026
M.A. McFarland	Retirement Plan Supplemental Retirement Plan	—   —	—   —

___________

(1) Because they were hired after October 1, 2007, Messrs. Young, Keglevic and McFarland are generally not eligible to participate in our Retirement Plan. However, Messrs. Young and Keglevic participate in the cash balance component of the Retirement Plan solely with respect to amounts that were transferred from the Salary Deferral Program in 2009

EFH Corp. and its participating subsidiaries maintain the Retirement Plan, which is intended to be qualified under applicable provisions of the Code and covered by ERISA. The Retirement Plan contains both a traditional defined benefit component and a cash balance component. Only employees hired before January 1, 2002 may participate in the traditional defined benefit component. Because none of our Named Executive Officers were hired before January 1, 2002, no Named Executive Officer participates in the traditional defined benefit component. Employees hired after January 1, 2002 and before October 1, 2007 are eligible to participate in the cash balance component and receive monthly contribution credits based on age and years of accredited service. In addition, effective December 31, 2009, certain assets and liabilities under the Salary Deferral Program and the Supplemental Retirement Plan were transferred to the cash balance component of the Retirement Plan. Because they were hired in 2004, Messrs. Campbell and Burke participate in the cash balance component of the Retirement Plan.

Under the cash balance component of the Retirement Plan, hypothetical accounts are established for participants and credited with monthly contribution credits equal to a percentage of the participant’s compensation (3.5%, 4.5%, 5.5% or 6.5% depending on the participant’s combined age and years of accredited service), contribution credits equal to the amounts transferred from the Salary Deferral Program and/or the Supplemental Retirement Plan in 2009 and interest credits on all of such amounts based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year.

The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Retirement Plan. Under the Supplemental Retirement Plan, retirement benefits under the cash balance component are calculated in accordance with the same formula used under the Retirement Plan. Participation in EFH Corp.’s Supplemental Retirement Plan has been limited to employees of all of its businesses other than Oncor, who were employed by EFH Corp. (or its participating subsidiaries) on or before October 1, 2007. Because they were hired in 2004, Messrs. Campbell and Burke participate in the Supplemental Retirement Plan, and because they were hired after October 2007, Messrs. Young, Keglevic and McFarland are not eligible to participate in the Supplemental Retirement Plan.

Benefits accrued under the Supplemental Retirement Plan after December 31, 2004, are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirements of Section 409A and related guidance.

The present value of the accumulated benefit for the Retirement Plan (the cash balance component) was calculated as the value of their cash balance account projected to age 65 at an assumed growth rate of 4.5% and then discounted back to December 31, 2011 at 5.0%. No mortality or turnover assumptions were applied.

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Nonqualified Deferred Compensation – 2011⁽¹⁾ 

The following table sets forth information regarding plans that provide for the deferral of the Named Executive Officers’ compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2011:

Name	Executive Contributions in  Last FY ($)	Registrant Contributions  in Last FY ($)(2)	Aggregate Earnings in  Last FY ($)	Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at Last FYE  ($)(3)
John F. Young(4)	—	$6,740,600	($7,570)		$7,042,432
Paul M. Keglevic(4)	—	$3,651,394	($1)		$3,789,049
David A. Campbell	—	$3,187,638	($9,729)	($40,644)	$3,626,121
James A. Burke(4)	—	$3,201,293	($32,075)	($3,655)	$3,667,961
M.A. McFarland	—	$3,132,765			$3,132,765

___________

(1) The amounts reported in the Nonqualified Deferred Compensation table include deferrals and the company match under the Salary Deferral Program. Under EFH Corp.'s Salary Deferral Program each employee of EFH Corp. and its participating subsidiaries who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Salary Deferral Program ($110,840 for the program year beginning January 1, 2011) may elect to defer up to 50% of annual base salary, and/or up to 85% of the annual incentive award, for a maturity period of seven years, for a maturity period ending with the retirement of such employee, or for a combination thereof. EFH Corp. provided no matching contributions for 2011. Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Salary Deferral Program selected by each participant. At the end of the applicable maturity period, the trustee for the Salary Deferral Program distributes the deferred compensation, any vested matching awards and the applicable earnings in cash as a lump sum or in annual installments at the participant's election made at the time of deferral. EFH Corp. is financing the retirement option portion of the Salary Deferral Program through the purchase of corporate-owned life insurance on the lives of participants. The proceeds from such insurance are expected to allow EFH Corp. to fully recover the cost of the retirement option. Since 2010, certain executive officers, including the Named Executive Officers, are not eligible to participate in the Salary Deferral Program.

(2) The amounts reported as “Registrant Contributions in Last FY” include the following for all Named Executive Officers: (i) the Initial LTI Award, which will be paid in September 2012 (subject to exceptions in limited circumstances), and (ii) the 2011 LTI Award, one half of which will be paid in September 2012 and one half of which will be paid in September 2013 (subject to exceptions in limited circumstances). The amount reported as “Registrant Contributions in Last FY” for Mr. Keglevic also includes the $500,000 portion of the special award he received in connection with his contribution to our liability management program, which will be paid in September 2012, and the fair market value of the 112,500 deferred shares of EFH Corp. common stock, which vested in July 2011.

(3) The amounts reported as “Aggregate Balance at Last FYE” include the following for all Named Executive Officers: (i) the Initial LTI Award, which will be paid in September 2012 (subject to exceptions in limited circumstances), (ii) the 2011 LTI Award, one half of which will be paid in September 2012 and one half of which will be paid in September 2013 (subject to exceptions in limited circumstances), and (iii) any amounts contributed under the Salary Deferral Plan. The amounts reported as “Aggregate Balance at Last FYE” for Messrs. Campbell and Burke also include the fair market value of deferred shares (500,000 shares with respect to Mr. Campbell and 450,000 shares with respect to Mr. Burke) that each is entitled to receive on the earlier to occur of their termination of employment or a change of control of EFH Corp. The amount reported as “Aggregate Balance at Last FYE” for Mr. Keglevic also includes the $50,000 portion of his signing bonus to be paid in July 2012 (subject to exceptions in limited circumstances), the $500,000 portion of the special award he received in connection with his contribution to our liability management program, which will be paid in September 2012, and the fair market value of the 112,500 deferred shares of EFH Corp. common stock, which vested in July 2011.

(4) A portion of the amounts reported as “Aggregate Balance at Last FYE” are also included in the Summary Compensation Table as follows: for Mr. Young, $80,000 of executive contributions is included as “Salary” for 2009, and $80,000 of company matching contributions is included as “All Other Compensation” for 2009; for Mr. Keglevic, $48,000 of executive contributions is included as “Salary” for 2009, and $48,000 of company matching contributions is included as “All Other Compensation” for 2009; for Mr. Burke, $48,000 of executive contributions is included as “Salary” for 2009, and $48,000 of company matching contributions is included as “All Other Compensation” for 2009.

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Potential Payments upon Termination or Change in Control

The tables and narrative below provide information for payments to each of the Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of his termination, including if such termination is voluntary, for cause, as a result of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection with a change in control.

The information in the tables below is presented in accordance with SEC rules, assuming termination of employment as of December 31, 2011.

Employment Arrangements with Contingent Payments

As of December 31, 2011, each ofMessrs. Young, Keglevic, Campbell, Burke and McFarland had employment agreements with change in control and severance provisions. With respect to each Named Executive Officer's employment agreement, a change in control is generally defined as (i) a transaction that results in a sale of substantially all of our assets or capital stock to another person who is not an affiliate of any member of the Sponsor Group and such person having more seats on our Board than the Sponsor Group, (ii) a transaction that results in a person not in the Sponsor Group owning more than 50% of our common stock and such person having more seats on our Board than the Sponsor Group or (iii) a transaction that results in the Sponsor Group owning less than 20% of our common stock and the Sponsor Group not being able to appoint a majority of the directors to our Board.

Each Named Executive Officer’s employment agreement includes customary non-compete and non-solicitation provisions that generally restrict the Named Executive Officer’s ability to compete with us or solicit our customers or employees for his own personal benefit during the term of the employment agreement and 24 months (with respect to Mr. Young) or 18 months (with respect to Messrs. Keglevic, Campbell, Burke and McFarland) after the employment agreement expires or is terminated.

Each of our Named Executive Officers has been granted long-term cash incentive awards, the Initial LTI Award, 2011 LTI Award and 2015 LTI Award, as more fully described above in “Amendment to Long-Term Cash Incentive Awards” and “Long Term Incentive Awards.” In the event of such Named Executive Officer's termination without cause, resignation for good reason or termination due to death or disability (or in certain circumstances when the Named Executive Officer's employment term is not extended) the Initial LTI Award, 2011 LTI Award and 2015 Award will vest and become payable, to the extent earned, on a pro-rated basis. In the event of termination without cause or resignation for good reason following a change in control of EFH Corp., the Initial LTI Award, 2011 LTI Award and 2015 LTI Award will vest and become payable, to the extent earned, on the same pro-rata basis; however the pro-rata calculation will include the actual management EBITDA for any earned, but unpaid, fiscal years prior to termination and the target level of management EBITDA, without regard to the actual achievement of management EBITDA, for any subsequent applicable years.

Each of our Named Executive Officers has the opportunity to receive a grant of Annual RSUs in each of 2011, 2012, and 2013, following the approval of such year's grant during the annual February O&C Committee meeting. In the event of such Named Executive Officer's termination without cause, resignation for good reason or termination due to death or disability, such year's Annual RSUs will vest on a pro-rata basis based on a ratio, the numerator of which is the length of time of the executive officer's employment from the date of the grant of such year's Annual RSUs to his termination and the denominator of which is the length of time from the date of grant of the Annual RSUs to the original vesting date. In the event of a change of control of EFH Corp., all ungranted Annual RSUs that would have been made to the executive in each of 2012 and 2013 will be immediately granted and vested.

As of December 31, 2011, each ofour Named Executive Officers had been granted Exchange RSUs. Under the applicable agreements governing these Exchange RSUs, in the event of such Named Executive Officer's termination without cause or resignation for good reason (or in certain circumstances when the Named Executive Officer's employment term is not extended) following a change in control of EFH Corp., such Named Executive Officer's Exchange RSUs would immediately vest as to 100% of the shares of EFH Corp. common stock subject to such Restricted Stock Units immediately prior to the change in control of EFH Corp. Additionally, in the event of such Named Executive Officer's termination without cause, resignation for good reason or termination due to death or disability (or in certain circumstances when the Named Executive Officer's employment term is not extended), such Named Executive Officer's Exchange RSUs will vest on a pro rata basis based on a ratio, the numerator of which is the length of time of the Named Executive Officer's employment from the date of the grant of the Exchange RSU to his termination and the denominator of which is the length of time from the date of grant of the Exchange RSUs to the original vesting date.

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Pursuant to the terms of a Deferred Share Agreement, subject to certain vesting requirements described below, Mr. Keglevic is entitled to receive $3,200,000 (the “Deferred Amount”). The Deferred Amount vests on September 30, 2012 provided that Mr. Keglevic is employed by EFH Corp. on such date (provided, however that the Deferred Amount shall become immediately vested upon a change of control of EFH Corp., a termination of Mr. Keglevic by EFH Corp. without cause, a resignation by Mr. Keglevic for good reason or due to Mr. Keglevic's death or disability). In the event that Mr. Keglevic's employment with EFH Corp. terminates prior to a vesting event described above, in lieu of the Deferred Amount, EFH Corp. will deliver to Mr. Keglevic the 112,500 shares of EFH Corp. common stock that vested in July 2011. Payment of the Deferred Amount or delivery of the shares (as applicable) will be made upon the earliest of September 30, 2013, Mr. Keglevic's termination of employment for any reason (or six months and one day following such termination of employment in the event EFH Corp. common stock is publicly traded on an established securities market at such time), or a change of control of EFH Corp.

Messrs. Campbell and Burke are each entitled to receive shares of EFH Corp. common stock (500,000 shares with respect to Mr. Campbell and 450,000 shares with respect to Mr. Burke) on the earlier to occur of their termination for any reason or a change in control of EFH Corp.

Please refer to the Pension Benefits - 2011 table, including the footnotes thereto, for a description of additional amounts Messrs. Young, Keglevic, Campbell and Burke are entitled to receive upon their termination for any reason or a change of control of EFH Corp.

Excise Tax Gross-Ups

Pursuant to their employment agreements, if any of our Named Executive Officers is subject to the imposition of the excise tax imposed by Section 4999 of the Code, related to the executive's employment, but the imposition of such tax could be avoided by approval of our shareholders as described in Section 280G(b)(5)(B) of the Code, then such executive may cause EFH Corp. to seek such approval, in which case EFH Corp. will use its reasonable best efforts to cause such approval to be obtained and such executive will cooperate and execute such waivers as may be necessary so that such approval avoids imposition of any excise tax under Section 4999. If such executive fails to cause EFH Corp. to seek such approval or fails to cooperate and execute the waivers necessary in the approval process, such executive shall not be entitled to any gross-up payment for any resulting tax under Section 4999. Because we believe the shareholder approval exception to such excise tax will apply, the tables below do not reflect any amounts for such gross-up payments.

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1. Mr. Young

Potential Payments to Mr. Young upon Termination as of December 31, 2011 (per employment agreement and restricted stock agreement, each in effect as of December 31, 2011)

Benefit	Voluntary	For Cause	Death		Disability		Without Cause  Or For Good Reason		Without Cause  Or For Good Reason In Connection With Change in Control
Cash Severance							$	4,800,000	$	7,200,000
EAIP			$	1,728,000	$	1,728,000
Supplemental Retirement Plan			$	3,000,000	$	3,000,000	$	3,000,000	$	3,000,000
LTI Cash Retention Award:
- Initial LTI Award			$	5,240,600	$	5,240,600	$	5,240,600	$	5,240,600
- 2011 LTI Award			$	1,500,000	$	1,500,000	$	1,500,000	$	1,500,000
LTI Equity Incentive Award:
- Annual RSUs			$	181,269	$	181,269	$	181,269	$	2,250,000
- Exchange RSUs			$	543,807	$	543,807	$	543,807	$	2,250,000
Deferred Compensation:
- Salary Deferral Program			$	170,848	$	170,848			$	170,848
Health & Welfare:
- Medical/COBRA							$	36,427	$	36,427
- Dental/COBRA							$	3,090	$	3,090
Totals			$	12,364,524	$	12,364,524	$	15,305,193	$	21,650,965

Mr. Young has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Young's voluntary resignation without good reason or termination with cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned for the previously completed year;

c. unreimbursed business expenses; and

d. payment of employee benefits, including equity compensation, if any, to which Mr. Young may be entitled.

2. In the event of Mr. Young's death or disability:

a. a prorated annual incentive bonus for the year of termination;

b. value of supplemental retirement plan for Mr. Young that commences on December 31, 2014;

c. the pro-rata cash retention award earned prior to the date of termination;

d. the pro-rata equity incentive award earned prior to the date of termination; and

e. payment of employee benefits, including equity compensation, if any, to which Mr. Young may be entitled.

3. In the event of Mr. Young's termination without cause or resignation for good reason:

a. a lump sum payment equal to (i) three times his annualized base salary and (ii) a prorated annual incentive bonus for the year of termination;

b. value of supplemental retirement plan for Mr. Young that commences on December 31, 2014;

c. the pro-rata cash retention award earned prior to the date of termination;

d. the pro-rata equity incentive award earned prior to the date of termination;

e. payment of employee benefits, including equity compensation, if any, to which Mr. Young may be entitled; and

f. certain continuing health care and company benefits.

4. In the event of Mr. Young's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to three times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. value of supplemental retirement plan for Mr. Young that commences on December 31, 2014;

c. the pro-rata cash retention award earned prior to the date of termination;

d. all Exchange RSUs;

e. all Annual RSUs;

f. payment of employee benefits, including equity compensation, if any, to which Mr. Young may be entitled; and

g. certain continuing health care and company benefits.

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2. Mr. Keglevic

Potential Payments to Mr. Keglevic upon Termination as of December 31, 2011 (per employment agreement, deferred share agreement and restricted stock unit agreement, each in effect as of December 31, 2011)

Benefit	Voluntary(1)		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For  Good Reason In Connection With  Change in Control
Cash Severance									$	1,852,500	$	2,405,000
EAIP					$	795,600	$	795,600
Payment of Cash or EFH Corp. Common Stock in respect of Restricted Stock Units (2)	$	56,250	$	56,250	$	3,200,000	$	3,200,000	$	3,200,000	$	3,200,000
LTI Cash Retention Award:
- Initial LTI Award					$	1,795,144	$	1,795,144	$	1,795,144	$	1,795,144
- 2011 LTI Award					$	1,300,000	$	1,300,000	$	1,300,000	$	1,300,000
LTI Equity Incentive Award:
- Annual RSUs					$	60,423	$	60,423	$	60,423	$	750,000
- Exchange RSUs					$	181,269	$	181,269	$	181,269	$	750,000
Deferred Compensation
- Salary Deferral Program					$	68,070	$	68,070			$	68,070
Health & Welfare
- Dental/COBRA									$	1,643	$	1,643
Totals	$	56,250	$	56,250	$	7,400,506	$	7,400,506	$	8,390,979	$	10,269,857

_______________

(1) Pursuant to his employment agreement, if Mr. Keglevic voluntarily resigned on or before December 31, 2011, he would have been required to return to EFH Corp. the $50,000 portion of his signing bonus he received in July 2011.

(2) See description of Mr. Keglevic's Deferred Share Agreement above.

Mr. Keglevic has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Keglevic's voluntary resignation without good reason or termination with cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned for the previously completed year;

c. unreimbursed business expenses; and

d. payment of employee benefits, including equity compensation, if any, to which Mr. Keglevic may be entitled.

2. In the event of Mr. Keglevic's death or disability:

a. a prorated annual incentive bonus for the year of termination;

b. the pro-rata cash retention award earned prior to the date of termination;

c. the pro-rata equity incentive award earned prior to the date of termination; and

d. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled.

3. In the event of Mr. Keglevic's termination without cause or resignation for good reason:

a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination;

b. the pro-rata cash retention award earned prior to the date of termination;

c. the pro-rata equity incentive award earned prior to the date of termination;

d. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled; and

e. certain continuing health care and company benefits.

4. In the event of Mr. Keglevic's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. the pro-rata cash retention award earned prior to the date of termination;

c. all Exchange RSUs;

d. all Annual RSUs;

e. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled; and

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f. certain continuing health care and company benefits.

3. Mr. Campbell

Potential Payments to Mr. Campbell upon Termination as of December 31, 2011 (per employment agreement, deferred share agreement and restricted stock unit agreement, each in effect as of December 31, 2011)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause  Or For Good Reason		Without Cause Or  For Good Reason  In Connection With Change in  Control
Cash Severance									$	1,995,000	$	2,590,000
EAIP					$	892,500	$	892,500
Distribution of Deferred Shares (1)	$	250,000	$	250,000	$	250,000	$	250,000	$	250,000	$	250,000
LTI Cash Retention Award:
- Initial LTI Award					$	1,887,638	$	1,887,638	$	1,887,638	$	1,887,638
- 2011 LTI Award					$	1,300,000	$	1,300,000	$	1,300,000	$	1,300,000
LTI Equity Incentive Award:
- Annual RSUs					$	80,564	$	80,564	$	80,564	$	1,000,000
- Exchange RSUs					$	290,030	$	290,030	$	290,030	$	1,200,000
Deferred Compensation
- Salary Deferral Program (2)
Health & Welfare
- Medical/COBRA									$	27,885	$	27,885
- Dental/COBRA									$	2,472	$	2,472
Totals	$	250,000	$	250,000	$	4,700,732	$	4,700,732	$	5,833,589	$	8,257,995

_______________

(1) The amount reported under the heading “Distribution of Deferred Shares” represents the fair market value of 500,000 shares of EFH Corp. common stock as of December 31, 2011, that Mr. Campbell is entitled to receive, pursuant to the terms of his deferred share agreement, on the earlier to occur of his termination of employment for any reason or a change in the effective control of EFH Corp.

(2) Mr. Campbell is fully vested in the company matching portion of the Salary Deferral Plan.

Mr. Campbell has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Campbell's voluntary resignation without good reason or termination with cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned for the previously completed year;

c. unreimbursed business expenses; and

d. payment of employee benefits, including equity compensation, if any, to which Mr. Campbell may be entitled.

2. In the event of Mr. Campbell's death or disability:

a. a prorated annual incentive bonus for the year of termination;

b. the pro-rata cash retention award earned prior to the date of termination;

c. the pro-rata equity incentive award earned prior to the date of termination; and

d. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled.

3. In the event of Mr. Campbell's termination without cause or resignation for good reason:

a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination;

b. the pro-rata cash retention award earned prior to the date of termination;

c. the pro-rata equity incentive award earned prior to the date of termination;

d. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled; and

e. certain continuing health care and company benefits.

4. In the event of Mr. Campbell's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. the pro-rata cash retention award earned prior to the date of termination;

221

c. all Exchange RSUs;

d. all Annual RSUs;

e. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled; and

f. certain continuing health care and company benefits.

4. Mr. Burke

Potential Payments to Mr. Burke upon Termination as of December 31, 2011 (per employment agreement, deferred share agreement and restricted stock unit agreement, each in effect as of December 31, 2011)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For  Good Reason In Connection With  Change in Control
Cash Severance									$	1,795,500	$	2,331,000
EAIP					$	745,416	$	745,416
Distribution of Deferred Shares (1)	$	225,000	$	225,000	$	225,000	$	225,000	$	225,000	$	225,000
LTI Cash Retention Award:
- Initial LTI Award					$	1,901,293	$	1,901,293	$	1,901,293	$	1,901,293
- 2011 LTI Award					$	1,300,000	$	1,300,000	$	1,300,000	$	1,300,000
LTI Equity Incentive Award:
- Annual RSUs					$	60,423	$	60,423	$	60,423	$	750,000
- Exchange RSUs					$	160,121	$	160,121	$	160,121	$	662,500
Deferred Compensation
- Salary Deferral Program					$	65,486	$	65,486			$	65,486
Health & Welfare
- Medical/COBRA									$	27,885	$	27,885
- Dental/COBRA									$	2,472	$	2,472
Totals	$	225,000	$	225,000	$	4,457,739	$	4,457,739	$	5,472,694	$	7,265,636

_______________

(1) The amount reported under the heading “Distribution of Deferred Shares” represents the fair market value of 450,000 shares of EFH Corp. common stock as of December 31, 2011 that Mr. Burke is entitled to receive, pursuant to the terms of his deferred share agreement, on the earlier to occur of his termination of employment for any reason or a change in the effective control of EFH Corp.

Mr. Burke has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances.

1. In the event of Mr. Burke's voluntary resignation without good reason or termination with cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned for the previously completed year;

c. unreimbursed business expenses; and

d. payment of employee benefits, including equity compensation, if any, to which Mr. Burke may be entitled.

2. In the event of Mr. Burke's death or disability:

a. a prorated annual incentive bonus for the year of termination;

b. the pro-rata cash retention award earned prior to the date of termination;

c. the pro-rata equity incentive award earned prior to the date of termination; and

d. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled.

3. In the event of Mr. Burke's termination without cause or resignation for good reason:

a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination;

b. the pro-rata cash retention award earned prior to the date of termination;

c. the pro-rata equity incentive award earned prior to the date of termination;

d. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled; and

e. certain continuing health care and company benefits.

4. In the event of Mr. Burke's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

222

a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. the pro-rata retention award earned prior to the date of termination;

c. all Exchange RSUs;

d. all Annual RSUs;

e. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled; and

f. certain continuing health care and company benefits.

5. Mr. McFarland

Potential Payments to Mr. McFarland upon Termination as of December 31, 2011 (per employment agreement and restricted stock unit agreement, each in effect as of December 31, 2011)

Benefit	Voluntary	For Cause	Death		Disability		Without Cause Or For Good Reason		Without Cause Or For  Good Reason In Connection With  Change in Control
Cash Severance							$	1,710,000	$	2,220,000
EAIP			$	807,840	$	807,840
LTI Cash Retention Award:
- Initial LTI Award			$	1,832,765	$	1,832,765	$	1,832,765	$	1,832,765
- 2011 LTI Award			$	1,300,000	$	1,300,000	$	1,300,000	$	1,300,000
LTI Equity Incentive Award:
- Annual RSUs			$	60,423	$	60,423	$	60,423	$	750,000
- Exchange RSUs			$	145,015	$	145,015	$	145,015	$	600,000
Health & Welfare
- Medical/COBRA							$	27,885	$	27,885
- Dental/COBRA							$	2,472	$	2,472
Totals			$	4,146,043	$	4,146,043	$	5,078,560	$	6,733,122

Mr. McFarland entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. McFarland's voluntary resignation without good reason or termination with cause:

a. accrued but unpaid base salary and unused vacation earned through the date of termination;

b. accrued but unpaid annual bonus earned for the previously completed year;

c. unreimbursed business expenses; and

d. payment of employee benefits, including equity compensation, if any, to which Mr. McFarland may be entitled.

2. In the event of Mr. McFarland's death or disability:

a. a prorated annual incentive bonus for the year of termination;

b. the pro-rata cash retention award earned prior to the date of termination;

c. the pro-rata equity incentive award earned prior to the date of termination; and

d. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled.

3. In the event of Mr. McFarland's termination without cause or resignation for good reason:

a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination;

b. the pro-rata cash retention award earned prior to the date of termination;

c. the pro-rata equity incentive award earned prior to the date of termination;

d. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled; and

e. certain continuing health care and company benefits.

4. In the event of Mr. McFarland's termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. the pro-rata cash retention award earned prior to the date of termination;

c. all Exchange RSUs;

d. all Annual RSUs;

e. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled; and

f. certain continuing health care and company benefits.

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Compensation Committee Interlocks and Insider Participation

There are no relationships among our executive officers, members of the O&C Committee or entities whose executives served on the O&C Committee that required disclosure under applicable SEC rules and regulations. For a description of related person transactions involving members of the O&C Committee, see Item 13, entitled “Related Person Transactions.”

Director Compensation

The table below sets forth information regarding the aggregate compensation paid to the members of the Board during the year ended December 31, 2011. Directors who are officers of EFH Corp. or members of the Sponsor Group (or their respective affiliates) do not receive any fees for service as a director. EFH Corp. reimburses directors for expenses incurred in connection with their services as directors.

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	All Other Compensation ($)	Total ($)
Arcilia C. Acosta (1)	150,000	100,000	—	250,000
David Bonderman	—	—	—	—
Donald L. Evans (2)	—	—	2,160,877	2,160,877
Thomas D. Ferguson	—	—	—	—
Frederick M. Goltz	—	—	—	—
James R. Huffines (1)	150,000	100,000	—	250,000
Scott Lebovitz	—	—	—	—
Jeffrey Liaw	—	—	—	—
Marc S. Lipschultz	—	—	—	—
Michael MacDougall	—	—	—	—
Lyndon L. Olson, Jr. (1)	150,000	100,000	—	250,000
Kenneth Pontarelli	—	—	—	—
William K. Reilly (1)	150,000	100,000	—	250,000
Jonathan D. Smidt	—	—	—	—
John F. Young	—	—	—	—
Kneeland Youngblood (1)	150,000	100,000	—	250,000

______________

(1) Ms. Acosta and Messrs. Huffines, Olson, Reilly and Youngblood receive $150,000 annually and an annual equity award (paid in shares of EFH Corp. common stock) valued at $100,000 (the grant date fair value) for their service as a director.

(2) In February 2010, we entered into a consulting agreement with Mr. Evans, pursuant to which Mr. Evans receives an annual fee of $2,000,000. The amounts for 2011 reported as “All Other Compensation” for Mr. Evans represent his annual fee and the costs of providing certain perquisites, including $160,877 for an office and administrative assistant in Midland, Texas. The initial term of the consulting agreement expires in October 2012. Effective January 1, 2012, we entered into a new consulting agreement with Mr. Evans, pursuant to which Mr. Evans will receive an annual fee of $2,500,000. Under the terms of the new consulting agreement, Mr. Evans also received (i) a grant of 4,400,000 options to purchase the common stock of EFH Corp. at a strike price of $0.50 per share, which vest in four equal installments from December 2013 to December 2015, (ii) a modification of the strike price of his 600,000 vested options to purchase the common stock of EFH Corp. to $0.50 per share, and (iii) payment by EFH Corp. of (a) $100,000 annually for office expenses and administrative support, (b) up to $200,000 annually in salary payments to a chief of staff, and (c) executive assistant services in Dallas and Midland, Texas. The initial term of the new consulting agreement expires in December 2015, and the parties have the ability to renew the agreement for up to an additional three years upon terms that are mutually agreeable.

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

The following table presents information concerning stock-based compensation plans as of December 31, 2011. (See Note 19 to Financial Statements.)

	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans, excluding securities reflected in column (a)
Equity compensation plans approved by security holders	—	$	—	—
Equity compensation plans not approved by security holders	46,416,114	$	1.70	25,583,886
Total	46,416,114	$	1.70	25,583,886

____________

Note: Includes 10.8 million vested and unvested restricted shares, deferred shares and stock granted to directors as part of their compensation plan. Also includes 20.5 million restricted stock units issued in exchange for previously issued stock options.

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Beneficial Ownership of Common Stock of Energy Future Holdings Corp.

The following table lists the number of shares of common stock of EFH Corp. beneficially owned by each director and certain executive officers of EFH Corp. and the holders of more than 5% of EFH Corp.’s common stock as of February 1, 2012.

The amounts and percentages of shares of common stock of EFH Corp. beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under SEC rules, a person is deemed to be a "beneficial owner" of a security if that person has or shares voting power or investment power, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person's ownership percentage, but not for purposes of computing any other person's percentage. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest.

Name	Number of Shares Beneficially Owned	Percent of Class
Texas Holdings (1)(2)(3)(4)	1,657,600,000	98.60	%
Arcilia C. Acosta (6)	193,529	*
David Bonderman (2)	1,657,600,000	98.60	%
Donald L. Evans (7)	1,000,000	*
Thomas D. Ferguson (3)	1,657,600,000	98.60	%
Frederick M. Goltz (5)	—	—	%
James R. Huffines	483,529	*
Scott Lebovitz (3)	1,657,600,000	98.60	%
Jeffrey Liaw (8)	—	—	%
Marc S. Lipschultz (5)	—	—	%
Michael MacDougall (8)	—	—	%
Lyndon L. Olson, Jr.	343,529	*
Kenneth Pontarelli (3)	1,657,600,000	98.60	%
William K. Reilly (9)	323,529	*
Jonathan D. Smidt (5)	—	—	%
John F. Young	1,012,222	*
Kneeland Youngblood (13)	263,529	*
James A. Burke (10)	450,000	*
David A. Campbell (11)	500,000	*
Paul M. Keglevic (12)	112,500	*
M. A. McFarland	100,000	*
All directors and current executive officers as a group (22 persons)	1,662,382,367	98.88	%

___________

* Less than 1%.

(1) Texas Holdings beneficially owns 1,657,600,000 shares of EFH Corp. The sole general partner of Texas Holdings is Texas Energy Future Capital Holdings LLC ("Texas Capital"), which, pursuant to the Amended and Restated Limited Partnership Agreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The TPG Funds, the Goldman Entities and the KKR Entities (each as defined below, and collectively, the "Texas Capital Funds") collectively own 91.08% of the outstanding units of Texas Capital. The Texas Capital Funds exercise control over Texas Capital and each has the right to designate and remove the managers of Texas Capital appointed by such Texas Capital Fund. Because of these relationships, each of the Texas Capital Funds may be deemed to have beneficial ownership of the shares of EFH Corp. held by Texas Holdings, but each disclaims beneficial ownership of such shares. The address of both Texas Holdings and Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

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(2) The TPG Funds (as defined below) beneficially own 302,923,439.752 units of Texas Capital, representing 27.01% of the outstanding units, including (i) 271,639,218.931 units held by TPG Partners V, L.P., a Delaware limited partnership ("TPG Partners V"), whose general partner is TPG GenPar V, L.P., a Delaware limited partnership ("TPG GenPar V"), whose general partner is TPG GenPar V Advisors, LLC, a Delaware limited liability company, whose sole member is TPG Holdings I, L.P., a Delaware limited partnership ("TPG Holdings"), (ii) 29,999,994.650 units held by TPG Partners IV, L.P., a Delaware limited partnership ("TPG Partners IV"), whose general partner is TPG GenPar IV, L.P., a Delaware limited partnership, whose general partner is TPG GenPar IV Advisors, LLC, a Delaware limited liability company, whose sole member is TPG Holdings, (iii) 710,942.673 units held by TPG FOF V-A, L.P., a Delaware limited partnership ("TPG FOF A"), whose general partner is TPG GenPar V and (iv) 573,283.498 units held by TPG FOF V-B, L.P., a Delaware limited partnership ("TPG FOF B" and, together with TPG Partners V, TPG Partners IV and TPG FOF A, the "TPG Funds"), whose general partner is TPG GenPar V. The general partner of TPG Holdings is TPG Holdings I-A, LLC, a Delaware limited liability company, whose sole member is TPG Group Holdings (SBS), L.P., a Delaware limited partnership, whose general partner is TPG Group Holdings (SBS) Advisors, Inc., a Delaware corporation ("Group Advisors"). David Bonderman and James G. Coulter are directors, officers and sole shareholders of Group Advisors and may therefore be deemed to beneficially own the units held by the TPG Funds. David Bonderman is also a manager of Texas Capital. Messrs. Bonderman and Coulter disclaim beneficial ownership of the shares of EFH Corp. held by Texas Holdings except to the extent of their pecuniary interest therein. The address of Group Advisors and Messrs. Bonderman and Coulter is c/o TPG Capital, L.P., 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

(3) GS Capital Partners VI Fund, L.P., GSCP VI Offshore TXU Holdings, L.P., GSCP VI Germany TXU Holdings, L.P., GS Capital Partners VI Parallel, L.P., GS Global Infrastructure Partners I, L.P., GS Infrastructure Offshore TXU Holdings, L.P. (GSIP International Fund), GS Institutional Infrastructure Partners I, L.P., Goldman Sachs TXU Investors L.P. and Goldman Sachs TXU Investors Offshore Holdings, L.P. (collectively, the "Goldman Entities") beneficially own 303,094,945.954 units of Texas Capital, representing 27.02% of the outstanding units. Affiliates of The Goldman Sachs Group, Inc. ("Goldman Sachs") are the general partner, managing general partner or investment manager of each of the Goldman Entities, and each of the Goldman Entities shares voting and investment power with certain of their respective affiliates. Each of Goldman Sachs and the Goldman Entities disclaims beneficial ownership of such shares of common stock except to the extent of its pecuniary interest therein. Messrs. Ferguson, Lebovitz and Pontarelli are managers of Texas Capital and executives with affiliates of Goldman Sachs. By virtue of their position in relation to Texas Capital and the Goldman Entities, Messrs. Ferguson, Lebovitz and Pontarelli may be deemed to have beneficial ownership with respect to the units of Texas Capital held by the Goldman Entities. Each of Messrs. Ferguson, Lebovitz and Pontarelli disclaims beneficial ownership of the shares of EFH Corp. held by Texas Holdings except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Goldman, Sachs & Co., 85 Broad Street, New York, New York 10004.

(4) KKR 2006 Fund L.P., KKR PEI Investments, L.P., KKR Partners III, L.P., KKR North American Co-Invest Fund I L.P. and TEF TFO Co-Invest, LP (collectively, the "KKR Entities") beneficially own 415,473,419.680 units of Texas Capital, representing 37.05% of the outstanding units. The KKR Entities disclaim beneficial ownership of any shares of our common stock in which they do not have a pecuniary interest. KKR & Co. L.P., as the holding company of affiliates that directly or indirectly control the KKR Entities, other than KKR Partners III, LP., may be deemed to share voting and dispositive power with respect to the shares beneficially owned by such KKR Entities, but disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. As the designated members of KKR Management LLC (which is the general partner of KKR & Co. L.P.) and the managing members of KKR III GP LLC (which is the general partner of KKR Partners III, L.P.), Henry R. Kravis and George R. Roberts may be deemed to share voting and dispositive power with respect to the shares beneficially owned by the KKR Entities but disclaim beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019.

(5) Messrs. Goltz, Lipschultz and Smidt are managers of Texas Capital and executives of Kohlberg Kravis Roberts & Co. L.P. and/or one or more of its affiliates. None of Messrs. Goltz, Lipschultz or Smidt have voting or investment power over and each disclaim beneficial ownership of the units held by the KKR Entities and the shares of EFH Corp. held by Texas Holdings, except in each case to the extent of their pecuniary interest. The address of each individual listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019.

(6) 70,000 shares held in a family limited partnership, ACA Family LP.

(7) Includes 600,000 shares issuable upon exercise of vested options.

(8) Jeffrey Liaw is a TPG principal and Michael MacDougall is a TPG partner. Messrs. Liaw and MacDougall are each managers of Texas Capital. Neither Mr. Liaw nor Mr. MacDougall have voting or investment power over and each disclaim beneficial ownership of the units held by the TPG Funds and the shares of EFH Corp. held by Texas Holdings. The address of Messrs. Liaw and MacDougall is c/o TPG Capital, L.P., 301 Commerce Street, Suite 3300, Fort Worth, TX 76102.

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(9) William K. Reilly is a TPG senior advisor. Mr. Reilly does not have voting or investment power over and disclaims beneficial ownership of the units held by the TPG Funds. The address of Mr. Reilly is c/o TPG Capital, L.P., 301 Commerce Street, Suite 3300, Fort Worth, TX 76102.

(10) Shares consist of 450,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp.

(11) Shares consist of 500,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp.

(12) Shares consist of 112,500 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp.

(13) 100,000 shares held in a limited partnership, Burton Hills Limited, LP.

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

Policies and Procedures Relating to Related Party Transactions

The Board has adopted a policy regarding related person transactions. Under this policy, a related person transaction shall be consummated or shall continue only if:

1. the Audit Committee of the Board approves or ratifies such transaction in accordance with the policy and determines that the transaction is on terms comparable to those that could be obtained in arm’s length dealings with an unrelated third party;

2. the transaction is approved by the disinterested members of the Board or the Executive Committee; or

3. the transaction involves compensation approved by the Organization and Compensation Committee of the Board.

For purposes of this policy, the term "related person" includes EFH Corp.'s directors, executive officers, 5% shareholders and their immediate family members." Immediate family members" means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.

A "related person transaction" is a transaction between EFH Corp. or its subsidiaries and a related person, other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:

1. any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act;

2. any transaction with another company at which a related person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company's ownership interests;

3. any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person's only relationship is as an employee (other than an executive officer) or director;

4. transactions where the related person's interest arises solely from the ownership of EFH Corp.’s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis;

5. transactions involving a related party where the rates or charges involved are determined by competitive bids;

6. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority;

7. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service;

8. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable);

9. transactions involving less than $100,000 when aggregated with all similar transactions;

10. transactions between EFH Corp. and its subsidiaries or between subsidiaries of EFH Corp.;

11. transactions not required to be disclosed under Item 404 of Regulation S-K under the Securities Act of 1933, and

12. open market purchases of EFH Corp.'s or its subsidiaries' debt or equity securities and interest payments on such debt.

The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify related person transactions. Accordingly, at least annually, management reviews related person transactions to be entered into by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the Board approves/ratifies or disapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such related person transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed and ratified as soon as reasonably practicable by the Audit Committee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. makes all reasonable efforts to cancel or otherwise terminate the affected transactions.

The related person transactions described below under "Related Person Transactions – Business Affiliations," were ratified by the Audit Committee of the Board pursuant to the policy described above. All other related person transactions were approved prior to the Board's adoption of this policy, but were approved by either the Board or its Executive Committee. Transactions described below under "Related Person Transactions – Transactions with Sponsor Affiliates" are not related person transactions under the EFH Corp. policy because they are not with a director, executive officer, 5% shareholder or any of their immediate family members, but are described in the interest of greater disclosure.

229

Related Person Transactions

Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership; Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC

The Sponsor Group and certain investors who agreed to co-invest with the Sponsor Group or through a vehicle jointly controlled by the Sponsor Group to provide equity financing for the Merger (Co-Investors) entered into (i) a limited partnership agreement (LP Agreement) in respect of EFH Corp.'s parent company, Texas Holdings and (ii) the LLC Agreement in respect of Texas Holdings' sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or execute consents with respect to any shares of EFH Corp.’s common stock owned by Texas Holdings. The LLC Agreement and LP Agreement contain agreements among the parties with respect to the election of EFH Corp.'s directors, restrictions on the issuance or transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions (including the right to approve various corporate actions).

The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managers of Texas Capital are also members of EFH Corp.'s Board. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. and affiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman Sachs, has the right to designate three managers of Texas Capital. These rights are subject to maintenance of certain investment levels in Texas Holdings.

Registration Rights Agreement

The Sponsor Group and the Co-Investors entered into a registration rights agreement with EFH Corp. upon completion of the Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the Sponsor Group and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.'s common stock under the Securities Act that it may undertake. Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Messrs. Young, Campbell, Burke, Keglevic, McFarland, O'Brien and Landy, each of whom are executive officers of EFH Corp., are parties to this agreement.

Management Services Agreement

In October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFH Corp. (Management Agreement), pursuant to which affiliates of the Sponsor Group provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount increases 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million in the aggregate for certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Under terms of the Management Agreement, EFH Corp. paid $37 million, inclusive of expenses, to the Sponsor Group during 2011.

Indemnification Agreement

Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. entered into an indemnification agreement (Indemnification Agreement), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, Company Group), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.

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Sale Participation Agreement

Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Young, Campbell, Burke, Keglevic, McFarland, O'Brien and Landy, each of whom are executive officers, entered into sale participation agreements with EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.'s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.'s common stock held by the Sponsor Group.

Certain Charter Provisions

EFH Corp.'s restated certificate of formation contains provisions limiting our directors' obligations in respect of corporate opportunities.

Management Stockholders' Agreement

Subject to a management stockholders' agreement, certain members of management, including EFH Corp.'s directors, executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The net aggregate amount of this investment as of December 31, 2011 is approximately $29 million. The management stockholders' agreement creates certain rights and restrictions on these shares of common stock, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.

Director Stockholders' Agreement

Certain members of our Board have entered into a stockholders' agreement with EFH Corp. These stockholders’ agreements create certain rights and restrictions on the equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.

Business Affiliations

Mr. Olson, a member of our board, has an ownership interest in Texas Meter and Device Company (TMD), a company that conducts tests on Oncor's high voltage personal protective equipment. Mr. Olson and his brother collectively directly own approximately 24% of TMD. This entity is majority owned by its chief executive officer. In 2011, Oncor paid TMD approximately $900 thousand for its services. The business relationship with TMD commenced several years prior to Mr. Olson joining the Board.

Mr. Olsen, a member of our board, has an ownership interest in Metrum Technologies (MT), a company that is a subsidiary of Texas Meter and Device Company and provides Oncor with certain technology based products for Oncor's advanced metering devices. Mr. Olson and his brother collectively directly own approximately 19% of MT. This entity is majority owned by its chief executive officer. In 2011, Oncor paid MT approximately $500 thousand for its services. The business relationship with MT commenced several years prior to Mr. Olson joining the Board.

Mr. Olsen, a member of our board of directors, is chairman of the New York and Sweden offices of Hill+Knowlton Strategies (HKS). Mr. Olsen is also a member of HKS' Global Counsel. HKS is the parent company of Public Strategies Inc. (PSI). PSI performs certain consulting services for EFH Corp. and its subsidiaries, primarily in the areas of public relations and public advocacy. Mr. Olsen does not have any ownership interest in HKS or its subsidiaries. In 2011, EFH Corp. and its subsidiaries paid approximately $5.9 million to PSI for its services.

Transactions with Sponsor Affiliates

TCEH entered into the TCEH Senior Secured Facilities, and Oncor entered into its revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners. These transactions were approved by the Board of Directors. Neither GS Capital Partners nor any of its affiliates is currently a lender under Oncor's revolving credit facility.

231

An affiliate of GS Capital Partners, a member of the Sponsor Group, acted as a joint lead arranger and joint book-runner in the April 2011 amendment and extension of the TCEH Senior Secured Facilities and received fees totaling approximately $17 million. Further, an affiliate of GS Capital Partners 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 approximately $9 million. In addition, an affiliate of GS Capital Partners acted as a joint book-running manager and initial purchaser in the issuance of $800 million principal amount of EFIH Second Lien Senior Secured Notes and received fees totaling approximately $4.5 million.

An affiliate of Kohlberg Kravis Roberts & Co. L.P., a member of the Sponsor Group, served as an advisor in the April 2011 amendment and extension of the TCEH Senior Secured Facilities and related transactions and received approximately $5 million as compensation for its services. In addition, an affiliate of Kohlberg Kravis Roberts & Co. L.P. served as a co-manager and initial purchaser in the issuance of $800 million principal amount of EFIH Second Lien Senior Secured Notes and received fees totaling approximately $800 thousand.

An affiliate of TPG Capital, L.P., a member of the Sponsor Group, served as an advisor in the April 2011 amendment and extension of the TCEH Senior Secured Facilities and related transactions and received approximately $5 million as compensation for its services. An affiliate of TPG Capital, L.P. served as an advisor in the issuance of $800 million principal amount of EFIH Second Lien Senior Secured Notes and received fees totaling approximately $800 thousand as compensation for its services.

Affiliates of GS Capital Partners have from time to time engaged in commercial and investment banking and financial advisory transactions with EFH Corp. in the normal course of business. Affiliates of Goldman Sachs & Co. are party to certain commodity and interest rate hedging transactions with EFH Corp. in the normal course of business.

From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.

Members of the Sponsor Group and/or their respective affiliates have from time to time entered into, and may continue to enter into, arrangements with the Company to use our products and services in the ordinary course of their business, which often result in revenues to the Company in excess of $120,000 annually. In addition, the Company has entered into, and may continue to enter into, arrangements with members of the Sponsor Group and/or their respective affiliates to use their products and services in the ordinary course of their business, which often result in revenues to members of the Sponsor Group or their respective affiliates in excess of $120,000 annually.

Director Independence

Though not formally considered by the Board because EFH Corp.'s common stock is not currently registered under the Exchange Act of 1934 with the SEC or traded on any national securities exchange, based upon the listing standards for issuers of equity securities on the New York Stock Exchange (NYSE), the national securities exchange upon which EFH Corp.'s common stock was traded prior to the Merger, only Ms. Acosta and Mr. Youngblood would be considered independent. Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other directors would be considered independent under the NYSE listing standards for issuers of equity securities. See "Certain Relationships and Related Party Transactions" and Item 11, "Executive Compensation – Director Compensation." Accordingly, we believe that Ms. Acosta is the only member of the Organization and Compensation Committee who would meet the NYSE's independence requirements for issuers of equity securities. We believe that none of the members of EFH Corp.'s Governance and Public Affairs Committee would meet the NYSE's independence requirements for issuers of equity securities. Under the NYSE’s audit committee independence requirement for issuers of debt securities, Messrs. Huffines and Youngblood and Ms. Acosta, who constitute the Audit Committee, are considered independent.

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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. 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 pre-approval by the Audit Committee of all anticipated audit and non-audit services; and

2. The quarterly pre-approval 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 2011 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 EFH Corp. from engaging its independent auditor to provide:

1. Bookkeeping or other services related to EFH Corp.’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 EFH Corp.’s independent auditor from providing tax or financial planning advice to any officer of EFH Corp.

233

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.

For the years ended December 31, 2011 and 2010, fees billed to EFH Corp. by Deloitte & Touche were as follows:

	2011		2010
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	$	6,298,000	$	5,833,000
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	445,000		706,000
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	19,000		102,000
All Other Fees. Fees for services including process improvement reviews, forensic accounting reviews, litigation and rate case assistance, and training services	—		—
Total	$	6,762,000	$	6,641,000

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PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Schedule I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

ENERGY FUTURE HOLDINGS CORP. (PARENT) SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF INCOME (LOSS) (Millions of Dollars)
	Year Ended December 31,
	2011			2010			2009
Selling, general and administrative expenses	$	(26	)	$	(32	)	$	(123	)
Other income	10			137			49
Other deductions	(14		)	—			(6		)
Interest income	132			178			235
Interest expense and related charges	(1,114		)	(1,082		)	(981		)
Loss before income taxes and equity in earnings of unconsolidated subsidiaries	(1,012		)	(799		)	(826		)
Income tax benefit	341			305			268
Equity in earnings of consolidated subsidiaries	(1,528		)	(2,595		)	902
Equity in earnings of unconsolidated subsidiaries (net of tax)	286			277			—
Net income (loss)	(1,913		)	(2,812		)	344

See Notes to Financial Statements.

235

ENERGY FUTURE HOLDINGS CORP. (PARENT) SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF CASH FLOWS (Millions of Dollars)
	Year Ended December 31,
	2011			2010			2009
Cash flows — operating activities
Net income (loss)	$	(1,913	)	$	(2,812	)	$	344
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Equity in (earnings) losses of subsidiaries	1,528			2,595			(902		)
Equity in (earnings) losses of unconsolidated subsidiaries	(286		)	(277		)	—
Deferred income tax expense (benefit) — net	(218		)	(56		)	(13		)
Interest expense on toggle notes payable in additional principal	361			333			317
Impairment of investment in long-term debt of affiliates	53			40			—
Amortization of debt related costs	52			74			86
Debt extinguishment gains	(3		)	(133		)	(46		)
Other, net	9			7			4
Changes in operating assets and liabilities:
Dividends received from subsidiaries	—			2			216
Other – net assets	—			328			(31		)
Other – net liabilities	(50		)	67			(17		)
Cash provided by (used in) operating activities	$	(467	)	$	168		$	(42	)
Cash flows — financing activities
Issuances of long-term debt	$	—		$	500		$	—
Repayments/repurchases of long-term debt	(5		)	(96		)	(4		)
Repayment of note — affiliate	—			770			—
Change in notes/advances — affiliate	(292		)	(785		)	425
Other, net	(16		)	(28		)	5
Cash provided by (used in) financing activities	$	(313	)	$	361		$	426
Cash flows — investing activities
Capital contribution to subsidiary	—			(440		)	—
Investment in affiliate debt	(15		)	(105		)	—
Investment (posted with) redeemed from derivative counterparty	—			400			(400		)
Other, net	11			—			—
Cash used in investing activities	$	(4	)	$	(145	)	$	(400	)
Net change in cash and cash equivalents	(784		)	384			(16		)
Cash and cash equivalents — beginning balance	1,443			1,059			1,075
Cash and cash equivalents — ending balance	$	659		$	1,443		$	1,059

See Notes to Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. (PARENT) SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEETS (Millions of Dollars)
	December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	659		$	1,443
Trade accounts receivable — net	13			12
Income taxes receivable — net	37			47
Accounts receivable from affiliates	33			26
Notes receivable from affiliates	182			165
Commodity and other derivative contractual assets	142			92
Other current assets	3			2
Total current assets	1,069			1,787
Receivables from unconsolidated subsidiary	1,235			1,463
Investment in long-term debt of subsidiaries	115			152
Other investments	1,465			2,772
Income taxes receivable from affiliate	119			—
Notes receivable from affiliates	12			12
Accumulated deferred income taxes	902			714
Other noncurrent assets, principally unamortized issuance costs	77			95
Total assets	$	4,994		$	6,995
LIABILITIES AND EQUITY
Current liabilities:
Notes/advances from affiliates	$	263		$	211
Trade accounts payable	1			1
Payables to affiliates/unconsolidated subsidiary	1,592			1,921
Commodity and other derivative contractual liabilities	166			119
Accumulated deferred income taxes	3			12
Accrued interest	171			165
Other current liabilities	5			3
Total current liabilities	2,201			2,432
Notes or other liabilities due affiliates/unconsolidated subsidiary	1,282			1,282
Long-term debt, less amounts due currently	7,619			7,286
Other noncurrent liabilities and deferred credits	1,744			1,985
Total liabilities	12,846			12,985
Shareholders' equity	(7,852		)	(5,990		)
Total liabilities and equity	$	4,994		$	6,995

See Notes to Financial Statements.

237

ENERGY FUTURE HOLDINGS CORP. (PARENT)

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

The accompanying unconsolidated condensed balance sheets, statements of income (loss) and cash flows present results of operations and cash flows of EFH Corp. (Parent). Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the financial statements and related notes of Energy Future Holdings Corp. and Subsidiaries included in Item 8 of this Annual Report on Form 10-K. EFH Corp.'s subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

2. INVESTMENT IN LONG-TERM DEBT OF SUBSIDIARIES

As a result of debt exchanges and purchases in 2009, 2010 and 2011, EFH Corp. (Parent) holds debt securities of TCEH with carrying values totaling $115 million and $152 million as of December 31, 2011 and 2010, respectively, reported as investment in long-term debt of subsidiaries.

As of December 31, 2011 and 2010, all of these debt securities are classified as available-for-sale. In accordance with accounting guidance for investments classified as available-for-sale, as of December 31, 2011 the securities are recorded at fair value and unrealized gains or losses are recorded in other comprehensive income unless such losses are other than temporary, in which case they are reported as impairments. The principal amounts, coupon rates, maturities and carrying value are as follows:

	December 31, 2011				December 31, 2010
	Principal Amount		Carrying Value (a)		Principal Amount		Carrying Value (a)
Available-for-sale securities:
TCEH 3.776% Term Loan Facilities maturing October 10, 2014 (b)	$	—	$	—	$	20	$	16
TCEH 4.776% Term Loan Facilities maturing October 10, 2017 (b)	19		16		—		—
TCEH 10.25% Fixed Senior Notes due November 1, 2015 (both periods include $102 million of Series B Notes)	284		99		244		136
Total available-for-sale securities	$	303	$	115	$	264	$	152

_____________

(a) Carrying value equals fair value.

(b) Interest rates in effect as of December 31, 2011.

Impairments - In 2011, we deemed the declines in values of TCEH securities were other than temporary and recorded a $53 million impairment recorded as a reduction of interest income. We considered that the securities were in a loss position for more than 12 months and that declines in natural gas prices and other corresponding effects on the profitability and cash flows of TCEH (which has below investment grade credit ratings) were unlikely to reverse in the near term. In 2010, we recorded a $40 million impairment of TCEH securities. As a result of the impairments, no cumulative unrealized losses were recorded in accumulated other comprehensive income as of December 31, 2011 and 2010.

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Interest income recorded on these investments was as follows:

	Year Ended December 31,
	2011			2010
Held-to-maturity securities:
Interest received/accrued	$	—		$	18
PIK interest received related TCEH toggle notes	—			4
Accretion of purchase discount	—			11
Total interest income related to held-to-maturity securities	—			33
Available-for-sale securities:
Interest received/accrued	26			—
Accretion of purchase discount	2			—
Impairments related to issuer credit	(53		)	(40		)
Total interest income related to available-for-sale securities	(25		)	(40		)
Total interest income	$	(25	)	$	(7	)

N9030 [I] We determine value under the fair value hierarchy established in accounting standards. Under the fair value hierarchy, 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. The fair value of our investment in long-term debt of subsidiaries is estimated at the lesser of either the call price or the market value as determined by broker quotes and quoted market prices for similar securities in active markets. For the periods presented, the fair values of our investment in long-term debt of subsidiaries represent Level 2 valuations.

3. GUARANTEES

As discussed below, EFH Corp. (Parent) has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions.

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

Indebtedness guarantee—In 1990, EFCHrepurchased an electric co-op's minority ownership interest in the Comanche Peak nuclear generation plant and assumed the co-op's indebtedness to the US government for the facilities. EFCH is making principal and interest payments to the co-op in an amount sufficient for the co-op to make payments on its indebtedness. EFCH guaranteed the co-op's payments, and in the event that the co-op fails to make its payments on the indebtedness, the US government would assume the co-op's rights under the agreement, and such payments would then be owed directly by EFCH. At December 31, 2011, the balance of the indebtedness on EFCH's balance sheet was $84 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities. EFH Corp. (Parent) has guaranteed EFCH's obligation under this agreement.

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4. DIVIDEND RESTRICTIONS

The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our common stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or on a pro forma basis, after giving effect to such distribution, EFH Corp. (Parent)'s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total debt (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. EFH Corp. (Parent)'s consolidated leverage ratio was 9.7 to 1.0 as of December 31, 2011.

In addition, the indentures governing the EFIH Notes generally restrict EFIH from making any cash distribution to EFH Corp. for the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend, EFIH's consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indentures governing the EFIH Notes, the term "consolidated leverage ratio" is defined as the ratio of EFIH's consolidated total debt (as defined in the indentures) to EFIH's Adjusted EBITDA on a consolidated basis (including Oncor's Adjusted EBITDA). EFIH's consolidated leverage ratio was 5.3 to 1.0 as of December 31, 2011.

The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. As of December 31, 2011, the ratio was 8.7 to 1.0.

In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes, TCEH Senior Secured Notes and TCEH Senior Secured Second Lien Notes generally restrict TCEH's ability to make distributions or loans to any of its parent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and the indentures governing such notes. See discussion in Note 10 regarding amendments to the TCEH Senior Secured Facilities affecting intercompany loans from TCEH to EFH Corp.

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

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

EFH Corp. (Parent) did not receive any dividends from its consolidated subsidiaries in the year ended December 31, 2011. EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $2 million and $216 million for the years ended December 31, 2010 and 2009, respectively.

5. SUPPLEMENTAL CASH FLOW INFORMATION

	Year Ended December 31,
	2011			2010			2009
Cash payments (receipts) related to:
Interest paid	$	1,097		$	1,022		$	958
Income taxes	(91		)	(4		)	32
Noncash investing and financing activities:
Debt exchange transactions	12			200			46
Principal amount of toggle notes issued in lieu of cash	355			324			309

____________

(a) Represents end-of-period accruals.

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(b) Oncor Holdings Financial Statements are presented pursuant to Rules 3–09 and 3–16 of Regulation S-X as Exhibit 99(e).

(c) Exhibits:

EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2011

Exhibits	Previously Filed* With File Number	As Exhibit
(2)	Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2(a)	1-12833 Form 8-K (filed February 26, 2007)	2.1	—	Agreement and Plan of Merger, dated February 25, 2007, by and among Energy Future Holdings Corp. (formerly known as TXU Corp.), Texas Energy Future Holdings Limited Partnership and Texas Energy Future Merger Sub Corp.
(3(i))	Articles of Incorporation
3(a)	1-12833 Form 8-K (filed October 11, 2007)	3.1	—	Restated Certificate of Formation of Energy Future Holdings Corp.
(3(ii))	By-laws
3(b)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	3(a)	—	Amended and Restated Bylaws of Energy Future Holdings Corp.
(4)	Instruments Defining the Rights of Security Holders, Including Indentures**
	Energy Future Holdings Corp.
4(a)	1-12833 Form 10-K (2007) (filed March 31, 2008)	4(c)	—	Indenture (For Unsecured Debt Securities Series P), dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee.
4(b)	1-12833 Form 8-K (filed July 7, 2010)	99.1	—	Supplemental Indenture, dated July 1, 2010, to Indenture (For Unsecured Debt Securities Series P), dated November 1, 2004.
4(c)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(q)	—	Officers’ Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 5.55% Series P Senior Notes due 2014.
4(d)	1-12833 Form 10-K (2010) (filed February 18, 2011)	4(d)	—	Indenture (For Unsecured Debt Securities Series Q), dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee. Energy Future Holdings Corp.’s Indentures for its Series R Senior Notes are not filed as it is substantially similar to this Indenture.
4(e)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(r)	—	Officer’s Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 6.50% Series Q Senior Notes due 2024.
4(f)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(s)	—	Officer’s Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 6.55% Series R Senior Notes due 2034.
4(g)	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(h)	1-12833 Form 10-K (2009) (filed February 19, 2010)	4(f)	—	Supplemental Indenture, dated July 8, 2008, to Indenture, dated October 31, 2007.
4(i)	1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009)	4(a)	—	Second Supplemental Indenture, dated August 3, 2009, to Indenture, dated October 31, 2007.

241

Exhibits	Previously Filed* With File Number	As Exhibit
4(j)	1-12833 Form 8-K (filed July 30, 2010)	99.1	—	Third Supplemental Indenture, dated July 29, 2010, to Indenture, dated October 31, 2007.
4(k)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	4(b)	—	Fourth Supplemental Indenture, dated October 18, 2011, to Indenture dated October 31, 2007.
4(l)	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(m)	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(n)	333-165860 Form S-3 (filed April 1, 2010)	4(j)	—	First Supplemental Indenture, dated March 16, 2010, to Indenture, dated January 12, 2010.
4(o)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(a)	—	Second Supplemental Indenture, dated April 13, 2010, to Indenture, dated January 12, 2010.
4(p)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(b)	—	Third Supplemental Indenture, dated April 14, 2010, to Indenture, dated January 12, 2010.
4(q)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(c)	—	Fourth Supplemental Indenture, dated May 21, 2010, to Indenture, dated January 12, 2010.
4(r)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(d)	—	Fifth Supplemental Indenture, dated July 2, 2010, to Indenture, dated January 12, 2010.
4(s)	1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010)	4(e)	—	Sixth Supplemental Indenture, dated July 6, 2010, to Indenture, dated January 12, 2010.
4(t)	333-171253 Form S-4 (filed January 24, 2011)	4(r)	—	Seventh Supplemental Indenture, dated July 7, 2010, to Indenture, dated January 12, 2010.
	Oncor Electric Delivery Company LLC
4(u)	333-100240 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as trustee.
4(v)	1-12833 Form 8-K (filed October 31, 2005)	10.1	—	Supplemental Indenture No. 1, dated October 25, 2005, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon.
4(w)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(b)	—	Supplemental Indenture No. 2, dated May 15, 2008, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon.

242

Exhibits	Previously Filed* With File Number	As Exhibit
4(x)	333-100240 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated May 6, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2012 and 7.000% Senior Notes due 2032.
4(y)	333-100242 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture (for Unsecured Debt Securities), dated August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as trustee.
4(z)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(c)	—	Supplemental Indenture No. 1, dated May 15, 2008, to Indenture and Deed of Trust, dated August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York.
4(aa)	333-100242 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated August 30, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5% Debentures due 2007 and 7% Debentures due 2022.
4(bb)	333-106894 Form S-4 (filed July 9, 2003)	4(c)	—	Officer’s Certificate, dated December 20, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2015 and 7.250% Senior Notes due 2023.
4(cc)	333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	4(a)	—	Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008, by Oncor Electric Delivery Company LLC, as grantor, to and for the benefit of, The Bank of New York Mellon Trust, as collateral agent and trustee.
4(dd)	333-100240 Form 10-K (2008) (filed March 2, 2009)	4(n)	—	First Amendment, dated March 2, 2009, to Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008.
4(ee)	333-100240 Form 8-K (filed September 3, 2010)	10.1	—	Second Amendment, dated September 3, 2010, to Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008.
4(ff)	333-100240 Form 8-K (filed November 15, 2011)	10.1	—	Third Amendment, dated November 10, 2011, to Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008.
4(gg)	333-100242 Form 8-K (filed September 9, 2008)	4.1	—	Officer’s Certificate, dated September 8, 2008, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038.
4(hh)	333-100240 Form 8-K (filed September 16, 2010)	4.1	—	Officer’s Certificate, dated September 13, 2010, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5.25% Senior Secured Notes due 2040.
4(ii)	333-100240 Form 8-K (filed October 12, 2010)	4.1	—	Officer's Certificate, dated October 8, 2010, establishing the form and certain terms of Oncor Electric Delivery Company LLC's 5.00% Senior Secured Notes due 2017 and 5.75% Senior Secured Notes due 2020.
4(jj)	333-100240 Form 8-K (filed November 23, 2011)	4.1	—	Officer's Certificate, dated November 23, 2011, establishing the terms of Oncor's 4.55% Senior Secured Notes due 2041.
4(kk)	333-100240 Form 8-K (filed November 23, 2011)	4.2	—	Registration Rights Agreement, dated November 23, 2011, among Oncor Electric Delivery Company LLC and the representatives of the initial purchasers of Oncor's 4.55% Senior Secured Notes due 2041.

243

Exhibits	Previously Filed* With File Number	As Exhibit
	Texas Competitive Electric Holdings Company LLC
4(ll)	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(mm)	1-12833 Form 8-K (filed December 12, 2007)	4.1	—	First Supplemental Indenture, dated December 6, 2007, to 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(nn)	1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009)	4(b)	—	Second Supplemental Indenture, dated August 3, 2009, to 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(oo)	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(pp)	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(qq)	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(rr)	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(ss)	1-12833 Form 8-K (filed October 8, 2010)	4.3	—	Second Lien Pledge Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as collateral agent for the benefit of the second lien secured parties.
4(tt)	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(uu)	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(vv)	1-12833 Form 10-K (2010) (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.

244

Exhibits	Previously Filed* With File Number	As Exhibit
4(ww)	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(xx)	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 Fling 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(yy)	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 dues 2020, as Beneficiary.
4(zz)	1-12833 Form 8-K (filed April 20, 2011)	4.4	—	Form of Subordination and Priority Agreement, among Citibank, N.A., as beneficiary under the First Lien Credit Deed of Trust, The Bank of New York Mellon Trust Company, N.A., as beneficiary under the Second Lien Indenture Deed of Trust, Citibank, N.A., as beneficiary under the First Lien Indenture Deed of Trust, Texas Competitive Electric Holdings Company LLC and the subsidiary guarantors party thereto.
	Energy Future Intermediate Holding Company LLC
4(aaa)	1-12833 Form 8-K (filed November 20, 2009)	4.2	—	Indenture, dated November 16, 2009, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.
4(bbb)	1-12833 Form 8-K (filed August 18, 2010)	4.1	—	Indenture, dated August 17, 2010, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020.
4(ccc)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	4(e)		Indenture, dated as of April 25, 2011, among Energy Future Intermediate Holding Company LLC, EFIH Finance, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 11% Senior Secured Second Lien Notes due 2021.
4(ddd)	1-12833 Form 8-K (filed February 6, 2012)	4.1		First Supplemental Indenture, dated February 6, 2012, to the Indenture dated April 25, 2011.
4(eee)	1-12833 Form 10-Q (Quarter ended March 31, 2011) (filed April 29, 2011)	4(f)		Junior Lien Pledge Agreement, dated as of April 25, 2011, from Energy Future Intermediate Holding Company LLC, as pledgor, to The Bank of New York Mellon Trust Company, N.A., as collateral trustee.
4(fff)	1-12833 Form 8-K (filed February 6, 2012)	4.2		Registration Rights Agreement, dated February 6, 2012, among Energy Future Intermediate Holding Company LLC, EFIH Finance, Inc., the initial purchasers and the guarantors named therein, relating to 11.75% Senior Secured Second Lien Notes due 2022.
(10)	Material Contracts
	Management Contracts; Compensatory Plans, Contracts and Arrangements
10(a)	1-12833 Form 8-K (filed May 23, 2005)	10.6	—	Energy Future Holdings Corp. Executive Change in Control Policy effective May 20, 2005.
10(b)	333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008)	10(p)	—	Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy, dated December 23, 2008.

245

Exhibits	Previously Filed* With File Number	As Exhibit
10(c)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(c)	—	Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy, dated December 20, 2010.
10(d)	1-12833 Form 8-K (filed May 23, 2005)	10.7	—	Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description.
10(e)	333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008)	10(n)	—	Amendment to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description, dated December 23, 2008.
10(f)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(f)	—	Amendment to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description, dated December 10, 2010.
10(g)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(a)	—	2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its affiliates.
10(h)	1-12833 Form 10-K (2009) (filed February 19, 2010)	10(ii)	—	Amendment No. 1 to the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates, dated July 14, 2009, effective as of December 23, 2008.
10(i)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(i)	—	EFH Executive Annual Incentive Plan, effective as of January 1, 2010.
10(j)	1-12833 Form 10-K (2008) (filed March 3, 2009)	10(q)	—	EFH Second Supplemental Retirement Plan, effective as of October 10, 2007.
10(k)	1-12833 Form 10-K (2009) (filed February 19, 2010)	10(ee)	—	Amendment to EFH Second Supplemental Retirement Plan, dated July 31, 2009.
10(l)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(l)	—	Second Amendment to EFH Second Supplemental Retirement Plan, dated April 9, 2010 with effect as of January 1, 2010.
10(m)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(m)	—	Third Amendment to EFH Second Supplemental Retirement Plan, dated April 21, 2010 with effect as of January 1, 2010.
10(n)			—	Fourth Amendment to EFH Second Supplemental Retirement Plan, dated June 17, 2011.
10(o)	1-12833 Form 10-K (2009) (filed February 19, 2010)	10(dd)	—	EFH Salary Deferral Program, effective January 1, 2010.
10(p)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(o)	—	Amendment to EFH Salary Deferral Program, effective January 20, 2011.
10(q)			—	Second Amendment to EFH Salary Deferral Program, dated June 17, 2011.
10(r)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(b)	—	Registration Rights Agreement, dated October 10, 2007, among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp. and the stockholders party thereto.
10(s)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(a)	—	Form of Stockholder’s Agreement (for Directors) among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto.

246

Exhibits	Previously Filed* With File Number	As Exhibit
10(t)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(b)	—	Form of Sale Participation Agreement (for Directors) between Texas Energy Future Holdings Limited Partnership and the stockholder party hereto.
10(u)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(f)	—	Form of Management Stockholder’s Agreement (For Executive Officers) among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto.
10(v)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(g)	—	Form of Sale Participation Agreement (For Executive Officers) between Texas Energy Future Holdings Limited Partnership and the stockholder party thereto.
10(w)	1-12833 Form 10-K (2009) (filed February 19, 2010)	10(m)	—	Form of Amended and Restated Non-Qualified Stock Option Agreement (For Executive Officers) between Energy Future Holdings Corp. and the optionee thereto.
10(x)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(i)	—	Form of Restricted Stock Unit Agreement between Energy Future Holdings Corp. and the stockholder party thereto.
10(y)			—	EFH Corp. Retention Award Plan (For Key Employees), effective December 20, 2011.
10(z)			—	Form of Participation Agreement (For Key Employees) between Energy Future Holdings Corp. and the participant party thereto.
10(aa)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(f)	—	Energy Future Holdings Corp. Non-Employee Director Compensation Arrangements.
10(bb)			—	Second Amended and Restated Consulting Agreement, dated January 1, 2012, between Energy Future Holdings Corp. and Donald L. Evans.
10(cc)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(a)	—	Amended and Restated Employment Agreement, dated October 17, 2011, between Energy Future Holdings Corp. and John Young.
10(dd)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(r)	—	Management Stockholder’s Agreement, dated February 1, 2008, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and John Young.
10(ee)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(s)	—	Sale Participation Agreement, dated February 1, 2008, between Texas Energy Future Holdings Limited Partnership and John F. Young.
10(ff)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(b)	—	Amended and Restated Employment Agreement, dated October 17, 2011, among EFH Corporate Services Company, Energy Future Holdings Corp. and Paul M. Keglevic.
10(gg)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(ee)	—	Deferred Share Agreement, dated July 1, 2008, between Energy Future Holdings Corp. and Paul Keglevic.
10(hh)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(h)	—	First Amendment to Deferred Share Agreement, dated October 17, 2011, between Energy Future Holdings Corp. and Paul Keglevic.

247

Exhibits	Previously Filed* With File Number	As Exhibit
10(ii)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(c)	—	Amended and Restated Employment Agreement, dated October 17, 2011, among Luminant Holding Company LLC, Energy Future Holdings Corp. and David A. Campbell.
10(jj)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(y)	—	Additional Payment Agreement, dated October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Texas Competitive Electric Holdings Company LLC and David Campbell.
10(kk)	1-12833 Form 10-K (2010) (filed February 18, 2011)	10(hh)	—	Deferred Share Agreement, dated May 20, 2008, between Energy Future Holdings Corp. and David Campbell.
10(ll)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(d)	—	Amended and Restated Employment Agreement, dated October 17, 2011, among TXU Retail Company LLC, Energy Future Holdings Corp. and James A. Burke.
10(mm)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ff)	—	Additional Payment Agreement, dated October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Texas Competitive Electric Holdings Company LLC and James Burke.
10(nn)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(nn)	—	Deferred Share Agreement, dated October 9, 2007, between Texas Energy Future Holdings Limited Partnership and James Burke.
10(oo)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(e)	—	Amended and Restated Employment Agreement, dated October 17, 2011, among Luminant Holding Company LLC, Energy Future Holdings Corp. and Mark Allen McFarland.
10(pp)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(f)	—	Amended and Restated Employment Agreement, dated October 17, 2011, among EFH Corporate Services Company, Energy Future Holdings Corp. and Richard J. Landy.
10(qq)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	10(g)	—	Employment Agreement, dated October 17, 2011, among EFH Corporate Services Company, Energy Future Holdings Corp., and John D. O'Brien, Jr.
	Credit Agreements and Related Agreements
10(rr)	333-100240 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007)	10(a)	—	$2,000,000,000 Revolving Credit Agreement, dated October 10, 2007, among Oncor Electric Delivery Company LLC, as the borrower; the several lenders from time to time parties thereto; JPMorgan Chase Bank, N.A., as administrative agent, fronting bank and swingline lender, Citibank, N.A., as syndication agent and fronting bank; Credit Suisse, Cayman Islands Branch, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc., Morgan Stanley Senior Funding, Inc., as co-documentation agents; J.P. Morgan Securities Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman Sachs Credit Partners L.P., Lehman Brothers Inc. and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and bookrunners.
10(ss)	333-176464 Form S-1 (filed August 24, 2011)	10(cc)	—	Amendment No. 1, dated as of August 4, 2011, to the $2,000,000,000 Revolving Credit Agreement.

248

Exhibits	Previously Filed* With File Number	As Exhibit
10(tt)	333-100240 Form 8-K (filed October 11, 2011)	10.1	—	Amended and Restated Revolving Credit Agreement, dated as of October 11, 2011, among Oncor Electric Delivery Company LLC, as borrower, the lenders listed therein, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., as swingline lender, and JPMorgan Chase Bank, N.A., Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America, N.A. and Citibank N.A., as fronting banks for letters of credit issued thereunder.
10(uu)	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(vv)	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(ww)	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(xx)	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(yy)	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(zz)	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(aaa)	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.
10(bbb)	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.

249

Exhibits	Previously Filed* With File Number	As Exhibit
10(ccc)	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(ddd)	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(eee)	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(fff)	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, a owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as lessor and EFH Properties Company, as Lessee (Energy Plaza Property).
10(ggg)	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(hhh)	333-100240 Form 10-K (2004) (filed March 23, 2005)	10(i)	—	Agreement, dated March 10, 2005, between Oncor Electric Delivery Company LLC and TXU Energy Company LLC, allocating to Oncor Electric Delivery Company LLC the pension and post-retirement benefit costs for all Oncor Electric Delivery Company LLC employees who had retired or had terminated employment as vested employees prior to January 1, 2002.
10(iii)	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(jjj)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(eee)	—	Stipulation as approved by the PUCT in Docket No. 34077.
10(kkk)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(fff)	—	Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077.
10(lll)	333-100240 Form 10-K (2010) (filed February 18, 2011)	10(ae)	—	PUCT Order on Rehearing in Docket No. 34077.
10(mmm)	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(nnn)	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(ooo)	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.

250

Exhibits	Previously Filed* With File Number	As Exhibit
10(ppp)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(vvv)	—	ISDA Master Agreement, dated October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International.
10(qqq)	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(rrr)	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(sss)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(yyy)	—	Management Agreement, dated October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., Goldman, Sachs & Co. and Lehman Brothers Inc.
10(ttt)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(cccc)	—	Indemnification Agreement, dated October 10, 2007, among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp., Kohlberg Kravis Roberts & Co., L.P., TPG Capital, L.P. and Goldman, Sachs & Co.
10(uuu)	333-100240 Form 8-K (filed August 13, 2008)	10.1	—	Contribution and Subscription Agreement, dated August 12, 2008, between Oncor Electric Delivery Company LLC and Texas Transmission Investment LLC.
10(vvv)	1-12833 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	10(g)	—	Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Holdings Company LLC, dated November 5, 2008.
10(www)	333-100240 Form 10-K (2008) (filed March 3, 2009)	3(c)	—	Amendment No. 1, dated February 18, 2009, to Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery LLC.
10(xxx)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	4(c)	—	Investor Rights Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(yyy)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	4(d)	—	Registration Rights Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(zzz)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	10(b)	—	Amended and Restated Tax Sharing Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Oncor Management Investment LLC, Texas Transmission Investment LLC, Energy Future Intermediate Holding Company LLC and Energy Future Holdings Corp.
(12)	Statement Regarding Computation of Ratios
12(a)			—	Computation of Ratio of Earnings to Fixed Charges.
(21)	Subsidiaries of the Registrant
21(a)			—	Subsidiaries of Energy Future Holdings Corp.
(23)	Consent of Experts
23(a)			—	Consent of Deloitte & Touche LLP, an independent registered public accounting firm, relating to the consolidated financial statements of Energy Future Holdings Corp.

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Exhibits	Previously Filed* With File Number	As Exhibit
23(b)			—	Consent of Deloitte & Touche LLP, an independent registered public accounting firm, relating to the consolidated financial statements of Oncor Electric Delivery Holdings Company LLC
31	Rule 13a - 14(a)/15d-14(a) Certifications
31(a)			—	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
32(a)			—	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)			—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(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.
99(b)			—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2011 and 2010.
99(c)			—	Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2011 and 2010.
99(d)			—	Energy Future Intermediate Holding Company LLC Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2011 and 2010.
99(e)			—	Oncor Electric Delivery Holdings Company LLC financial statements presented pursuant to Rules 3–09 and 3–16 of Regulation S–X.
	XBRL Data Files
101.INS			—	XBRL Instance Document
101.SCH			—	XBRL Taxonomy Extension Schema Document
101.CAL			—	XBRL Taxonomy Extension Calculation Document
101.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.

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SIGNATURES

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

		ENERGY FUTURE HOLDINGS CORP.
Date:	February 20, 2012	By	/s/ JOHN F. YOUNG
			(John F. Young, President and Chief Executive Officer)

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 Holdings Corp. and in the capacities and on the date indicated.

Signature	Title	Date
/s/ JOHN F. YOUNG	Principal Executive	February 20, 2012
(John F. Young, President and Chief Executive Officer)	Officer and Director
/s/ PAUL M. KEGLEVIC	Principal Financial Officer	February 20, 2012
(Paul M. Keglevic, Executive Vice President and Chief Financial Officer)
/s/ STANLEY J. SZLAUDERBACH	Principal Accounting Officer	February 20, 2012
(Stanley J. Szlauderbach, Senior Vice President and Controller)
/s/ DONALD L. EVANS	Director	February 20, 2012
(Donald L. Evans, Chairman of the Board)
/s/ ARCILIA C. ACOSTA	Director	February 20, 2012
(Arcilia C. Acosta)
/s/ DAVID BONDERMAN	Director	February 20, 2012
(David Bonderman)
/s/ THOMAS D. FERGUSON	Director	February 20, 2012
(Thomas D. Ferguson)
/s/ FREDERICK M. GOLTZ	Director	February 20, 2012
(Frederick M. Goltz)
/s/ JAMES R. HUFFINES	Director	February 20, 2012
(James R. Huffines)
/s/ SCOTT LEBOVITZ	Director	February 20, 2012
(Scott Lebovitz)
/s/ JEFFREY LIAW	Director	February 20, 2012
(Jeffrey Liaw)
/s/ MARC S. LIPSCHULTZ	Director	February 20, 2012
(Marc S. Lipschultz)

253

Signature	Title	Date
/s/ MICHAEL MACDOUGALL	Director	February 20, 2012
(Michael MacDougall)
/S/ KENNETH PONTARELLI	Director	February 20, 2012
(Kenneth Pontarelli)
/S/ WILLIAM K. REILLY	Director	February 20, 2012
(William K. Reilly)
/S/ JONATHAN D. SMIDT	Director	February 20, 2012
(Jonathan D. Smidt)
/S/ KNEELAND YOUNGBLOOD	Director	February 20, 2012
(Kneeland Youngblood)

254