Filed Pursuant to Rule 424(b)(3)
Registration Nos. 333-157057, 333-157057-01 to 333-157057-44

TEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY LLC

TCEH FINANCE, INC.

SUPPLEMENT NO. 7 TO

MARKET MAKING PROSPECTUS DATED APRIL 27, 2011

THE DATE OF THIS SUPPLEMENT IS FEBRUARY 23, 2012

On February 21, 2012, registrant parent guarantor, Energy Future Competitive Holdings Company, filed the attached Current Report on Form 10-K with the Securities and Exchange Commission.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

— OR—

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

Commission File Number 001-34543

Energy Future Competitive Holdings Company

(Exact name of registrant as specified in its charter)

Texas	75-1837355
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1601 Bryan Street Dallas, TX 75201-3411

(Address of principal executive offices)(Zip Code)

(214) 812-4600

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Name of Each Exchange on Which Registered
Guaranty of Energy Future Holdings Corp. 9.75% Senior Secured Notes due 2019	New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	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

Common Stock Outstanding as of February 20, 2012: 2,062,768 Class A shares, without par value and 39,192,594 Class B shares, without par value.

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

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

Glossary		ii
	PART I
Items 1. and 2. BUSINESS AND PROPERTIES		1
Item 1A.	RISK FACTORS	17
Item 1B.	UNRESOLVED STAFF COMMENTS	34
Item 3.	LEGAL PROCEEDINGS	35
Item 4.	MINE SAFETY DISCLOSURES	36
	PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	37
Item 6.	SELECTED FINANCIAL DATA	38
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	40
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	77
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	84
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	164
Item 9A.	CONTROLS AND PROCEDURES	164
Item 9B.	OTHER INFORMATION	167
	PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	167
Item 11.	EXECUTIVE COMPENSATION	167
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	167
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	167
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	168
	PART IV
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	170

Energy Future Competitive Holdings Company’s (EFCH) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the Energy Future Holdings Corp. (EFH Corp.) website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. EFCH also from time to time makes available to the public, free of charge, on the EFH Corp. website certain financial statements of its wholly-owned subsidiary, Texas Competitive Electric Holdings Company LLC. The information on EFH Corp.’s website shall not be deemed a part of, or incorporated by reference into, this annual report on Form 10-K. Readers should not rely on or assume the accuracy of any representation or warranty in any agreement that EFCH 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 EFCH and its subsidiaries occasionally make references to EFH Corp., EFCH (or “we”, “our”, “us” or “the company”), TCEH, TXU Energy or Luminant when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company’s financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the relevant parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

i

GLOSSARY

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

Adjusted EBITDA	Adjusted EBITDA means EBITDA adjusted to exclude noncash items, unusual items and other adjustments allowable under certain debt arrangements of TCEH and EFH Corp. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under US GAAP and, thus, are non-GAAP financial measures. We are providing TCEH’s and EFH Corp.’s Adjusted EBITDA in this Form 10-K (see reconciliations in Exhibits 99(b) and 99(c)) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in the debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with US GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
ancillary services	Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system.
CAIR	Clean Air Interstate Rule
CFTC	US Commodity Futures Trading Commission
CO2	carbon dioxide
CPNPC	Refers to Comanche Peak Nuclear Power Company LLC, which was formed by subsidiaries of TCEH (holding an 88% equity interest) and Mitsubishi Heavy Industries Ltd. (MHI) (holding a 12% equity interest) for the purpose of developing two new nuclear generation units and obtaining a combined operating license from the NRC for the units.
CSAPR	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.
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
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.
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act

iii

purchase accounting	The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
REP	retail electric provider
RRC	Railroad Commission of Texas, which among other things, has oversight of 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 Posting Facility. See Note 9 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.
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 EFCH and/or its subsidiaries, as apparent in the context. See “Glossary” on page iii for defined terms.

EFCH’s Business and Strategy

EFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company. We conduct our operations almost entirely through our wholly-owned subsidiary, TCEH. TCEH, 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. Key management activities, including commodity risk management and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis; consequently, there are no reportable business segments.

TCEH owns or leases 15,427 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. TCEH is also 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.

As of December 31, 2011, we had approximately 5,200 full-time employees, including approximately 2,150 employees under collective bargaining agreements.

EFCH’s Market

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

The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure adequacy and reliability of power supply across Texas’ main interconnected transmission grid. The ERCOT ISO is responsible for 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.

1

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.

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.

EFCH’s Strategies

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

Other elements of our strategies include:

• Increase value from existing business lines. 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.

2

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

• Pursuing generation development opportunities to help meet ERCOT’s growing electricity needs over the longer term from a diverse range of 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.

• Manage exposure to wholesale electricity price volatility. We actively manage our exposure to wholesale electricity prices in ERCOT through contracts for physical delivery of electricity, exchange traded and “over-the-counter” financial contracts, ERCOT “day-ahead market” transactions and bilateral contracts with other wholesale market participants, including other generators and end-use customers. These hedging activities include shorter-term agreements, longer-term electricity sales contracts and forward sales of natural gas.

• The historical relationship between natural gas prices and wholesale electricity prices in the ERCOT market has provided us an opportunity to manage a portion of our exposure to variability of wholesale electricity prices through a natural gas price hedging program. Under this program, TCEH has entered into market transactions involving natural gas-related financial instruments, and 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.

• 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, EFH Corp. initiated a liability management program focused on improving EFH Corp.’s and its competitive subsidiaries’ (including our) balance sheets. Accordingly, we and EFH Corp. expect to opportunistically look for ways to reduce the amount and extend the maturity of our outstanding debt. The program has resulted in our capture of $700 million of debt discount and the extension of $19.6 billion of debt maturities to 2017-2021. For EFH Corp., the program has resulted in the capture of $2.0 billion of debt discount (including the acquisition of $363 million principal amount of TCEH Senior Notes and $19 million principal amount of borrowings under the TCEH Senior Secured Facilities that are held as an investment by EFH Corp. or EFIH) and the extension of approximately $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 9 to Financial Statements for additional discussion of these transactions.

3

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.

Business Organization

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

Luminant — Luminant’s existing electricity generation fleet consists of 14 plants in Texas with total installed nameplate generating capacity as shown in the table below:

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

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

(b) Includes 1,655 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.

4

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.

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 15 to Financial Statements for discussion of the decommissioning trust fund.)

Nuclear insurance provisions are discussed in Note 10 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.

5

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.

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 business by optimally dispatching the generation fleet, sourcing all of TXU Energy’s electricity requirements and managing commodity price risk associated with retail and wholesale electricity sales and generation fuel requirements.

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

Luminant’s wholesale operations provide TXU Energy and other retail and wholesale customers with electricity-related services to meet their demands and the operating requirements of ERCOT. In consideration of electricity generation resource availability and consumer demand levels that can be highly variable, as well as opportunities to meet longer-term objectives of larger wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-term forward electricity purchase and sales agreements. Luminant is 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.

6

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 “EFCH’s Strategies”, designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, principally utilizing natural gas-related financial instruments.

The wholesale operations also dispatch Luminant’s available generation capacity. These dispatching activities 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.

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.

7

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.

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, 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. EFH Corp.’s Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, customers, economic development in Texas and technology/reliability standards. If, despite these efforts, a substantial number of our customers or others refuse to do business with us because of our GHG emissions, it could have a material effect on our results of operations, liquidity and financial condition.

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.

8

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.

9

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.

EFCH’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 — We 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;

• 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;

10

• 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.

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 (NO_x) that significantly contribute to other states failing to attain or maintain compliance with the EPA’s National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone. In 2008, the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) invalidated CAIR, but allowed the rule to continue until the EPA issued a final replacement rule. In 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 NO_x programs to address alleged downwind fine particulate matter effects.

11

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 NO_x emissions reduction programs, as well as the seasonal NO_x emissions reduction program. These programs require significant additional reductions of SO₂ and NO_x 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 NO_x 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 NO_x 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 NOx 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.

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 NO_x emissions—that allow for limited trading of allowances among sources covered by the programs. An allowance represents a ton of emissions of SO₂ or NO_x 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 NO_x 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.

12

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 3 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.

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.

13

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.

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 longstanding 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 10 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.

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.

14

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 10 to Financial Statements.)

Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits 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.

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.

15

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.

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.

16

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 and amounts held by affiliates) totaled $31.4 billion (see Note 9 to Financial Statements). As of December 31, 2011, EFCH guaranteed an additional $7.1 billion principal amount of debt of EFH Corp. not pushed down to its financial statements (including $4.4 billion held by EFIH and demand notes payable to TCEH totaling $1.592 billion). 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.

17

As of December 31, 2011, a substantial amount of our long-term debt matures in the next few years, including approximately $110 million principal amount of debt maturing in 2012-2013, approximately $3.9 billion principal amount of debt maturing in 2014 and approximately $3.7 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 $16.4 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.

18

Aspects of our current financial condition may also be challenging to our efforts to obtain additional financing (or refinance or extend our existing financing) in the future. For example, our liabilities exceed our assets as shown on our balance sheet prepared in accordance with US GAAP 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 9 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 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 9 to Financial Statements for a description of these covenants and other restrictions.

19

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

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 and adversely affect our ability to raise additional capital and/or refinance our existing debt.

Lenders or holders of our debt have in the past alleged, and might allege in the future, that we are not operating in compliance with the covenants in our debt agreements, that a default under our debt agreements has occurred or that our or our subsidiaries’ boards of directors or similar bodies or officers are not properly discharging their fiduciary duties, or make other allegations regarding our business, including for the purpose, and potentially having the effect, of causing a default under our debt or other agreements, accelerating the maturity of such debt, protecting claims of debt issued at a certain entity or entities in our capital structure at the expense of debt claims elsewhere in our capital structure and/or obtaining economic benefits from us. These claims have included 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. Further, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the past claimed, and may claim in the future, that a credit event has occurred under such credit derivative securities based on our financial condition. Even if these claims are without merit, they could nevertheless cause the trading price of our debt to decline and adversely affect our ability to raise additional capital and/or refinance our existing debt.

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

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

20

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.

Risks Related to Our Structure

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

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

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

EFH Corp. relies significantly on loans from TCEH to meet its obligations, and such reliance may intensify if EFH Corp. does not receive distributions from Oncor.

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, which are significant. The terms of the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities permit TCEH to make loans and/or dividends (to the extent permitted by applicable state law) to cover certain of EFH Corp.’s obligations, including principal and interest payments, working capital requirements and SG&A and corporate overhead costs and expenses. As of December 31, 2011, TCEH has notes receivable from EFH Corp. totaling $1.592 billion (see Note 18 to Financial Statements), and TCEH may make additional loans to EFH Corp. in the future.

21

The amendment to the TCEH Senior Secured Facilities that became effective in April 2011 contains certain provisions related to loans to EFH Corp. that are payable to TCEH on demand and 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 and, together with the P&I Note, the Intercompany Notes). TCEH agreed in the amendment:

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

• that borrowings outstanding under the P&I Note will not exceed $2 billion in the aggregate at any time; and

• that 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.

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

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

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.

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, recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations may have a material effect on our businesses.

22

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.

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.

23

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.

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 NOx emissions by approximately 120,600 tons (56 percent) and 9,000 tons (22 percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NOx 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.

24

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.

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.

25

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.

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.

26

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.

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.

27

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.

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.

28

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

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

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 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.

29

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.

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 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.

30

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 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. 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.

31

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.

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

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

Most of EFCH’s large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us. If EFCH’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 EFCH (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, which could impact 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 EFCH’s (and/or its subsidiaries’) creditworthiness or enterprise value;

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

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

32

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.

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

The values of the investments that fund EFH Corp.’s pension and OPEB plans are subject to changes in financial market conditions. Significant decreases in the values of these investments could increase the expenses of the pension plan and the costs of the OPEB plans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods. See Note 16 to Financial Statements for further discussion of EFH Corp.’s pension and OPEB plans.

As discussed in Note 4 to Financial Statements, goodwill and/or other intangible assets not subject to amortization that we have recorded in connection with the Merger are subject to at least annual impairment evaluations. As a result, 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.

33

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.

34

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.

35

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.

36

PART II

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

Not applicable. All of EFCH’s common stock is owned by EFH Corp.

See Note 11 to Financial Statements for a description of the restrictions on EFCH’s ability to pay dividends.

37

Item 6. SELECTED FINANCIAL DATA

EFCH 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,			Period from January 1, 2007 through October 10,
	2011			2010			2009			2008			2007			2007
Operating revenues	$	7,040		$	8,235		$	7,911		$	9,787		$	1,671		$	6,884
Impairment of goodwill	$	—		$	4,100		$	70		$	8,000		$	—		$	—
Net income (loss)	$	(1,802	)	$	(3,530	)	$	515		$	(9,039	)	$	(1,266	)	$	1,306
Net (income) loss attributable to noncontrolling interests	$	—		$	—		$	—		$	—		$	—		$	—
Net income (loss) attributable to EFCH	$	(1,802	)	$	(3,530	)	$	515		$	(9,039	)	$	(1,266	)	$	1,306
Ratio of earnings to fixed charges (a)		—			—			1.36			—			—			5.88
Cash provided by (used in) operating activities	$	1,236		$	1,257		$	1,384		$	1,657		$	(248	)	$	1,231
Cash provided by (used in) financing activities	$	(973	)	$	27		$	279		$	1,289		$	1,488		$	895
Cash used in investing activities	$	(190	)	$	(1,338	)	$	(2,048	)	$	(2,682	)	$	(1,881	)	$	(1,277	)
Capital expenditures, including nuclear fuel	$	662		$	902		$	1,521		$	2,074		$	519		$	1,585

EFCH AND SUBSIDIARIES

SELECTED CONSOLIDATED FINANCIAL DATA (CONTINUED)

(millions of dollars, except ratios)

	As of December 31,
	2011			2010			2009			2008			2007
Total assets	$	37,340		$	39,144		$	43,245		$	43,000		$	49,152
Property, plant & equipment — net	$	19,218		$	20,155		$	20,980		$	20,902		$	20,545
Goodwill and intangible assets	$	7,978		$	8,523		$	12,845		$	13,096		$	22,197
Capitalization
Long-term debt, less amounts due currently	$	30,458		$	29,474		$	32,121		$	31,556		$	30,762
EFCH shareholder’s equity		(7,819	)		(6,236	)		(4,266	)		(5,002	)		4,003
Noncontrolling interests in subsidiaries		103			87			48			—			—
Total	$	22,742		$	23,325		$	27,903		$	26,554		$	34,765
Capitalization ratios
Long-term debt, less amounts due currently		133.9	%		126.4	%		115.1	%		118.8	%		88.5	%
EFCH shareholder’s equity		(34.4	)%		(26.7	)%		(15.3	)%		(18.8	)%		11.5	%
Noncontrolling interests in subsidiaries		0.5	%		0.3	%		0.2	%		—	%		—	%
Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
Short-term borrowings	$	774		$	1,221		$	953		$	900		$	438
Long-term debt due currently	$	39		$	658		$	302		$	269		$	202

(a) Fixed charges exceeded earnings (see Exhibit 12(a)) by $859 million, $3.212 billion, $9.543 billion and $1.941 billion for the years ended December 31, 2011, 2010 and 2008 and for the period from October 11, 2007 through December 31, 2007, respectively.

38

Note: Although EFCH 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 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 8 to Financial Statements. Results for 2011 were significantly impacted by an impairment charge related to emissions allowance intangible assets as discussed in Note 3 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 4 to Financial Statements and debt extinguishment gains as discussed in Notes 7 and 9. Results for 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities.

See Notes to Financial Statements.

Quarterly Information (Unaudited)

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

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

	First Quarter			Second Quarter			Third Quarter (b)			Fourth Quarter
2010
Operating revenues	$	1,999		$	1,993		$	2,607		$	1,636
Net income (loss)	$	401		$	(458	)	$	(3,720	)	$	247
Net (income) loss attributable to noncontrolling interests	$	(1	)	$	1		$	—		$	—
Net income (loss) attributable to EFCH	$	400		$	(457	)	$	(3,720	)	$	247

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

(b) Net income (loss) and net income (loss) attributable to EFCH include the effect of a goodwill impairment charge (see Note 4 to Financial Statements).

39

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

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

Significant Activities and Events

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.

40

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		~150		~698
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.

41

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.

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). The write-off reflected the estimated effect of lower wholesale power prices on our enterprise value driven by the sustained decline in forward natural gas prices as discussed above. Our recorded goodwill totaled $6.2 billion as of December 31, 2011.

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

See Note 4 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, we had $31.4 billion principal amount of debt outstanding, including short-term borrowings and $704 million pushed down from EFH Corp. We and EFH Corp. have implemented a liability management program designed to reduce debt and extend debt maturities through debt exchanges, repurchases and extensions.

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 completed by EFCH in 2011 and 2010 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
TCEH 10.25% Notes due 2015		1,513		—
TCEH Toggle Notes due 2016		758		—
TCEH Senior Secured Facilities due 2013 and 2014		1,604		—
TCEH 15% Notes due 2021		—		1,221
TCEH 11.5% Notes due 2020 (a)		—		1,604
Cash paid, including use of proceeds from debt issuances in 2010 (b)		—		343
Total	$	3,875	$	3,168

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

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

Since inception, TCEH’s transactions in the liability management program resulted in the capture of approximately $700 million of debt discount and the extension of approximately $19.6 billion of debt maturities to 2017-2021. Also, see “Key Risks and Challenges – Substantial Leverage, Uncertain Financial Markets and Liquidity Risk” and Note 9 to Financial Statements.

42

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.

TCEH Interest 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, 3% 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.

43

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 9 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.

44

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 $31.4 billion as of December 31, 2011, and cash interest payments in 2011 totaled $2.5 billion.

Significant amounts of our long-term debt mature in the next few years, including approximate principal amounts of $110 million in 2012-2013, $3.9 billion in 2014 and $3.7 billion in 2015. A substantial amount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities. In April 2011, we secured an extension of the maturity date of approximately $16.4 billion 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 9 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 2010 and 2011, which resulted in the extension of approximately $19.6 billion of debt maturities to 2017-2021. 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 9 to Financial Statements.

45

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 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.

46

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.

		000,000.00		000,000.00		000,000.00		000,000.00		000,000.00
	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.

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 10 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.”

47

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,” 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 more than 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.

48

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 10 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.

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.

49

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	%

(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 support utilization of smart grid and advanced meter technology to implement ERCOT mandated rotating outages to noncritical customers. We continue to work with ERCOT and other market participants to develop policies and protocols that provide appropriate pricing signals that encourage the development of new generation to meet growing demand in the ERCOT market.

Cyber Security and Infrastructure Protection Risk

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

We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques. These groups include, but are not limited to: the US Cyber Emergency Response Team, the National Electric Sector Cyber Security Organization, the NRC and NERC. We also apply the knowledge gained by continuing to invest in technology, processes and services to detect, mitigate and protect our cyber assets. These investments include upgrades to network architecture, regular intrusion detection monitoring and compliance with emerging industry regulation.

50

APPLICATION OF CRITICAL ACCOUNTING POLICIES

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

Push Down of Merger-Related Debt

Merger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing as of the time of the Merger. Debt issued in exchange for Merger-related debt is considered Merger-related. Debt issuances are considered Merger-related debt to the extent the proceeds are used to repurchase Merger-related debt. Merger-related debt held by nonaffiliates that is fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH is subject to push down in accordance with SEC Staff Accounting Bulletin Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected in our financial statements. The amount reflected on our balance sheet represents 50% of the EFH Corp. Merger-related debt EFCH has guaranteed. This percentage reflects the fact that as of the time of the Merger, the equity investments of EFCH and EFIH in their respective operating subsidiaries were essentially equal amounts. Because payment of principal and interest on the notes is the responsibility of EFH Corp., we record the settlement of such amounts as noncash capital contributions from EFH Corp. See Note 9 to Financial Statements.

Impairment of Goodwill and Other Long-Lived Assets

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

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

51

The determination of enterprise value involves a number of assumptions and estimates. We use a combination of fair value inputs to estimate the enterprise value of our reporting unit: 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 unit. 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.

Since the Merger, we have recorded goodwill impairment charges totaling $12.170 billion; including $4.1 billion recorded in 2010 and $8.070 billion recorded largely in 2008. The total impairment charges represented aproximately 67% 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 EFCH, driven by the sustained decline in forward natural gas prices. The impairment in 2008 primarily arose from the dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies in the second half of 2008.

See Note 4 to Financial Statements for additional discussion.

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 12 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.

52

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.”

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.

		000000000			000000000			000000000
	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	)		(129	)
Total net gain (loss) recognized	$	(510	)	$	667		$	1,112
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			129
Total net gain recognized	$	19		$	59		$	109

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

		0000000000			0000000000
	December 31,
	2011			2010
Commodity contract assets	$	4,435		$	4,705
Commodity contract liabilities	$	(1,245	)	$	(1,608	)
Interest rate swap assets	$	—		$	6
Interest rate swap liabilities	$	(2,231	)	$	(1,425	)
Net accumulated other comprehensive loss included in shareholders’ equity (amounts after tax)	$	(49	)	$	(68	)

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

53

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.

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 12 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 equal to 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.

54

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 12 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. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the rights granted to the interest holders of the VIE to determine whether we have the right or obligation to absorb profit and loss from the VIE and the power to direct the significant activities of the VIE. See Note 2 to Financial Statements for information regarding our consolidated variable interest entities.

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 $468 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 retail operations, totaled $56 million, $108 million and $116 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. EFH Corp.’s income tax returns are regularly subject to examination by applicable tax authorities. In management’s opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination. See Notes 1, 5 and 6 for discussion of income tax matters.

55

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 4 to Financial Statements for additional information.

Defined Benefit Pension Plans and OPEB Plans

EFCH’s subsidiaries are participating employers in the pension plan sponsored by EFH Corp. and offer pension benefits to eligible employees based on a traditional defined benefit formula or a cash balance formula. Our subsidiaries also participate in health care and life insurance benefit plans offered by EFH Corp. to eligible employees and their eligible dependents upon the retirement of such employees from the 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 TCEH’s activities, related to their service prior to the deregulation and disaggregation of EFH Corp.’s business effective January 1, 2002. Accordingly, Oncor and TCEH entered into an agreement whereby Oncor assumed responsibility for applicable pension and OPEB costs related to those personnel. 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:

		$00000			$00000			$00000
	Year Ended December 31,
	2011			2010			2009
Pension costs	$	38		$	28		$	13
OPEB costs		14			11			9
Total benefit costs and net amounts recognized as expense	$	52		$	39		$	22
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 16 to Financial Statements regarding other disclosures related to pension and OPEB obligations.

56

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.

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.

57

Revenue and Commodity Hedging and Trading Activities

	Year Ended December 31,						2011			2010
	2011		2010		2009		% Change			% Change
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 contract 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.

58

Production, Purchased Power and Delivery Cost Data

	Year Ended December 31,									2011			2010
	2011			2010			2009			% Change			% Change
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		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 (c)	$	20.03		$	19.19		$	16.47			4.4			16.5
Natural gas fuel and purchased power (d)	$	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 (e)		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 (f)		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 (e):
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 depreciation and amortization of lignite mining assets (except for incremental depreciation due to the CSAPR as discussed in Note 3 to Financial Statements), which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.

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

(e) 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.

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

59

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.

60

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 $90 million, or 7%, to $1.470 billion in 2011. The increase reflected $44 million of accelerated depreciation in 2011 resulting from the revised estimated useful lives for mine assets due to the planned mine closures to comply with the CSAPR by January 1, 2012 (see Note 3 to Financial Statements for discussion of the effects of the CSAPR), $37 million in increased depreciation primarily related to lignite/coal-fueled generation facilities reflecting equipment additions and replacements and $36 million in incremental depreciation related to the new lignite-fueled generation unit discussed above. These increases were partially offset by $24 million in decreased amortization of intangible assets largely related to the retail customer relationship and reflecting expected customer attrition (see Note 4 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 4 to Financial Statements.

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

Other deductions totaled $524 million in 2011 and $18 million in 2010. Other deductions in 2011 resulting from the issuance of the CSAPR included a $418 million impairment charge for excess SO2 emissions allowances due to emissions allowance limitations under the CSAPR and a $9 million impairment of mining assets. Other deductions in 2011 also included $86 million in third party fees related to the amendment and extension of the TCEH Senior Secured Facilities. See Notes 3, 7 and 9 to Financial Statements.

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

Income tax benefit totaled $943 million on a pretax loss in 2011 compared to income tax expense totaling $318 million on pretax income in 2010, before the nondeductible goodwill impairment charge. The effective rate was 34.4% in 2011 and 35.8% in 2010, 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 declined $1.728 billion to $1.802 billion in 2011 reflecting the $4.1 billion goodwill impairment charge in 2010, partially offset in 2011 by lower gains from commodity hedging and trading activities, higher interest expense driven by unrealized mark-to-market net losses related to interest rate swaps, charges and expenses resulting from the issuance of the CSAPR and debt extinguishment gains in 2010.

61

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

62

	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

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 8 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 4 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 7 to Financial Statements.

Other deductions totaled $18 million in 2010 and $63 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 7 to Financial Statements.

Interest income increased $28 million, or 45%, to $90 million in 2010 reflecting higher notes receivable balances from affiliates.

Interest expense and related charges increased by $946 million, or 45%, to $3.067 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 $96 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges and $55 million in lower average borrowings.

63

Income tax expense totaled $318 million in 2010 compared to $351 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 35.8% and 37.5%, respectively. The decrease in the rate reflected lower interest accrued on uncertain tax positions in 2010.

Results decreased $4.045 billion in 2010 to a loss of $3.530 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.

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.

64

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 12 to Financial Statements for fair value disclosures and discussion of fair value measurements.

65

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 $21 million to $1.236 billion in 2011. The change included the effect of amended accounting standards related to the accounts receivable securitization program (see Note 8 to Financial Statements), under which the $383 million of funding under the program at the January 1, 2010 adoption was reported as a use of operating cash flows and a source of financing cash flows. Excluding this accounting effect, cash provided by operating activities declined $404 million. This decrease reflected lower cash earnings due to the low wholesale power price environment, lower generation and higher fuel and operating costs at our legacy generation facilities and an approximately $230 million increase in cash interest payments, partially offset by the contribution from the new lignite-fueled generation units (see Results of Operations). These effects were partially offset by a $408 million increase in net margin deposits received.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash provided by operating activities decreased $127 million to $1.257 billion in 2010. The decrease reflected a $350 million effect of the amended accounting standard related to the accounts receivable securitization program (see Note 8 to Financial Statements), under which the $383 million of funding under the program as of 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. The change in cash provided by operating activities also reflected improved working capital performance, particularly in retail accounts receivable due to the effects in 2009 of the implementation of a new customer information management system and more timely collections in 2010, as well as higher cash earnings driven by the contribution of the new generation units. These benefits were partially offset by an increase in cash interest payments net of capitalized interest and a decline in cash received as margin deposits.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $237 million, $276 million and $381 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 $973 million in 2011 compared to cash provided by financing activities of $27 million in 2010. Activity in 2011 reflected the amendment and extension of the TCEH Senior Secured Facilities, including approximately $800 million in transaction costs, and repayment of certain debt securities, including $415 million of pollution control revenue bonds, as discussed in Note 9 to Financial Statements. Activity in 2010 reflected a $96 million source of financing cash flows, reflecting a $383 million effect of an accounting change related to the accounts receivable securitization program as discussed above, net of a $287 million reduction of borrowings under the program.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash provided by financing activities totaled $27 million in 2010 compared to $279 million in 2009. The $252 million change was driven primarily by debt repurchases under our liability management program and repayments of debt at maturity, 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 9 to Financial Statements for further detail of short-term borrowings and long-term debt.

66

Investing Cash Flows

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

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

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

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

• $132 million for nuclear fuel purchases and

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

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 $1.338 billion and $2.048 billion in 2010 and 2009, respectively. Capital expenditures (excluding nuclear fuel purchases) totaled $796 million and $1.324 billion in 2010 and 2009, respectively. The $528 million decline in capital spending reflected a decrease in spending related to the construction of the now complete new generation facilities. The change in investing activities also reflected lower amounts loaned (in the form of a demand note) to EFH Corp.

Capital expenditures, including nuclear fuel, in 2010 totaled $902 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;

• $34 million related to nuclear generation development, and

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

67

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	$	(1,399	)
EFCH		—		(8	)
EFH Corp. (pushed down to EFCH)		49		(195	)
Total long-term		1,961		(1,602	)
Total short-term – TCEH (c)		—		(455	)
Total	$	1,961	$	(2,057	)

(a) Includes $209 million of noncash principal increases consisting of $162 million of TCEH Toggle Notes and $21 million of EFH Toggle Notes issued in payment of accrued interest as discussed below under “Toggle Notes Interest Election” and $26 million of new EFH Toggle Notes pushed down as a result of EFH Corp. debt exchanged as discussed in Note 9 to Financial Statements.

(b) Includes $195 million of noncash retirements as a result of EFH Corp. debt exchanged as discussed in Note 9 to Financial Statements.

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

See Note 9 to Financial Statements for further detail of long-term debt and other financing arrangements, including $39 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	$	120	$	47	$	73
TCEH Revolving Credit Facility (a)		1,384		1,440		(56	)
TCEH Letter of Credit Facility		169		261		(92	)
Total liquidity	$	1,673	$	1,748	$	(75	)

(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.

Available liquidity decreased $75 million in 2011 reflecting $1.236 billion in cash provided by operating activities, which included $540 million of margin deposits received from counterparties, receipt of net repayments of notes due from affiliates totaling $346 million, primarily related to demand notes due from EFH Corp., $843 million in financing related cash transaction costs, largely related to the April 2011 amendment and extension of the TCEH Senior Secured Facilities and $662 million in capital expenditures and nuclear fuel purchases. The net effect of other financing related cash activity was not material.

68

In February 2012, $650 million of the cash loaned by TCEH to EFH Corp. under demand notes was repaid by EFH Corp. bringing the balance of the demand notes to approximately $960 million (see Note 18 to Financial Statements.) TCEH used the $650 million it received from EFH Corp. to repay borrowings under the TCEH Revolving Credit Facility.

Secured Debt Capacity — As of February 15, 2012, EFCH believes that it and its subsidiaries 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:

• 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.

These amounts are estimates based on EFCH’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 EFCH and its subsidiaries. Consequently, the actual amount of senior secured debt that EFCH 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 $925 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

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

We expect cash flows from operations combined with availability under our credit facilities discussed in Note 9 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.

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. EFH Corp. and TCEH 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.

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 issued to EFH Corp., 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.

69

Similarly, 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), 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 9 to Financial Statements for further discussion of the EFH Corp. Toggle Notes, including debt exchange and repurchase transactions involving the notes.

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 9 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 19 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.

70

Income Tax Refunds/Payments — Income tax payments related to the Texas margin tax are expected to total approximately $35 million, and net refunds of federal income taxes from EFH Corp. are expected to total approximately $75 million in the next twelve months. Net payments totaled $123 million, $49 million and $27 million in the years ended December 31, 2011, 2010 and 2009, respectively.

As discussed in Note 5 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.

Interest Rate Swap Transactions — See Note 9 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 8 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.

Capitalization — Our capitalization ratios consisted of 133.9% and 126.4% long-term debt, less amounts due currently, and (33.9)% and (26.4)% common stock equity, as of December 31, 2011 and 2010, respectively. Total debt to capitalization, including short-term debt, was 132.8% and 124.4% 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 maintenance covenant contained in the TCEH Senior Secured Facilities) for the year ended December 31, 2011 totaled $3.584 billion for TCEH. See Exhibits 99(b) and 99(c) for a reconciliation of net income (loss) to Adjusted EBITDA for TCEH and EFH Corp., respectively, for the years ended December 31, 2011 and 2010.

The table below summarizes TCEH’s secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp. and TCEH that are applicable under certain other 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 and the EFH Corp. Senior Secured 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. or TCEH to incur certain permitted debt or make certain restricted payments and/or investments. EFCH and its consolidated subsidiaries are in compliance with their maintenance covenants.

71

	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
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 (c)	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 (c)	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
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

(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.

(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 9 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) 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.

72

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 EFCH and its subsidiaries, including the accounts receivable securitization program (see Note 8 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.

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 ($20.911 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.

73

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 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 of TCEH’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.

74

Long-Term Contractual Obligations and Commitments — The following table summarizes our contractual cash obligations as of December 31, 2011 (see Notes 9 and 10 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)	$	68	$	4,105	$	5,446	$	21,131	$	30,750
Long-term debt — interest (b)		2,615		5,209		4,166		3,680		15,670
Operating and capital leases (c)		58		95		81		228		462
Obligations under commodity purchase and services agreements (d)		939		1,228		728		929		3,824
Total contractual cash obligations	$	3,680	$	10,637	$	10,421	$	25,968	$	50,706

(a) Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting. Also excludes $101 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 18 to Financial Statements. More than five years period includes $704 million of EFH Corp. notes pushed down to EFCH (See Note 9 to Financial Statements.)

(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 a $225 million liability due to Oncor related to the nuclear plant decommissioning trust fund described in Note 18 to Financial Statements;

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

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

• employment contracts with management;

• payments to EFH Corp. related to pension and OPEB plans, and

• liabilities related to uncertain tax positions totaling $1.069 billion (excluding accrued interest of $151 million) discussed in Note 5 to Financial Statements as the ultimate timing of payment, if any, is not known.

Guarantees — See Note 10 to Financial Statements for details of guarantees.

OFF BALANCE SHEET ARRANGEMENTS

See Notes 2 and 10 to Financial Statements regarding VIEs and guarantees, respectively.

COMMITMENTS AND CONTINGENCIES

See Note 10 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.

75

REGULATORY MATTERS

See discussions in Part I under “Environmental Regulations and Related Considerations” and in Note 10 to Financial Statements.

Sunset Review

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.

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.

76

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Risk Oversight

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

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

Commodity Price Risk

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

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

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

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

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

77

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.

		$195		$195
	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.

78

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 9 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 9 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)	$	27		$	84		$	43		$	3,505		$	1,583		$	4,882		$	10,124		$	5,574	$	8,797			$	5,879
Average interest rate		8.00	%		7.11	%		6.36	%		10.24	%		11.23	%		11.68	%		11.04	%				10.71	%
Variable rate debt amount	$	—		$	—		$	3,890		$	154		$	154		$	16,249		$	20,447		$	13,166	$	21,403			$	16,558
Average interest rate		—	%		—	%		3.79	%		4.78	%		4.78	%		4.72	%		4.54	%				3.73	%
Total debt	$	27		$	84		$	3,933		$	3,659		$	1,737		$	21,131		$	30,571		$	18,740	$	30,200			$	22,437
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 9 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 9 to Financial Statements.

79

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.

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 14 to Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

80

									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.

81

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;

• 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;

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

82

• 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.

83

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Energy Future Competitive Holdings Company (a subsidiary of Energy Future Holdings Corp.) and subsidiaries (“EFCH”) as of December 31, 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. These financial statements are the responsibility of EFCH’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Future Competitive Holdings Company and subsidiaries as of December 31, 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.

As discussed in note 18 to the consolidated financial statements, Texas Competitive Electric Holdings Company LLC has made loans, which are payable on demand, to its indirect parent, Energy Future Holdings Corp., with amounts outstanding as of December 31, 2011 and 2010 of $1.592 billion and $1.921 billion, respectively. Also, as discussed in notes 1 and 8 to the consolidated financial statements, EFCH 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), EFCH’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 EFCH’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Dallas, Texas

February 20, 2012

84

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Millions of Dollars)

	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		(1,470	)		(1,380	)		(1,172	)
Selling, general and administrative expenses		(728	)		(722	)		(741	)
Franchise and revenue-based taxes		(96	)		(106	)		(108	)
Impairment of goodwill (Note 4)		—			(4,100	)		(70	)
Other income (Note 7)		48			903			59
Other deductions (Note 7)		(524	)		(18	)		(63	)
Interest income		86			90			62
Interest expense and related charges (Note 19)		(3,792	)		(3,067	)		(2,121	)
Income (loss) before income taxes		(2,745	)		(3,212	)		866
Income tax (expense) benefit (Note 6)		943			(318	)		(351	)
Net income (loss)		(1,802	)		(3,530	)		515
Net (income) loss attributable to noncontrolling interests		—			—			—
Net income (loss) attributable to EFCH	$	(1,802	)	$	(3,530	)	$	515

See Notes to Financial Statements.

85

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Millions of Dollars)

	Year Ended December 31,
	2011			2010			2009
Net income (loss)	$	(1,802	)	$	(3,530	)	$	515
Other comprehensive income, net of tax effects:
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			129
Total other comprehensive income		19			59			109
Comprehensive income (loss)		(1,783	)		(3,471	)		624
Comprehensive (income) loss attributable to noncontrolling interests		—			—			—
Comprehensive income (loss) attributable to EFCH	$	(1,783	)	$	(3,471	)	$	624

See Notes to Financial Statements.

86

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

	Year Ended December 31,
	2011			2010			2009
Cash flows — operating activities
Net income (loss)	$	(1,802	)	$	(3,530	)	$	515
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization		1,707			1,656			1,553
Deferred income tax expense (benefit) — net		(1,116	)		534			324
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 9)		812			207			(696	)
Amortization of debt related costs, discounts, fair value discount sand losses on dedesignated cash flow hedges (Note 19)		227			226			324
Accretion expense related to asset retirement and mining reclamation obligations		48			57			59
Impairment of goodwill (Note 4)		—			4,100			70
Impairment of emission allowances intangible assets (Note 3)		418			—			—
Debt extinguishment gains (Note 9)		—			(687	)		—
Effect of Parent’s payment of interest on pushed-down debt		81			231			265
Interest expense on toggle notes payable in additional principal (Notes 9 and 19)		166			217			207
Gain on termination of long-term power sales contract (Note 7)		—			(116	)		—
Bad debt expense (Note 8)		56			108			116
Third party fees related to debt amendment and extension transactions (reported as financing) (Note 9)		86			—			—
Net gain on sale of assets		(2	)		(81	)		(5	)
Stock-based incentive compensation expense		5			7			4
Net equity loss from unconsolidated affiliate		4			5			7
Reversal of reserves recorded in purchase accounting (Note 7)		—			—			(34	)
Impairment of land		—			—			34
Impairment of assets related to mining operations (Note 3)		9			—			—
Other — net		2			13			2
Changes in operating assets and liabilities:
Affiliate accounts receivable/payable — net		(4	)		5			45
Accounts receivable — trade		175			258			(104	)
Impact of accounts receivable securitization program (Note 8)		—			(383	)		(33	)
Inventories		(23	)		(6	)		(32	)
Accounts payable — trade		(126	)		(149	)		(141	)
Commodity and other derivative contractual assets and liabilities		(33	)		(44	)		(64	)
Margin deposits — net		540			132			248
Other — net assets		(27	)		20			(4	)
Other — net liabilities		91			(302	)		(51	)
Cash provided by operating activities	$	1,236		$	1,257		$	1,384

87

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

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 9)		1,750			353			522
Repayments/repurchases of long-term debt/securities (Note 9)		(1,408	)		(647	)		(279	)
Net short-term borrowings under accounts receivable securitization program (Note 8)		8			96			—
Increase (decrease) in other short-term borrowings (Note 9)		(455	)		172			53
Notes due to affiliates		—			34			—
Decrease in income tax-related note payable to Oncor		(39	)		(37	)		(35	)
Contributions from noncontrolling interests		16			32			48
Debt amendment, exchange and issuance costs and discounts, including third party fees expensed		(843	)		(13	)		(35	)
Other, net		(2	)		37			5
Cash provided by (used in) financing activities	$	(973	)	$	27		$	279
Cash flows — investing activities
Notes due from affiliates	$	346		$	(503	)	$	(822	)
Capital expenditures		(530	)		(796	)		(1,324	)
Nuclear fuel purchases		(132	)		(106	)		(197	)
Reduction of restricted cash related to letter of credit facility (Note 19)		188			—			115
Other changes in restricted cash		(96	)		(33	)		3
Proceeds from sales of assets		49			141			41
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	)
Money market fund redemptions		—			—			142
Other — net		9			(7	)		10
Cash used in investing activities	$	(190	)	$	(1,338	)	$	(2,048	)
Net change in cash and cash equivalents		73			(54	)		(385	)
Effect of consolidation of VIE		—			7			—
Cash and cash equivalents — beginning balance		47			94			479
Cash and cash equivalents — ending balance	$	120		$	47		$	94

See Notes to Financial Statements.

88

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

	December 31,
	2011		2010
ASSETS
Current assets:
Cash and cash equivalents (Note 1)	$	120	$	47
Restricted cash (Note 19)		129		33
Trade accounts receivable — net (includes $524 and $612 in pledged amounts related toa VIE (Notes 2 and 8))		760		991
Notes receivable from parent (Note 18)		670		1,921
Inventories (Note 19)		418		395
Commodity and other derivative contractual assets (Note 14)		2,883		2,640
Margin deposits related to commodity positions		56		166
Other current assets		59		37
Total current assets		5,095		6,230
Restricted cash (Note 19)		947		1,135
Notes receivable from parent (Note 18)		922		—
Investments (Note 15)		629		602
Property, plant and equipment — net (Note 19)		19,218		20,155
Goodwill (Note 4)		6,152		6,152
Identifiable intangible assets — net (Note 4)		1,826		2,371
Commodity and other derivative contractual assets (Note 14)		1,552		2,071
Other noncurrent assets, principally unamortized debt amendment and issuance costs		999		428
Total assets	$	37,340	$	39,144
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (includes $104 and $96 related to a VIE (Notes 2 and 9))	$	774	$	1,221
Advances from parent		7	$	—
Long-term debt due currently (Note 9)		39		658
Trade accounts payable		553		669
Trade accounts and other payables to affiliates		209		210
Notes payable to parent (Note 18)		57		46
Commodity and other derivative contractual liabilities (Note 14)		1,784		2,164
Margin deposits related to commodity positions		1,061		631
Accrued income taxes payable to parent (Note 18)		74		21
Accumulated deferred income taxes (Note 6)		53		4
Accrued taxes other than income		136		130
Accrued interest		394		326
Other current liabilities		266		250
Total current liabilities		5,407		6,330
Accumulated deferred income taxes (Note 6)		4,712		6,000
Commodity and other derivative contractual liabilities (Note 14)		1,692		869
Notes or other liabilities due affiliates (Note 18)		363		384
Long-term debt held by affiliates (Note 18)		382		343
Long-term debt, less amounts due currently (Note 9)		30,076		29,131
Other noncurrent liabilities and deferred credits (Note 19)		2,424		2,236
Total liabilities		45,056		45,293

89

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

	December 31,
	2011			2010
Commitments and Contingencies (Note 10)
Equity (Note 11):
Class A common stock (shares outstanding 2011 and 2010 — 2,062,768)		368			358
Class B common stock (shares outstanding 2011 and 2010 — 39,192,594)		6,983			6,793
Retained earnings		(15,121	)		(13,319	)
Accumulated other comprehensive loss, net of tax effect		(49	)		(68	)
EFCH shareholder’s equity		(7,819	)		(6,236	)
Noncontrolling interests in subsidiaries		103			87
Total equity		(7,716	)		(6,149	)
Total liabilities and equity	$	37,340		$	39,144

See Notes to Financial Statements.

90

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

STATEMENTS OF CONSOLIDATED EQUITY

(Millions of Dollars)

	Year Ended December 31,
	2011			2010			2009
Preferred stock — not subject to mandatory redemption:
Balance as of beginning of period	$	—		$	—		$	1
Redemption of preferred stock		—			—			(1	)
Balance as of end of period		—			—			—
Class A common stock without par value — authorized shares — 9,000,000:
Balance as of beginning of period		358			283			277
Effects of debt push-down from EFH Corp. (Note 9)		10			75			6
Balance as of end of period (shares outstanding for all periods presented — 2,062,768)		368			358			283
Class B common stock without par value — authorized shares — 171,000,000:
Balance as of beginning of period		6,793			5,368			5,261
Effects of debt push-down from EFH Corp. (Note 9)		184			1,417			101
Effects of stock-based incentive compensation plans		6			8			5
Other		—			—			1
Balance as of end of period (shares outstanding for all periods presented — 39,192,594)		6,983			6,793			5,368
Retained earnings:
Balance as of beginning of period		(13,319	)		(9,790	)		(10,305	)
Net income (loss) attributable to EFCH		(1,802	)		(3,530	)		515
Other		—			1			—
Balance as of end of period		(15,121	)		(13,319	)		(9,790	)
Accumulated other comprehensive loss, net of tax effects (a):
Balance as of beginning of period		(68	)		(127	)		(236	)
Change during the period		19			59			109
Balance as of end of period		(49	)		(68	)		(127	)
EFCH shareholder’s equity as of end of period		(7,819	)		(6,236	)		(4,266	)
Noncontrolling interests in subsidiaries (Note 11):
Balance as of beginning of period		87			48			—
Net income (loss) attributable to noncontrolling interests		—			—			—
Effect of consolidation of TXU Receivables Company		—			7			—
Investment in subsidiary by noncontrolling interests		16			32			48
Noncontrolling interests in subsidiaries as of end of period		103			87			48
Total equity as of end of period	$	(7,716	)	$	(6,149	)	$	(4,218	)

(a) All amounts relate to cash flow hedges.

See Notes to Financial Statements.

91

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

References in this report to “we,” “our,” “us” and “the company” are to EFCH and/or its subsidiaries, as apparent in the context. See “Glossary” for defined terms.

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

TCEH operates largely in the ERCOT market, and wholesale electricity prices in that market have 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.

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 EFCH’s Annual Report on Form 10-K for the year ended December 31, 2010. See Note 8 for discussion of the prospective adoption, effective January 1, 2010, of amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program reported as short-term borrowings and the prospective adoption of amended guidance that requires reconsideration of consolidation conclusions for all variable interest entities (VIEs) that resulted in the consolidation, effective January 1, 2010 of TXU Receivables Company. All intercompany items and transactions have been eliminated in consolidation. 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.

92

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 12 and 14 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the “normal” purchase and sale exemption. A commodity-related derivative contract may be designated as a “normal” purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.

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

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

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 9).

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.

93

Revenue Recognition

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

We report physically delivered commodity sales and purchases in the income statement on a gross basis in revenues and fuel, purchased power and delivery fees, respectively, and we report all other commodity related contracts and financial instruments (primarily derivatives) in the income statement on a net basis in net gain (loss) from commodity hedging and trading activities. As part of ERCOT’s transition to a nodal wholesale market effective December 1, 2010, volumes under nontrading bilateral purchase and sales contracts, including contracts intended as hedges, are no longer scheduled as physical power with ERCOT. Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, effective with the nodal market implementation, such contracts are reported net in the income statement in net gain (loss) from commodity hedging and trading activities instead of reported gross as wholesale revenues or purchased power costs. As a result of the changes in wholesale market operations, effective with the nodal market implementation, if volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues, and if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record additional purchased power costs. The additional wholesale revenues or purchased power costs are offset in net gain (loss) from commodity hedging and trading activities.

Impairment of Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 3 for discussion of impairments of emission allowances intangible assets and mining-related assets in 2011.

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

Goodwill and Intangible Assets with Indefinite Lives

We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually (as of December 1). See Note 4 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations and goodwill impairments recorded in 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 bear a portion of the costs of the EFH Corp. sponsored pension and OPEB plans offering pension benefits based on either a traditional defined benefit formula or a cash balance formula to eligible employees and also offering certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. Under multiemployer plan accounting, EFH Corp. has elected to not allocate retirement plan assets and liabilities to us. See Note 16 for additional information regarding pension and OPEB plans.

94

Stock-Based Incentive Compensation

EFH Corp.’s 2007 Stock Incentive Plan authorizes discretionary grants to directors, officers and qualified managerial employees of EFH Corp. or its affiliates of non-qualified stock options, stock appreciation rights, restricted shares, shares of common stock, the opportunity to purchase shares of common stock and other stock-based awards. Stock-based compensation expense is recognized over the vesting period based on the grant-date fair value of those awards. Restricted shares have been (and stock options previously were) granted to certain of our employees under the plan. See Note 17 for information regarding stock-based incentive compensation.

Sales and Excise Taxes

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

Franchise and Revenue-Based Taxes

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

Income Taxes

EFH Corp. files a consolidated federal income tax return; however, our income tax expense and related balance sheet amounts are recorded as if we file separate corporate income tax returns. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. 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 10 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 9 and 19 for more details regarding restricted cash.

Property, Plant and Equipment

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

Depreciation of our property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful lives. See Note 19.

95

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 19.

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 19.

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 3 for details of impairment amounts recorded in 2011.

Investments

Investments in a nuclear decommissioning trust fund are carried at current market value in the balance sheet. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 15 for discussion of these and other investments.

Noncontrolling Interests

See Note 11 for discussion of accounting for noncontrolling interests in subsidiaries.

Push-Down of EFH Corp. Debt

In accordance with SEC Staff Accounting Bulletin (SAB) Topic 5-J, we reflect amounts of certain EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes on our balance sheet and the related interest expense in our income statement. The amount reflected on our balance sheet was calculated based upon the relative equity investment of EFCH and EFIH in their respective operating subsidiaries at the time of the Merger (see Note 9).

96

2. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. 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.

Consolidated VIEs

See discussion in Note 8 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 because EFCH (as the owner of TXU Energy) is the primary beneficiary of TXU Receivables Company, which is owned and controlled by our parent, EFH Corp.

We also consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existing Comanche Peak nuclear-fueled generation facility using MHI’s US-Advanced Pressurized Water Reactor technology and to obtain a combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries of TCEH and MHI that hold 88% and 12% of CPNPC’s equity interests, respectively (see Note 11).

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

	December 31,
Assets:	2011		2010
Cash and cash equivalents	$	10	$	9
Accounts receivable		525		612
Property, plant and equipment		132		112
Other assets, including $2 million of current assets in both periods		6		8
Total assets	$	673	$	741

	December 31,
Liabilities:	2011		2010
Short-term borrowings	$	104		96
Trade accounts payable		1		3
Other current liabilities		9		1
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.

97

3. 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 12. 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 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.

98

4. 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. None of the goodwill is being deducted for tax purposes.

Goodwill before impairment charges	$	18,322
Accumulated impairment charges through 2009 (a)		(8,070	)
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 $70 million in 2009 and $8.0 billion in 2008.

(b) Net of accumulated impairment charges totaling $12.170 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 our carrying value likely exceeds our 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 we largely operate, 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.

• Our carrying value exceeded our 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.

• 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 3).

99

• 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. While our estimated enterprise value declined from previous estimates, the estimated fair values of our 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 our 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 3.

In the third quarter 2010, we recorded a $4.1 billion noncash goodwill impairment charge. The impairment charge reflected the estimated effect of lower wholesale power prices on our enterprise value, 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 $8.0 billion goodwill impairment charge that was recorded in the fourth quarter 2008. A $70 million increase in the charge 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 $8.070 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 12). Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

100

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		241		79		162		202		50		152
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	$	1,974	$	1,141		833	$	2,246	$	921		1,325
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization) (b)						38						91
Total intangible assets					$	1,826					$	2,371

(a) Amounts impaired have been removed from the table as of the impairment date (see Note 3).

(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:

Intangible Asset (Income Statement Line):	Useful lives as  of December 31, 2011 (weighted average in years)		Year Ended December 31, 2011		Year Ended December 31, 2010		Year Ended December 31, 2009
Retail customer relationship (Depreciation and amortization)		6	$	51	$	78	$	85
Favorable purchase and sales contracts (Operating revenues/fuel, purchased power costs and delivery fees)		11		31		35		125
Capitalized in-service software (Depreciation and amortization)		6		29		23		16
Environmental allowances and credits (Fuel, purchased power costs and delivery fees)		26		71		92		91
Mining development costs (Depreciation and amortization)		4		38		11		4
Total amortization expense			$	220	$	239	$	321

101

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 19).

• 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 3 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	$	132
2013	$	115
2014	$	99
2015	$	90
2016	$	74

102

5. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES

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

EFH Corp. and its subsidiaries file or have filed income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of income tax returns filed by EFH Corp. and any of its subsidiaries for the years ending prior to January 1, 2007 are complete, but the tax years 1997 to 2006 remain in appeals with the IRS. 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 $85 million with an offsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002.

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

We classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled an expense of $15 million in 2011, a benefit of $8 million in 2010 and an expense of $18 million in 2009 (all amounts after tax).

Noncurrent liabilities included a total of $151 million and $128 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:

		$000,000			$000,000			$000,000
	Year Ended December 31,
	2011			2010			2009
Balance as of January 1, excluding interest and penalties	$	931		$	903		$	787
Additions based on tax positions related to prior years		80			26			59
Reductions based on tax positions related to prior years		(6	)		(70	)		(10	)
Additions based on tax positions related to the current year		64			72			67
Balance as of December 31, excluding interest and penalties	$	1,069		$	931		$	903

Of the balance as of December 31, 2011, $1.0 billion represents tax positions for which the uncertainty relates to the timing of recognition in tax returns. The disallowance of such positions would not affect the effective tax rate, but could accelerate the payment of cash to the taxing authority to an earlier period.

With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should EFH Corp. sustain such positions on income tax returns previously filed, our liabilities recorded would be reduced by $69 million, and accrued interest would be reversed resulting in a $10 million after-tax benefit, resulting in increased net income and a favorable impact on the effective tax rate.

Other than the items discussed above, we do not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.

103

6. INCOME TAXES

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

	Year Ended December 31,
	2011			2010			2009
Current:
US Federal	$	125		$	(254	)	$	(9	)
State		48			39			36
Total current		173			(215	)		27
Deferred:
US Federal		(1,120	)		521			322
State		4			12			2
Total deferred		(1,116	)		533			324
Total	$	(943	)	$	318		$	351

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

		$000,000			$000,000			$000,000
	Year Ended December 31,
	2011			2010			2009
Income (loss) before income taxes	$	(2,745	)	$	(3,212	)	$	866
Income taxes at the US federal statutory rate of 35%		(961	)		(1,124	)		303
Texas margin tax, net of federal benefit		33			31			19
Lignite depletion allowance		(23	)		(21	)		(18	)
Production activities deduction		(20	)		—			(8	)
Interest accrued for uncertain tax positions, net of tax		15			(8	)		18
Nondeductible interest expense		14			9			9
Reversal of previously disallowed interest resulting from debt exchanges		(1	)		(13	)		—
Nondeductible goodwill impairment		—			1,435			25
Other, including audit settlements		—			9			3
Income tax expense (benefit)	$	(943	)	$	318		$	351
Effective tax rate		34.4	%		(9.9	)%		40.5	%

104

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						December 31, 2010
	Total		Current		Noncurrent		Total		Current		Noncurrent
Deferred Income Tax Assets
Alternative minimum tax credit carryforwards	$	231	$	—	$	231	$	328	$	—	$	328
Net operating loss carryforwards		76		—		76		211		—		211
Unfavorable purchase and sales contracts		231		—		231		240		—		240
Debt extinguishment gains		748				748		—		—		—
Employee benefit obligations		50		—		50		63		20		43
Accrued interest		184		—		184		129		—		129
Other		246		—		246		250		7		243
Total		1,766		—		1,766		1,221		27		1,194
Deferred Income Tax Liabilities
Property, plant and equipment		4,286		—		4,286		4,384		—		4,384
Commodity contracts and interest rate swaps		1,373		31		1,342		1,677		31		1,646
Employee benefit liabilities		17		17		—		—		—		—
Identifiable intangible assets		619		—		619		833		—		833
Debt fair value discounts		217		—		217		4		—		4
Debt extinguishment gains		—		—		—		313		—		313
Other		19		5		14		14		—		14
Total		6,531		53		6,478		7,225		31		7,194
Net Deferred Income Tax Liability	$	4,765	$	53	$	4,712	$	6,004	$	4	$	6,000

As of December 31, 2011, we had $231 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 $216 million that are expected to offset liabilities resulting from the IRS audit for the years 2003 to 2006. The decline in the net operating loss carryforward is due to current taxable income resulting from cancellation of debt income.

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 $26 million and $37 million, respectively.

See Note 5 for discussion regarding accounting for uncertain tax positions.

105

7. OTHER INCOME AND DEDUCTIONS

	Year Ended December 31,
	2011		2010		2009
Other income:
Settlement of counterparty bankruptcy claims (a)	$	21	$	—	$	—
Property damage claim		7		—		—
Franchise tax refund		6		—		—
Debt extinguishment gains (Note 9)		—		687		—
Gain on termination of long-term power sales contract (b)		—		116		—
Gain on sale of land/water rights		—		44		—
Gain on sale of interest in natural gas gathering pipeline business		—		37		—
Sales tax refunds		5		5		5
Insurance/litigation settlements		—		3		—
Mineral rights royalty income		3		1		6
Reversal of reserves recorded in purchase accounting (c)		—		—		34
Fee received related to interest rate swap/commodity hedge derivative agreement (Note 14)		—		—		6
Net gain on sale of other properties and investments		—		—		4
Other		6		10		4
Total other income	$	48	$	903	$	59
Other deductions:
Impairment of emission allowances (Note 3)	$	418	$	—	$	—
Severance charges related to facility closures		—		3		7
Impairment of assets related to mining operations (Note 3)		9		—		—
Net third party fees paid in connection with the amendment and extension of the TCEH Senior Secured Facilities (Note 9)		86		—		—
Impairment of land		—		—		34
Asset writeoff		—		5		2
Equity losses — unconsolidated affiliates		—		—		6
Contract termination expenses		—		—		4
Other		11		10		10
Total other deductions	$	524	$	18	$	63

(a) Represents net cash received as a result of the settlement of bankruptcy claims against a hedging trading counterparty.

A reserve of $26 million was established in 2008 related to amounts then due from the counterparty.

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

(c) Includes $23 million for reversal of a use tax accrual, related to periods prior to the Merger, due to state ruling in 2009 and $11 million for reversal of excess exit liabilities recorded in connection with the termination of outsourcing arrangements (see Note 19).

106

8. 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 wholly-owned, bankruptcy-remote, direct subsidiary of EFH Corp. Effective January 1, 2010, we consolidate TXU Receivables Company in accordance with amended consolidated accounting standards as discussed in Note 2. 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 standards, we did not consolidate TXU Receivables Company, and 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	%
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

107

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	$	787		$	1,055
Allowance for uncollectible accounts		(27	)		(64	)
Trade accounts receivable — reported in balance sheet	$	760		$	991

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	$	64		$	81		$	64
Increase for bad debt expense		56			108			116
Decrease for account write-offs		(67	)		(125	)		(99	)
Reversal of reserve related to counterparty bankruptcy (Note 7)		(26	)		—			—
Allowance for uncollectible accounts receivable as of end of period	$	27		$	64		$	81

108

9. 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 8.

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
	Maturity		Facility		Letters of		Cash
Facility	Date		Limit		Credit		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.

109

Long-Term Debt

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

	December 31,
	2011			2010
TCEH
Senior Secured Facilities:
3.776% TCEH Term Loan Facilities maturing October 10, 2014 (a)(b)(c)	$	3,809		$	19,949
3.796% TCEH Letter of Credit Facility maturing October 10, 2014 (b)		42			1,250
0.214% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (d)		—			—
4.776% TCEH Term Loan Facilities maturing October 10, 2017 (a)(b)(c)		15,370			—
4.796% TCEH Letter of Credit Facility maturing October 10, 2017 (b)		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 (c)		2,046			2,046
10.25% Fixed Senior Notes due November 1, 2015, Series B (c)		1,442			1,442
10.50 / 11.25% Senior Toggle Notes due November 1, 2016		1,568			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 (e)		16			16
7.700% Fixed Series 1999C due March 1, 2032		50			50
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 (e)		—			217
8.250% Fixed Series 2001D-1 due May 1, 2033		171			171
0.093% Floating Series 2001D-2 due May 1, 2033 (f)		97			97
0.248% Floating Taxable Series 2001I due December 1, 2036 (g)		62			62
0.093% Floating Series 2002A due May 1, 2037 (f)		45			45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (e)		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 (e)		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 (e)		—			91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011 (e)		—			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 (h)		(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 (h)		(1	)		(2	)
Total TCEH	$	29,705		$	29,191

110

	December 31,
	2011			2010
EFCH (parent entity)
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 (b)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized fair value discount (h)		(8	)		(10	)
Subtotal		85			91
EFH Corp. debt pushed down (i)
10.875% Fixed Senior Notes due November 1, 2017		98			179
11.25 / 12.00% Senior Toggle Notes due November 1, 2017		218			285
9.75% Fixed Senior Secured Notes due October 15, 2019		58			58
10.000% Fixed Senior Secured Notes due January 15, 2020		330			328
Unamortized premium		3			—
Subtotal — EFH Corp. debt pushed down		707			850
Total EFCH (parent entity)		792			941
Total EFCH consolidated		30,497			30,132
Less amount due currently		(39	)		(658	)
Less amount held by affiliates (Note 18)		(382	)		(343	)
Total long-term debt	$	30,076		$	29,131

(a) 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.

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

(c) As discussed below and in Note 18, principal amounts of notes/term loans totaling $382 million and $343 million as of December 31, 2011 and 2010, respectively, were held by EFH Corp. and EFIH.

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

(e) These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds. We repurchased the $415 million principal amount subject to mandatory tender and remarketing in November 2011.

(f) 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.

(g) 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.

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

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

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

During 2011, TCEH issued, through the payment-in-kind (PIK) election, $162 million principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes) in lieu of making cash interest payments.

111

Amendment and Extension of TCEH Senior Secured Facilities — Borrowings under the TCEH Senior Secured Facilities totaled $20.911 billion as of December 31, 2011 (including $19 million held by EFH Corp.). In April 2011, (i) the Credit Agreement governing the TCEH Senior Secured Facilities was amended, (ii) the maturity dates of approximately 80% of the borrowings under the term loans (initial term loans and delayed draw term loans) and deposit letter of credit loans under the TCEH Senior Secured Facilities and approximately 70% of the commitments under the TCEH Revolving Credit Facility were extended, (iii) borrowings totaling $1.604 billion under the TCEH Senior Secured Facilities were repaid from proceeds of issuance of $1.750 billion principal amount of TCEH 11.5% Senior Secured Notes as discussed below and (iv) the amount of commitments under the TCEH Revolving Credit Facility was reduced by $646 million.

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

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

The amendment contained certain provisions related to 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 Facilities in April 2011:

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

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

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

112

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.

113

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 $86 million were expensed (see Note 7).

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 $660 million in operating loss carryforwards. The transactions resulted in a cash charge under the Texas margin tax of $13 million (reported as income tax expense).

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

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

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

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

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

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.

114

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 (EFH Corp. 5.55% Notes). EFIH intends to hold the exchanged securities as an investment. Prior to the exchange, 50% of the outstanding EFH Corp. 10.875% Notes and Toggle Notes had been pushed down to EFCH for reporting purposes.

October 2011 EFH Corp. Debt Exchange — In a private exchange in October 2011, EFH Corp. issued $53 million principal amount of new EFH Corp. 11.25%/12.00% Toggle Notes due 2017 in exchange for $65 million principal amount of EFH Corp. 5.55% Notes. The new EFH Corp. Toggle Notes, which are subject to push down to our balance sheet, 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 that had been held by EFIH as an investment following prior debt exchange transactions, and EFH Corp. retired the notes.

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

Debt-Related Activity in 2010

Repayments of long-term debt in 2010 totaling $304 million included $205 million of principal payments at scheduled maturity dates as well as other repayments totaling $99 million principally related to capitalized leases.

During 2010, TCEH issued, through the PIK election, $205 million principal amount of TCEH Toggle Notes in lieu of making cash interest payments.

115

2010 Debt Exchanges, Repurchases and Issuances — In 2010, TCEH issued $1.221 billion principal amount of 15% Senior Secured Second Lien Notes due 2021 in exchange for $1.748 billion principal amount of outstanding TCEH Senior Notes due in 2015 and 2016. TCEH also issued $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 for cash, and used the net proceeds to repurchase $523 million principal amount of TCEH Senior Notes due in 2015 and 2016. Activity related to pushed down debt consisted of the issuance of $561 million principal amount of EFH Corp. 10% Notes due 2020 in an exchange transaction, the issuance of $500 million principal amount of EFH Corp. 10% Notes for cash, of which $95 million was used to repurchase Merger-related debt as of December 31, 2010 and $100 million as of December 31, 2011, the acquisition in exchange transactions of $3.892 billion of EFH Corp. Senior Notes and Senior Toggle Notes and $194 million in PIK interest on the EFH Corp. Senior Toggle Notes. A discussion of these transactions and descriptions of TCEH 15% Senior Secured Second Lien Notes are presented below. Debt issued in exchange for or to repurchase Merger-related debt is considered Merger-related and subject to pushdown (see discussion below under “Guarantees and Push Down of EFH Corp. Debt”).

Transactions completed in the year ended December 31, 2010 related to debt issued by TCEH and pushed down debt 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). As a result of EFIH acquiring these EFH Corp. Senior Notes, they are no longer pushed down to EFCH’s financial statements. (See “Push Down of EFH Corp. Debt” below.)

• 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 (not pushed down to EFCH), $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. Of the proceeds, $95 million was used in 2010 to repurchase Merger-related debt.

• 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.

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. All other securities acquired in the above transactions were cancelled. (See “Guarantees and Push Down of EFH Corp. Debt” below.)

116

Maturities — Long-term debt maturities as of December 31, 2011 are as follows:

Year:
2012	$	27
2013		84
2014		3,933
2015		3,659
2016		1,737
Thereafter (a)		21,131
Unamortized premium (b)		3
Unamortized discounts (c)		(140	)
Capital lease obligations		63
Total	$	30,497

(a) Long-term debt maturities for EFCH (parent entity), including pushed down debt, total $11 million, $11 million, $12 million, $13 million, $15 million and $735 million for 2012, 2013, 2014, 2015, 2016 and thereafter, respectively.

(b) Unamortized premium for EFCH (parent entity).

(c) Unamortized fair value discount for EFCH (parent entity) totals $(8) million.

Guarantees and Push Down of EFH Corp. Debt

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

The amount reflected on our balance sheet as pushed down debt ($707 million and $850 million as of December 31, 2011 and 2010, respectively, as shown in the long-term debt table above) represents 50% of the EFH Corp. Merger-related debt guaranteed by EFCH (parent entity). This percentage reflects the fact that at the time of the Merger, the equity investments of EFCH (parent entity) and EFIH in their respective operating subsidiaries were essentially equal amounts. Because payment of principal and interest on the debt is the responsibility of EFH Corp., we record the settlement of such amounts as noncash capital contributions from EFH Corp.

117

The tables below present, as of December 31, 2011 and 2010, an analysis of the total outstanding principal amount of EFH Corp. debt that EFCH (parent entity) and EFIH have guaranteed (fully and unconditionally on a joint and several basis), as (i) amounts that EFIH held as an investment, (ii) amounts held by nonaffiliates subject to push down to our balance sheet and (iii) amounts held by nonaffiliates that are not Merger-related. The EFCH (parent entity) guarantee of the EFH Corp. debt is not secured, and the EFIH guarantee of the EFH Corp. Senior Notes is not secured. The EFIH guarantee of the EFH Corp. 10% and 9.75% Notes is secured by EFIH’s pledge of 100% of the membership interests and other investments it owns in Oncor Holdings (the EFIH Collateral).

December 31, 2011
Securities Guaranteed (principal amounts)	Held by EFIH		Subject to Push Down		Not Merger- Related		Total Guaranteed
EFH Corp. 10% Senior Secured Notes	$	—	$	661	$	400	$	1,061
EFH Corp. 9.75% Senior Secured Notes		—		115		—		115
EFH Corp. 10.875% Senior Notes		1,591		196		—		1,787
EFH Corp. 11.25/12.00% Senior Toggle Notes		2,784		438		—		3,222
Subtotal	$	4,375	$	1,410	$	400		6,185
EFH Corp. P&I and SG&A demand notes payable to
TCEH (Note 18)								1,592
Total							$	7,777

December 31, 2010
Securities Guaranteed (principal amounts)	Held by EFIH		Subject to Push Down		Not Merger- Related		Total Guaranteed
EFH Corp. 10% Senior Secured Notes	$	—	$	656	$	405	$	1,061
EFH Corp. 9.75% Senior Secured Notes		—		115		—		115
EFH Corp. 10.875% Senior Notes		1,428		359		—		1,787
EFH Corp. 11.25/12.00% Senior Toggle Notes		2,296		571		—		2,867
Subtotal	$	3,724	$	1,701	$	405		5,830
EFH Corp. P&I demand note payable to TCEH (Note 18)								916
Total							$	6,746

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.

118

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.

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 Facilities. The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Facilities on a first-priority basis, subject to certain exceptions (including the elimination of the pledge of equity interests of any subsidiary Guarantor to the extent that separate financial statements would be required to be filed with the SEC for such subsidiary Guarantor under Rule 3-16 of Regulation S-X) and permitted liens. The guarantee from EFCH is not secured.

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 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.

119

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.

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.

120

TCEH Interest 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 14 for discussion of collateral investments in 2009 related to certain of these interest rate swaps.

121

10. 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	$	16	$	42
2013		10		39
2014		6		40
2015		4		37
2016		4		36
Thereafter		33		195
Total future minimum lease payments		73	$	389
Less amounts representing interest		10
Present value of future minimum lease payments		63
Less current portion		14
Long-term capital lease obligation	$	49

(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 $66 million, $89 million and $68 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.

122

Guarantees

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

See Note 9 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.

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 3 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.

123

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 3 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 NOx 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.

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 3 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.

124

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.

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.

125

11. EQUITY

Cash Distributions to Parent

We paid no cash distributions to EFH Corp. in 2011, 2010 or 2009.

Dividend Restrictions

There are no restrictions on our ability to use our retained earnings or net income to make distributions on our equity. However, we rely on distributions or loans from TCEH to meet our cash requirements, including funding of dividends. 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 their common stock unless at the time, and after giving effect to such distribution, TCEH’s consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. 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 9 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.

See Note 17 for discussion of stock-based compensation.

Noncontrolling Interests

As discussed in Note 2, we consolidate a joint venture formed 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.

Debt Pushed Down from EFH Corp.

See Note 1 for discussion of noncash contributions from EFH Corp. related to debt pushed down from EFH Corp. in accordance with SEC SAB Topic 5-J.

126

12. 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.

127

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
Nuclear decommissioning trust—equity securities (c)		208		124		—		—		332
Nuclear decommissioning trust—debt securities (c)		—		242		—		—		242
Total assets	$	603	$	4,281	$	124	$	1	$	5,009
Liabilities:
Commodity contracts	$	446	$	727	$	71	$	1	$	1,245
Interest rate swaps		—		2,231		—		—		2,231
Total liabilities	$	446	$	2,958	$	71	$	1	$	3,476

(a) 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 investments line on the balance sheet. See Note 15.

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		—		6		—		—		6
Nuclear decommissioning trust—equity securities (c)		192		121		—		—		313
Nuclear decommissioning trust—debt securities (c)		—		223		—		—		223
Total assets	$	919	$	3,925	$	401	$	2	$	5,247
Liabilities:
Commodity contracts	$	875	$	672	$	59	$	2	$	1,608
Interest rate swaps		—		1,425		—		—		1,425
Total liabilities	$	875	$	2,097	$	59	$	2	$	3,033

128

(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 investments line on the balance sheet. See Note 15.

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 14 for further discussion regarding the company’s use of derivative instruments.

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 9 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.

129

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:

		0000000000			0000000000			0000000000
	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.

130

13. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments attributable to EFCH (including pushed down debt) as of December 31, 2011 and 2010 were as follows:

	December 31, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Amount		Value (a)		Amount		Value (a)
On balance sheet liabilities:
Long-term debt (including current maturities)(b)	$	30,434	$	18,740	$	30,056	$	22,437
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 12. 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 12 and 14 for discussion of accounting for financial instruments that are derivatives.

131

14. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage 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 12 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 9 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:

		000000000			000000000		000000000			000000000			000000000
December 31, 2011
	Derivative assets					Derivative liabilities
	Commodity			Interest rate		Commodity			Interest rate
	contracts			swaps		contracts			swaps			Total
Current assets	$	2,883		$	—	$	—		$	—		$	2,883
Noncurrent assets		1,552			—		—			—			1,552
Current liabilities		(1	)		—		(1,162	)		(621	)		(1,784	)
Noncurrent liabilities		—			—		(82	)		(1,610	)		(1,692	)
Net assets (liabilities)	$	4,434		$	—	$	(1,244	)	$	(2,231	)	$	959

		000000000			000000000		000000000			000000000			000000000
December 31, 2010
	Derivative assets					Derivative liabilities
	Commodity			Interest rate		Commodity			Interest rate
	contracts			swaps		contracts			swaps			Total
Current assets	$	2,637		$	3	$	—		$	—		$	2,640
Noncurrent assets		2,068			3		—			—			2,071
Current liabilities		(2	)		—		(1,542	)		(620	)		(2,164	)
Noncurrent liabilities		—			—		(64	)		(805	)		(869	)
Net assets (liabilities)	$	4,703		$	6	$	(1,606	)	$	(1,425	)	$	1,678

As of December 31, 2011 and 2010, there were no derivative positions accounted for as cash flow or fair value hedges.

132

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, EFH Corp. and TCEH entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which the companies 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:

		0000000000			0000000000			0000000000
	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 7).

(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 19).

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.

		00000000			00000000			00000000
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	)	$	(183	)
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	)	$	(201	)

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.

Accumulated other comprehensive income related to cash flow hedges as of December 31, 2011 and 2010 totaled $49 million and $68 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.

133

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	$	31,255	$	15,800	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.

134

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 $2.651 billion and $1.747 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 $1.160 billion and $647 million, respectively. See Note 9 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 $3.015 billion and $2.155 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.

135

15. INVESTMENTS

The investments balance consists of the following:

	December 31,		December 31,
	2011		2010
Nuclear plant decommissioning trust	$	574	$	536
Assets related to employee benefit plans, including employee savings programs, net of distributions		10		17
Land		41		41
Investment in unconsolidated affiliate		1		5
Miscellaneous other		3		3
Total investments	$	629	$	602

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 Oncor, reflecting changes in Oncor’s regulatory asset/liability. 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.

136

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	)

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. EFH Corp. pays the premiums and is the beneficiary of these life insurance policies.

137

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

Pension Plan

Our subsidiaries are participating employers in the EFH Retirement Plan (Retirement Plan), a defined benefit pension plan sponsored by EFH Corp. The Retirement Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code) and is subject to the provisions of ERISA. All benefits are funded by the participating employers. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.

Effective October 1, 2007, all new employees, with the exception of employees hired by Oncor, are not eligible to participate in the Retirement Plan. It is EFH Corp.’s policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.

Our subsidiaries also participate in EFH Corp.’s supplemental unfunded retirement plans for certain employees whose retirement benefits cannot fully be earned under the qualified Retirement Plan, the information for which is included below.

Other Postretirement Employee Benefit (OPEB) Plan

Our subsidiaries participate with EFH Corp. and certain other affiliated subsidiaries of EFH Corp. to offer OPEB in the form of health care and life insurance to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service. In 2011, we announced a change to the OPEB plan whereby, effective January 1, 2013, Medicare-eligible employees of the competitive business will be subject to a cap on increases in subsidies received under the plan to offset medical costs.

Pension and OPEB Costs Recognized as Expense

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

		0000000		0000000		0000000
	Year Ended December 31,
	2011		2010		2009
Pension costs	$	38	$	28	$	13
OPEB costs		14		11		9
Total benefit costs recognized as expense	$	52	$	39	$	22

EFH Corp. uses the calculated value method to determine the market-related value of the assets held in trust. EFH Corp. includes the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

138

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. These costs are associated with Oncor’s active and retired employees as well as active and retired personnel engaged in TCEH’s activities, related to their service prior to the deregulation and disaggregation of EFH Corp.’s business effective January 1, 2002. Accordingly, Oncor and TCEH entered into an agreement whereby Oncor assumed responsibility for applicable pension and OPEB costs related to those personnel.

Additional Multiemployer Plan Participation Disclosures

We have not been allocated any overfunded asset or underfunded liability related to our participation in EFH Corp.’s pension and OPEB plans. However, we are jointly and severally liable for all EFH Corp. pension and OPEB plan liabilities and are subject to certain risks including the following:

• Funding/assets contributed by us may be used to provide benefits to employees from other participating entities;

• We may be required to bear the unfunded obligations of another participating employer that stops making contributions, and

• If we stop participating, we may be required to pay an amount to the plan based on the underfunded status of the plan.

Our share of contributions to the EFH Corp. Retirement Plan was zero percent in each of the years ended December 31, 2011 and 2010 and 18% in the year ended December 31, 2009. The plan was at least 80% funded for those periods as determined under the provisions of ERISA. The Employer Identification Number of the Retirement Plan is 75-2669310 and the plan number is 002.

Assumed Discount Rate

The discount rate reflected for net pension and OPEB costs is 5.50% and 5.55%, respectively, for the year ended December 31, 2011, 5.90% for both plans for the year ended December 31, 2010 and 6.90% and 6.85%, respectively, for the year ended December 31, 2009. The expected rate of return on plan assets reflected in the 2011 cost amounts is 7.7% and 7.1% for the pension plan assets and OPEB assets, respectively.

Thrift Plan

Our employees may participate in a qualified savings plan, the EFH Thrift Plan (Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are 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 $18 million, $17 million and $16 million for the years ended December 31, 2011, 2010 and 2009, respectively.

139

17. STOCK-BASED COMPENSATION

In December 2007, EFH Corp. established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007 SIP). We bear the costs of EFH Corp.’s 2007 SIP for applicable management personnel engaged in our business activities. Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferred shares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in whole or in part by reference to, or are otherwise based on the fair market value of EFH Corp.’s shares of common stock.

Stock-based compensation expense recorded in the years ended December 31, 2011, 2010 and 2009 was as follows:

		000000000			000000000			000000000
	Year Ended December 31,
Type of award	2011			2010			2009
Restricted stock units granted to employees	$	2		$	—		$	—
Stock options granted to employees		4			9			5
Other share and share-based awards		(1	)		(2	)		(1	)
Total compensation expense	$	5		$	7		$	4

Restricted Stock Units — Restricted stock unit activity, all of which occurred in 2011, consisted of the issuance of 11.2 million units in exchange for stock options as discussed below, grants of 2.2 million units and forfeitures of 0.4 million units. Restricted stock units vest as common stock of EFH Corp, upon the earlier of September 2014 or a change of control, or on a prorated basis upon certain defined events such as termination of employment. Compensation expense per unit is based on the estimated value of EFH Corp. stock at the grant date, less a marketability discount factor. To determine expense related to units issued in exchange for stock options, the unit value is further reduced by the fair value of the options exchanged. As of December 31, 2011, there was approximately $9.4 million of unrecognized compensation expense related to nonvested restricted stock units expected to be recognized by us through September 2014.

Stock Options — Options to purchase 0.2 million and 9.0 million shares of EFH Corp. common stock were granted to certain of our management employees in 2010 and 2009, respectively. No options were granted in 2011. Of the options granted in 2009, 6.3 million were granted in exchange for previously granted options. The exercise period for vested awards was 10 years from the grant date. The options initially provided the holder the right to purchase EFH Corp. common stock for $5.00 per share. The terms of the options were fixed at grant date. One-half of the options initially granted were to vest solely based upon continued employment over a specific period of time, generally five years, with the options vesting ratably on an annual basis over the period (Time-Based Options). One-half of the options initially granted were to vest based upon both continued employment and the achievement of targeted five-year EFH Corp. EBITDA levels (Performance-Based Options). Prior to vesting, expenses were recorded if the achievement of the EBITDA levels was probable, and amounts recorded were adjusted or reversed if the probability of achievement of such levels changed. Probability of vesting was evaluated at least each quarter. The stock option expense presented in the table above relates to Time-Based Options except for $1.6 million in 2010 related to Performance-Based Options.

In October 2009, in consideration of the then recent economic dislocation and the desire to provide incentives for retention, grantees of Performance-Based Options (excluding named executive officers and a small group of other employees) were provided an offer, which substantially all accepted, to exchange their unvested Performance-Based Options granted under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options (Cliff-Vesting Options) with a strike price of $3.50 per share (the then most recent market valuation of each share), with one-half of these options to vest in September 2012 and one-half of these options to vest in September 2014. Additionally, certain named executive officers and a small group of other employees were granted an aggregate 2.0 million Cliff-Vesting Options with a strike price of $3.50 per share, to vest in September 2014, and substantially all of these employees also accepted an offer to exchange half of their unvested Performance-Based Options with a strike price of $5.00 per share and a vesting schedule through December 2012 for new time-based stock options with a strike price of $3.50 per share, to vest in September 2014.

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 late February 2011, and substantially all of our eligible employees accepted the offer, which resulted in the issuance of 6.5 million restricted stock units in exchange for 11.1 million time-based options (including 3.5 million that were vested) and 1.9 million performance-based options (including 1.4 million that were vested).

140

In October 2011, in consideration of the desire to enhance retention incentives, EFH Corp. offered its named executive officers and a limited number of other officers (including certain of our officers) the right to exchange their vested and unvested options for restricted stock units payable in shares on terms largely consistent with offers made in December 2010 to other employee grantees of stock options. The exchange offer closed in October 2011, and all eligible employees accepted the offer, which resulted in the issuance of 4.6 million restricted stock units in exchange for 7.3 million time-based options (including 3.2 million that were vested) and 1.9 million performance-based options (including 1.8 million that were vested).

The fair value of all options granted was estimated using the Black-Scholes option pricing model and the assumptions noted in the table below. Since EFH Corp. is a private company, expected volatility was based on actual historical experience of comparable publicly-traded companies for a term corresponding to the expected life of the options. The expected life represents the period of time that options granted were expected to be outstanding and was calculated using the simplified method prescribed by the SEC Staff Accounting Bulletin No. 107. The simplified method was used since EFH Corp. did not have stock option history upon which to base the estimate of the expected life and data for similar companies was not reasonably available. The risk-free rate was based on the US Treasury security with terms equal to the expected life of the option as of the grant date.

The weighted average grant-date fair value of the Time-Based Options granted in 2010 and 2009 was $1.36 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 $1.42 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		35%	30%	30%
Expected annual dividend		—	—	—
Expected life (in years)		6.8	6.4 –7.4	5.6 – 7.6
Risk-free rate		2.99%	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 $6.7 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.

141

A summary of Time-Based Options activity is presented below:

		00000000			00000000
				Weighted
				Average
	Options			Exercise
Time-Based Options Activity in 2011:	(millions)			Price
Total outstanding as of beginning of period		18.7		$	4.30
Granted		—		$	—
Exercised		—		$	—
Forfeited		—		$	—
Exchanged		(18.4	)	$	4.30
Total outstanding as of end of period (weighted average remaining term of 6—10 years)		0.3		$	4.30
Exercisable as of end of period (weighted average remaining term of 6—10 years)		—		$	—
Expected forfeitures		(0.3	)	$	4.30
Expected to vest as of end of period (weighted average remaining term of 6—10 years)		—		$	—

		0000000			0000000
				Weighted
				Average
	Options			Exercise
Time-Based Options Activity in 2010:	(millions)			Price
Total outstanding as of beginning of period		20.0		$	4.34
Granted		0.2		$	2.18
Exercised		—		$	—
Forfeited		(1.5	)	$	4.59
Total outstanding as of end of period (weighted average remaining term of 7—10 years)		18.7		$	4.30
Exercisable as of end of period (weighted average remaining term of 7—10 years)		(2.5	)	$	4.77
Expected forfeitures		(0.1	)	$	5.00
Expected to vest as of end of period (weighted average remaining term of 7—10 years)		16.1		$	4.22

		00000000			00000000
				Weighted
				Average
	Options			Exercise
Time-Based Options Activity in 2009:	(millions)			Price
Total outstanding as of beginning of period		13.3		$	5.00
Granted		8.8		$	3.50
Exercised		—		$	—
Forfeited		(2.1	)	$	5.00
Total outstanding as of end of period (weighted average remaining term of 8—10 years)		20.0		$	4.34
Exercisable as of end of period (weighted average remaining term of 8—10 years)		(2.2	)	$	5.00
Expected forfeitures		(0.1	)	$	5.00
Expected to vest as of end of period (weighted average remaining term of 8—10 years)		17.7		$	4.25

142

		0000000			0000000		0000000			0000000		0000000			0000000
	2011					2010					2009
Nonvested Time-Based 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		11.7		$	1.55		15.5		$	1.63		11.0		$	2.05
Granted		—		$	—		0.2		$	1.36		8.8		$	1.32
Vested		—		$	—		(2.5	)	$	1.92		(2.2	)	$	1.93
Forfeited		—		$	—		(1.5	)	$	1.72		(2.1	)	$	1.84
Exchanged		(11.7	)	$	1.55		—		$	—		—		$	—
Total nonvested as of end of period		—		$	—		11.7		$	1.55		15.5		$	1.63

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.

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 2.4 million of the 2008 and 0.9 million of the 2009 Performance-Based Options had vested.

A summary of Performance-Based Options activity is presented below:

		00000000			00000000
				Weighted
				Average
	Options			Exercise
Performance-Based Options Activity in 2011:	(millions)			Price
Outstanding as of beginning of period		3.8		$	5.00
Granted		—		$	—
Exercised		—		$	—
Forfeited		—		$	—
Exchanged		(3.8	)	$	5.00
Total outstanding as of end of period (weighted average remaining term of 6 to 8 years)		—		$	—
Exercisable as of end of period (weighted average remaining term of 6 to 8 years)		—		$	—
Expected forfeitures		—		$	—
Expected to vest as of end of period (weighted average remaining term of 6 to 8 years)		—		$	—

		00000000			00000000
				Weighted
				Average
	Options			Exercise
Performance-Based Options Activity in 2010:	(millions)			Price
Outstanding as of beginning of period		4.9		$	5.00
Granted		—		$	—
Exercised		—		$	—
Forfeited		(1.1	)	$	5.00
Exchanged		—		$	—
Total outstanding as of end of period (weighted average remaining term of 7 to 10 years)		3.8		$	5.00
Exercisable as of end of period (weighted average remaining term of 7 to 10 years)		(0.9	)	$	5.00
Expected forfeitures		—		$	—
Expected to vest as of end of period (weighted average remaining term of 7 to 10 years)		2.9		$	5.00

143

		0000000			0000000
Performance-Based Options Activity in 2009:	Options (millions)			Weighted Average Exercise Price
Outstanding as of beginning of period		13.1		$	5
Granted		0.2		$	3.5
Exercised		—		$	—
Forfeited		(2.1	)	$	5
Exchanged		(6.3	)	$	5
Total outstanding as of end of period (weighted average remaining term of 8 to 10 years)		4.9		$	5
Exercisable as of end of period (weighted average remaining term of 8 to 10 years)		(2.4	)	$	5
Expected forfeitures		(0.1	)	$	5
Expected to vest as of end of period (weighted average remaining term of 8 to 10 years)		2.4		$	5

	2011					2010					2009
	Options			Grant- Date		Options			Grant- Date		Options			Grant- Date
Nonvested Performance-Based Nonvested Options Activity:	(millions)			Fair Value		(millions)			Fair Value		(millions)			Fair Value
Total nonvested as of beginning of period		0.5		$	1.16 - 2.01		2.5		$	1.16 – 2.01		13.1		$	1.73 – 2.25
Granted		—			—		—			—		0.2		$	1.16 – 1.42
Vested		—			—		(0.9	)	$	1.77 – 1.87		(2.4	)	$	1.73 – 2.25
Forfeited		—			—		(1.1	)	$	1.65 – 1.87		(2.1	)	$	1.77 – 1.92
Exchanged		(0.5	)	$	1.16 - 2.01		—			—		(6.3	)	$	1.13 – 2.25
Total nonvested as of end of period		—		$	1.16 - 2.01		0.5		$	1.16 – 2.01		2.5		$	1.16 – 2.01

Other Share and Share-Based Awards — In 2008, EFH Corp. granted 1.75 million deferred share awards, each of which represents the right to receive one share of EFH Corp. stock, to certain of our management employees who agreed to forego share-based awards that vested at the Merger date. The deferred share awards are fully vested and are payable in cash or stock upon the earlier of a change of control or separation of service. No expense was recorded in 2008 related to these awards. An additional 150 thousand deferred share awards were granted to certain of our management employees in 2008, which are payable in cash or stock, all of which have since vested or have been surrendered upon termination of employment. Expenses recognized in 2010 and 2009 related to these grants totaled $0.1 million and $0.4 million, respectively. The deferred share awards are accounted for as liability awards; therefore, the effects of changes in estimated value of EFH Corp. shares are recognized in earnings. As a result of the decline in estimated value of EFH Corp. shares, share-based compensation expense in 2011, 2010 and 2009 was reduced by $1.0 million, $1.9 million and $1.4 million, respectively.

144

18. RELATED-PARTY TRANSACTIONS

The following represent our significant related-party transactions:

• TCEH’s retail operations pay electricity delivery fees to Oncor. Amounts expensed for these fees totaled $1.0 billion, $1.1 billion and $1.0 billion for the years ended December 31, 2011, 2010 and 2009, 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 trade accounts and other payables to affiliates) 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 trade accounts and other payables to affiliates) and $217 million ($39 million current portion included in trade accounts and other payables to affiliates) as of December 31, 2011 and 2010, respectively. TCEH’s payments on the note totaled $39 million, $37 million and $35 million for the years ended December 31, 2011, 2010 and 2009, 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, $37 million and $42 million for the years ended December 31, 2011, 2010 and 2009, respectively.

• Notes receivable from EFH Corp. are payable to TCEH on demand and arise from cash loaned for debt principal and interest payments and other general corporate purposes of EFH Corp. As of December 31, 2011 and 2010, the notes consisted of:

	December 31, 2011		December 31, 2010
Note related to debt principal and interest payments	$	1,359	$	916
Note related to general corporate purposes	$	233	$	1,005
Total	$	1,592	$	1,921

The principal and interest related demand note has been guaranteed by EFIH and EFCH on a pari passu basis with the EFH Corp. Senior Notes since the Merger. In connection with the amendment to the TCEH Senior Secured Facilities discussed in Note 9, the note related to net borrowings for general corporate purposes is also now guaranteed by EFIH and EFCH on the same basis as the principal and interest related demand note, and $770 million of the note was repaid in April 2011. These demand notes have been pledged as collateral under the TCEH Senior Secured Facilities. As of December 31, 2011, $670 million of the total $1.6 billion of demand notes receivable from EFH Corp. are reported as current in the balance sheet. The current amount represents the amount of outstanding borrowings as of December 31, 2011 under the TCEH Revolving Credit Facility, which are classified as current liabilities and collateralized by the demand notes. Further, EFH Corp. has sufficient liquidity as of December 31, 2011 to repay the current amount. In February 2012, $650 million of the P&I Note was repaid by EFH Corp. bringing the balance of the demand notes to approximately $960 million. The repayment was funded by a debt issuance at EFIH in February 2012. The average daily balance of the notes totaled $1.542 billion, $1.588 billion and $944 million for the years ended December 31, 2011, 2010 and 2009, respectively. The notes carry interest at a rate based on the one-month LIBOR rate plus 5.00% and interest income totaled $82 million, $85 million and $51 million for the years ended December 31, 2011, 2010 and 2009, respectively.

145

TCEH had a demand note payable to EFH Corp. totaling $770 million for the period February to December 2010 and again for the period January to April 2011. The proceeds from the note were used to repay borrowings under the TCEH Revolving Credit Facility (see Note 9). The average daily balance of the note was $184 million and $644 million for the years ended December 31, 2011 and 2010, respectively. The note carried interest at a rate based on the one-month LIBOR rate plus 3.50%, and interest expense totaled $7 million and $25 million for the years ended December 31, 2011 and 2010, respectively. In addition, EFCH has a demand note payable to EFH Corp., the proceeds from which were used to repay outstanding debt. The note totaled $57 million and $46 million as of December 31, 2011 and 2010, respectively, and carried interest at a rate based on the one-month LIBOR rate plus 5.00%.

• Receivables from affiliates are measured at historical cost and primarily consist of notes receivable for cash loaned to EFH Corp. for debt principal and interest payments and other general corporate purposes of EFH Corp. as discussed above. TCEH reviews economic conditions, counterparty credit scores and historical payment activity to assess the overall collectability of its affiliated receivables. There were no credit loss allowances as of December 31, 2011 and 2010.

• Our subsidiaries pay a subsidiary of EFH Corp. for information technology, financial, accounting and other administrative services at cost. These costs, which are primarily reported in SG&A expenses, totaled $213 million, $193 million and $82 million for the years ended December 31, 2011, 2010 and 2009, respectively.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in investments on our 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. The delivery fee surcharges remitted to TCEH totaled $17 million in the year ended December 31, 2011 and $16 million in each of the years ended December 31, 2010 and 2009, respectively. Income and expenses associated with the trust fund and the decommissioning liability are offset by a net change in the intercompany receivable/payable between Oncor and us, 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 notes or other liabilities due affiliates in the balance sheet.

• TCEH had posted cash collateral totaling $4 million as of December 31, 2010 to Oncor related to interconnection agreements for the generation unit developed by TCEH. The collateral was returned in April 2011. The collateral was reported in our December 31, 2010 balance sheet in other current assets.

• EFH Corp. files a consolidated federal income tax return; however, under a tax sharing agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if we file our own corporate income tax return. As a result, we had income taxes payable to EFH Corp. of $74 million and $21 million as of December 31, 2011 and 2010, respectively. We made income tax payments to EFH Corp. totaling $123 million, $49 million and $27 million for the years ended December 31, 2011, 2010 and 2009, respectively.

• Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, 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.

• 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.

146

• 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 9.

• In the year ended December 31, 2011, fees paid to Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, 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 9 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 October 2010, Goldman acted as an initial purchaser in the issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) as discussed in Note 9 and received fees totaling $1 million.

• Affiliates of GS Capital Partners are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

• Affiliates of the Sponsor Group have, and in the future may, sell or acquire debt or debt securities issued by us in open market transactions or through loan syndications.

• As a result of debt repurchase and exchange transactions in 2009, 2010 and 2011, EFH Corp. and EFIH held as investments TCEH debt securities as follows (principal amounts):

	December 31, 2011		December 31, 2010
TCEH Senior Notes
Held by EFH Corp.	$	284	$	244
Held by EFIH		79		79
TCEH Term Loan Facilities
Held by EFH Corp.		19		20
Total	$	382	$	343

Interest expense on the notes totaled $34 million, $30 million and $2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

See Notes 9 and 10 for guarantees and push-down of certain EFH Corp. debt, Note 16 for allocation of EFH Corp. pension and OPEB costs to us and Note 17 for discussion of stock-based compensation.

147

19. 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)	$	2,618		$	2,477		$	2,560
Accrued interest to be paid with additional toggle notes (Note 9)		166			217			207
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			183
Amortization of fair value debt discounts resulting from purchase accounting		17			17			17
Amortization of debt issuance, amendment and extension costs and discounts (a)		183			122			124
Capitalized interest		(31	)		(60	)		(274	)
Total interest expense and related charges	$	3,792		$	3,067		$	2,121

(a) Includes write-off in the second quarter 2011 of $16 million of previously deferred fees as a result of the amendment and extension transactions in April 2011 (see Note 9).

Restricted Cash

	As of December 31, 2011				As of December 31, 2010
	Current		Noncurrent		Current		Noncurrent
	Assets		Assets		Assets		Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 9)	$	—	$	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

148

Property, Plant and Equipment

	December 31,
	2011		2010
Generation and mining	$	22,607	$	22,313
Other assets		427		387
Total		23,034		22,700
Less accumulated depreciation		4,723		3,490
Net of accumulated depreciation		18,311		19,210
Construction work in progress		575		580
Nuclear fuel (net of accumulated amortization of $776 and $610)		320		353
Held for sale		12		12
Property, plant and equipment — net	$	19,218	$	20,155

Depreciation expense totaled $1.330 billion, $1.245 billion and $1.051 billion for the years ended December 31, 2011, 2010 and 2009, respectively.

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 $67 million and $78 million as of December 31, 2011 and 2010, respectively, net of accumulated depreciation.

149

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:

		00000000000			00000000000			00000000000
	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 18.)

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 5)	$	1,220	$	1,059
Asset retirement and mining reclamation obligations		505		452
Unfavorable purchase and sales contracts		647		673
Retirement plan and other employee benefits		44		44
Other		8		8
Total other noncurrent liabilities and deferred credits	$	2,424	$	2,236

150

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 in 2011 and $27 million in both 2010 and 2009. Favorable purchase and sales contracts are recorded as intangible assets (see Note 4).

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. and TCEH 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, EFH Corp. and TCEH 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 $38 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:

		0,000
Liability for exit activities as of January 1, 2009	$	38
Payments recorded against liability		(24	)
Other adjustments to the liability (a)		(11	)
Liability for exit activities as of December 31, 2009	$	3
Payments recorded against liability		(1	)
Other adjustments to the liability (a)		(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.

151

Supplemental Cash Flow Information

	Year Ended December 31,
	2011			2010			2009
Cash payments (receipts) related to:
Interest paid (a)	$	2,469		$	2,269		$	2,305
Capitalized interest		(31	)		(60	)		(274	)
Interest paid (net of capitalized interest) (a)		2,438			2,209			2,031
Income taxes		123			49			27
Noncash investing and financing activities:
Effect of push down of debt from Parent		(167	)		(1,618	)		(33	)
Effect of Parent’s payment of interest and issuance of toggle notes as consideration for cash interest, net of tax, on pushed down debt		33			(99	)		227
Principal amount of TCEH Toggle Notes issued in lieu of cash interest
(Note 9)		162			211			202
Capital leases		—			—			15
Contribution related to EFH Corp. stock-based compensation		5			7			4
Construction expenditures (b)		62			83			130
Debt exchange transactions		—			527			—
Gain on termination of long-term power sales contract (Note 7)		—			116			—

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

(b) Represents end-of-period accruals.

152

20. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

As of December 31, 2011, TCEH and TCEH Finance, as Co-Issuers, had outstanding $5.056 billion aggregate principal amount of 10.25% Senior Notes Due 2015, 10.25% Senior Notes due 2015 Series B and Toggle Notes (collectively, the TCEH Senior Notes) and $1.571 billion aggregate principal amount of 15% Senior Secured Second Lien Notes due 2021 and 15% Senior Secured Second Lien Notes due 2021 (Series B) (collectively, the TCEH Senior Secured Second Lien Notes). The TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes are unconditionally guaranteed by EFCH and by each subsidiary (all 100% owned by TCEH) that guarantees the TCEH Senior Secured Facilities (collectively, the Guarantors). The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes. The guarantees of the TCEH Senior Notes rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. The guarantees of the TCEH Senior Secured Second Lien Notes rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH’s obligations under the TCEH Senior Secured Facilities, the TCEH Senior Secured Notes issued in April 2011 (see Note 9) 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. All other subsidiaries of EFCH, either direct or indirect, do not guarantee the TCEH Senior Notes or TCEH Senior Secured Second Lien Notes (collectively the Non-Guarantors). The indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes contain certain restrictions, subject to certain exceptions, on EFCH’s ability to pay dividends or make investments. See Note 11.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income and of cash flows of EFCH (Parent), TCEH (Issuer), the Guarantors and the Non-Guarantors for the years ended December 31, 2011, 2010 and 2009 and the condensed consolidating balance sheets as of December 31, 2011 and December 31, 2010 of the Parent, Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5J, “Push Down Basis of Accounting Required in Certain Limited Circumstances,” including the effects of the push down of $319 million and $464 million of the EFH Corp. Senior Notes and $388 million and $386 million of the EFH Corp. Senior Secured Notes to the Parent as of December 31, 2011 and December 31, 2010, respectively, and the TCEH Senior Notes, TCEH Senior Secured Notes (2011 only), TCEH Senior Secured Second Lien Notes and TCEH Senior Secured Facilities to the Other Guarantors as of December 31, 2011 and December 31, 2010. TCEH Finance’s sole function is to be the co-issuer of the certain TCEH debt securities; therefore, it has no other independent assets, liabilities or operations (see Note 9).

EFCH (parent entity) received no dividends/distributions from its consolidated subsidiaries for the years ended December 31, 2011, 2010 and 2009.

153

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2011

(Millions of Dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	7,040		$	11		$	(11	)	$	7,040
Fuel, purchased power costs and delivery fees		—			—			(3,396	)		—			—			(3,396	)
Net gain (loss) from commodity hedging and trading activities		—			1,018			(7	)		—			—			1,011
Operating costs		—			—			(924	)		—			—			(924	)
Depreciation and amortization		—			—			(1,470	)		—			—			(1,470	)
Selling, general and administrative expenses		—			—			(735	)		(4	)		11			(728	)
Franchise and revenue-based taxes		—			—			(96	)		—			—			(96	)
Other income		6			(16	)		58			—			—			48
Other deductions		—			(87	)		(437	)		—			—			(524	)
Interest income		—			381			694			—			(989	)		86
Interest expense and related charges		(94	)		(4,370	)		(2,301	)		(7	)		2,980			(3,792	)
Loss before income taxes and equity earnings of subsidiaries		(88	)		(3,074	)		(1,574	)		—			1,991			(2,745	)
Income tax benefit		26			1,067			520			—			(670	)		943
Equity earnings (losses) of subsidiaries		(1,740	)		267			—			—			1,473			—
Net loss	$	(1,802	)	$	(1,740	)	$	(1,054	)	$	—		$	2,794		$	(1,802	)

154

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2010

(Millions of Dollars)

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

155

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2009

(Millions of Dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	7,911		$	—		$	—		$	7,911
Fuel, purchased power costs and delivery fees		—			—			(3,934	)		—			—			(3,934	)
Net gain from commodity hedging and trading activities		—			1,049			687			—			—			1,736
Operating costs		—			—			(693	)		—			—			(693	)
Depreciation and amortization		—			—			(1,172	)		—			—			(1,172	)
Selling, general and administrative expenses		—			(1	)		(737	)		(3	)		—			(741	)
Franchise and revenue-based taxes		—			—			(108	)		—			—			(108	)
Impairment of goodwill		—			(70	)		—			—			—			(70	)
Other income		—			20			39			—			—			59
Other deductions		—			—			(63	)		—			—			(63	)
Interest income		—			431			419			—			(788	)		62
Interest expense and related charges		(289	)		(2,646	)		(1,696	)		—			2,510			(2,121	)
Income (loss) before income taxes and equity earnings of subsidiaries		(289	)		(1,217	)		653			(3	)		1,722			866
Income tax (expense) benefit		95			351			(201	)		1			(597	)		(351	)
Equity earnings (losses) of subsidiaries		709			1,575			—			—			(2,284	)		—
Net income (loss)	$	515		$	709		$	452		$	(2	)	$	(1,159	)	$	515

156

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2011

(Millions of Dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(4	)	$	(1,572	)	$	2,827		$	(15	)	$	—		$	1,236
Cash flows — financing activities:
Notes due to affiliates		12			2,370			—			7			(2,389	)		—
Issuances of long-term debt		—			1,750			—			—			—			1,750
Repayments/repurchases of logn-term debt		(8	)		(1,372	)		(28	)		—			—			(1,408	)
Net short-term borrowings under accounts receivable securitization program		—			—			—			8			—			8
Decrease in other short-term borrowings		—			(455	)		—			—			—			(455	)
Decrease in income tax-related note payable to Oncor		—			—			(39	)		—			—			(39	)
Contributions from noncontrolling interests		—			—			—			16			—			16
Debt amendment, exchange and issuance costs		—			(843	)		—			—			—			(843	)
Other, net
		—			(2	)		—			—			—			(2	)
Cash provided by (used in) financing activities		4			1,448			(67	)		31			(2,389	)		(973	)
Cash flows — investing activities:
Capital expenditures		—			—			(515	)		(15	)		—			(530	)
Nuclear fuel purchases		—			—			(132	)		—			—			(132	)
Notes/loans (to) from affiliates		—			—			(2,043	)		—			2,389			346
Proceeds from sale of assets		—			—			49			—			—			49
Reduction of restricted cash related to TCEH letter of credit facility		—			188			—			—			—			188
Other changes in restricted cash		—			—			(96	)		—			—			(96	)
Proceeds from sales of environmental allowances and credits		—			—			10			—			—			10
Purchases of environmental allowances and credits		—			—			(17	)		—			—			(17	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			2,419			—			—			2,419
Investments in nuclear decommissioning trust fund securities		—			—			(2,436	)		—						(2,436	)
Other-net		—			—			9			—			—			9
Cash provided by (used in) investing activities		—			188			(2,752	)		(15	)		2,389			(190	)
Net change in cash and cash equivalents		—			64			8			1			—			73
Cash and cash equivalents — beginning balance		—			23			15			9			—			47
Cash and cash equivalents — ending balance	$	—		$	87		$	23		$	10		$	—		$	120

157

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2010

(Millions of Dollars)

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

158

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2009

(Millions of Dollars)

	Parent/ Guarantor			Issuer			Other Guarantors			Non- guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(8	)	$	(1,333	)	$	2,736		$	(11	)	$	—		$	1,384
Cash flows — financing activities:
Issuances of long-term debt		—			522			—			—			—			522
Repayments/repurchases of long-term debt		(7	)		(174	)		(98	)		—			—			(279	)
Increase in other short-term borrowings		—			53			—			—			—			53
Notes/loans from affiliates		15			286			—			41			(377	)		(35	)
Contributions from noncontrolling interests		—			—			—			48			—			48
Debt discount, financing and reacquisition expenses		—			(33	)		—			(2	)		—			(35	)
Other-net		—			—			5			—			—			5
Cash provided by (used in) financing activities		8			654			(93	)		87			(377	)		279
Cash flows — investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(1,451	)		(70	)		—			(1,521	)
Redemption of investment held in money market fund		—			142			—			—			—			142
Reduction of restricted cash related to letter of credit facility		—			115			—			—			—			115
Proceeds from sales of environmental allowances and credits		—			—			19			—			—			19
Purchases of environmental allowances and credits		—			—			(19	)		—			—			(19	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			3,064			—			—			3,064
Investments in nuclear decommissioning trust fund securities		—			—			(3,080	)		—			—			(3,080	)
Net notes/loans to affiliates		—			—			(1,199	)		—			377			(822	)
Proceeds from sale of assets		—			40			1			—			—			41
Other-net		—			(16	)		29			—			—			13
Cash provided by (used in) investing activities		—			281			(2,636	)		(70	)		377			(2,048	)
Net change in cash and cash equivalents		—			(398	)		7			6			—			(385	)
Cash and cash equivalents — beginning balance		—			475			4			—			—			479
Cash and cash equivalents — ending balance	$	—		$	77		$	11		$	6		$	—		$	94

159

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of December 31, 2011

(Millions of Dollars)

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

160

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of December 31, 2011

(Millions of Dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors		Eliminations			Consolidated
Margin deposits related to commodity positions		—			865			196			—		—			1,061
Accumulated deferred income taxes		—			4			52			—		(3	)		53
Accrued income taxes payable to parent		—			—			170			—		(96	)		74
Accrued taxes other than income		—			—			136			—		—			136
Accrued interest		24			369			258			—		(257	)		394
Other current liabilities		—			11			257			1		(3	)		266
Total current liabilities		102			11,715			3,338			536		(10,284	)		5,407
Accumulated deferred income taxes		82			—			4,124			—		506			4,712
Commodity and other derivative contractual liabilities		—			1,670			22			—		—			1,692
Notes or other liabilities due affiliates		—			—			363			—		—			363
Long-term debt held by affiliate		—			382			—			—		—			382
Long-term debt, less amounts due currently		782			29,230			28,672			—		(28,608	)		30,076
Other noncurrent liabilities and deferred credits		13			52			2,358			—		1			2,424
Total liabilities		979			43,049			38,877			536		(38,385	)		45,056
EFCH shareholder’s equity		(7,819	)		(6,861	)		(4,946	)		36		11,771			(7,819	)
Noncontrolling interests in subsidiaries		—			—			—			103		—			103
Total equity		(7,819	)		(6,861	)		(4,946	)		139		11,771			(7,716	)
Total liabilities and equity	$	(6,840	)	$	36,188		$	33,931		$	675	$	(26,614	)	$	37,340

161

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of December 31, 2010

(Millions of Dollars)

	Parent Guarantor			Issuer		Other Guarantors		Non- guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	23	$	15	$	9	$	—		$	47
Restricted cash		—			—		33		—		—			33
Advances to affiliates (a)		—			—		39		—		(39	)		—
Trade accounts receivable – net		—			4		891		612		(516	)		991
Income taxes receivable		—			—		59		—		(59	)		—
Accounts receivable from affiliates		—			3		—		—		(3	)		—
Notes receivable from parent		—			1,921		—		—		—			1,921
Inventories		—			—		395		—		—			395
Commodity and other derivative contractual assets		—			696		1,944		—		—			2,640
Accumulated deferred income taxes		3			—		—		—		(3	)		—
Margin deposits related to commodity positions		—			—		166		—		—			166
Other current assets		—			—		35		2		—			37
Total current assets		3			2,647		3,577		623		(620	)		6,230
Restricted cash		—			1,135		—		—		—			1,135
Investments		(5,145	)		22,632		635		—		(17,520	)		602
Property, plant and equipment – net		—			—		20,043		112		—			20,155
Advances to affiliates (a)		—			—		6,744		—		(6,744	)		—
Goodwill		—			6,152		—		—		—			6,152
Identifiable intangible assets – net		—			—		2,371		—		—			2,371
Commodity and other derivative contractual assets		—			1,760		311		—		—			2,071
Accumulated deferred income taxes		—			—		—		1		(1	)		—
Other noncurrent assets, principally unamortized issuance costs		11			403		377		6		(369	)		428
Total assets	$	(5,131	)	$	34,729	$	34,058	$	742	$	(25,254	)	$	39,144
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	1,125	$	1,125	$	96	$	(1,125	)	$	1,221
Notes/advances from affiliates		8			6,774		—		1		(6,783	)		—
Long-term debt due currently		9			621		233		—		(205	)		658
Trade accounts payable		—			—		666		519		(516	)		669
Trade accounts and other payables to affiliates		—			—		210		3		(3	)		210
Notes payable to parent/affiliate		46			—		—		—		—			46
Commodity and other derivative contractual liabilities		—			918		1,246		—		—			2,164
Margin deposits related to commodity positions		—			341		290		—		—			631

162

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of December 31, 2010

(Millions of Dollars)

	Parent Guarantor			Issuer			Other Guarantors			Non- guarantors		Eliminations			Consolidated
Accrued income taxes payable to parent		—			79			—			1		(59	)		21
Accrued taxes other than income		—			—			130			—		—			130
Accrued interest		26			298			185			—		(183	)		326
Other current liabilities		—			8			253			—		(7	)		254
Total current liabilities		89			10,164			4,338			620		(8,881	)		6,330
Accumulated deferred income taxes		70			376			5,655			—		(101	)		6,000
Commodity and other derivative contractual liabilities		—			831			38			—		—			869
Notes or other liabilities due affiliates		—			—			384			—		—			384
Long-term debt held by affiliate		—			343			—			—		—			343
Long-term debt, less amounts due currently		934			28,106			27,550			—		(27,459	)		29,131
Other noncurrent liabilities and deferred credits		12			55			2,169			—		—			2,236
Total liabilities		1,105			39,875			40,134			620		(36,441	)		45,293
EFCH shareholder’s equity		(6,236	)		(5,146	)		(6,076	)		35		11,187			(6,236	)
Noncontrolling interests in subsidiaries		—			—			—			87		—			87
Total equity		(6,236	)		(5,146	)		(6,076	)		122		11,187			(6,149	)
Total liabilities and equity	$	(5,131	)	$	34,729		$	34,058		$	742	$	(25,254	)	$	39,144

(a) During the preparation of our December 31, 2011 financial statements, we determined that $6.7 billion of the advances from affiliates within the ‘Other Guarantors’ column previously reported within current assets should be classified as long-term. We believe this correction is not material.

163

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.

164

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

MANAGEMENT’S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Energy Future Competitive Holdings Company is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Energy Future Competitive Holdings Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.

The management of Energy Future Competitive Holdings Company performed an evaluation as of December 31, 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 Competitive Holdings Company’s internal control over financial reporting was effective.

The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Energy Future Competitive Holdings Company has issued an attestation report on Energy Future Competitive Holdings Company’s internal control over financial reporting.

/S/    JOHN F. YOUNG	/S/    PAUL M. KEGLEVIC
John F. Young, Chair, President and	Paul M. Keglevic, Executive Vice President
Chief Executive	and Chief Financial Officer

February 20, 2012

165

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the internal control over financial reporting of Energy Future Competitive Holdings Company (a subsidiary of Energy Future Holdings Corp.) and subsidiaries (“EFCH”) as of December 31, 2011 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. EFCH’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on EFCH’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, EFCH maintained, in all material respects, effective internal control over financial reporting as of December 31, 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 as of December 31, 2011 and for the year ended December 31, 2011 of EFCH and our report dated February 20, 2012 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding EFCH’s subsidiary, Texas Competitive Electric Holdings Company LLC’s, loans, which are payable on demand, to its indirect parent, Energy Future Holdings Corp., with amounts outstanding at December 31, 2011 and 2010 of $1.592 billion and $1.921 billion, respectively.

/S/    DELOITTE & TOUCHE LLP

Dallas, Texas

February 20, 2012

166

Item 9b. OTHER INFORMATION

None

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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

Item 11. EXECUTIVE COMPENSATION

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

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

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

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

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

167

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Deloitte & Touche LLP has been the independent auditor for EFH Corp. and for its Predecessor (TXU Corp.) since its organization in 1996.

The Audit Committee of the EFH Corp. Board of Directors has adopted a policy relating to the engagement of EFH Corp.’s independent auditor that applies to EFH Corp. and its consolidated subsidiaries, including EFCH. The policy provides that in addition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessary to complete SEC filings, EFH Corp.’s independent auditor may be engaged to provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditor must be authorized by the Audit Committee in accordance with pre-approval procedures which are defined in the policy. The pre-approval 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 pre-approved 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 and political action plan audits;

c. accounting and financial reporting standards consultation,

d. internal control reviews, and

e. attest services, including agreed upon procedures reports that are not required by statute or regulation.

2. Tax related services, including:

a. tax compliance;

b. general tax consultation and planning,

c. tax advice related to mergers, acquisitions, and divestitures, and

d. communications with and request for rulings from tax authorities.

3. Other services, including:

a. process improvement, review and assurance;

b. litigation and rate case assistance;

c. forensic and investigative services, and

d. training services.

The policy prohibits EFCH from engaging its independent auditor to provide:

1. Bookkeeping or other services related to EFCH’s accounting records or financial statements;

2. Financial information systems design and implementation services;

3. Appraisal or valuation services, fairness opinions, or contribution-in-kind reports;

4. Actuarial services;

5. Internal audit outsourcing services;

6. Management or human resource functions;

7. Broker-dealer, investment advisor, or investment banking services;

8. Legal and expert services unrelated to the audit, and

9. Any other service that the Public Company Accounting Oversight Board determines, by regulation, to be impermissible.

In addition, the policy prohibits EFCH’s independent auditor from providing tax or financial planning advice to any officer of EFCH.

Compliance with the Audit Committee’s policy relating to the engagement of Deloitte & Touche is monitored on behalf of the Audit Committee by EFH Corp.’s chief accounting officer. Reports describing the services provided by Deloitte & Touche and fees for such services are provided to the Audit Committee no less often than quarterly.

168

For the years ended December 31, 2011 and 2010, fees billed to EFCH by Deloitte & Touche were as follows:

		$000,000,00		$000,000,00
	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	$	6,035,500	$	5,037,166
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		326,000		157,149
Tax Fees. Fees for tax compliance, tax planning, and tax advice related to mergers and acquisitions, divestitures, and communications with and requests for rulings from taxing authorities		—		—
All Other Fees. Fees for services including process improvement reviews, forensic accounting reviews, litigation and rate case assistance, and training services		—		—
Total	$	6,361,500	$	5,194,315

169

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(b) Exhibits:

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2011

Exhibits	Previously Filed* With File Number	As Exhibit
(3)	Articles of Incorporation and By-laws
3(a)	333-153529 Form S-4 (filed September 17, 2008)	3(b)	—	Second Amended and Restated Articles of Incorporation of Energy Future Competitive Holdings Company (formerly known as TXU US Holdings Company)
3(b)	333-153529 Form S-4 (filed September 17, 2008)	3(e)	—	Restated Bylaws of Energy Future Competitive Holdings Company (formerly known as TXU US Holdings Company)
(4)	Instruments Defining the Rights of Security Holders, Including Indentures**
	Energy Future Holdings Corp. (Merger-related push down debt)
4(a)	1-12833 Form 8-K (filed October 31, 2007)	4.1	—	Indenture, dated October 31, 2007, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon, as trustee, relating to Senior Notes due 2017 and Senior Toggle Notes due 2017.
4(b)	1-12833 Form 10-K (2009) (filed February 19, 2010)	4(f)	—	Supplemental Indenture, dated July 8, 2008, to Indenture, dated October 31, 2007.
4(c)	1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009)	4(a)	—	Second Supplemental Indenture, dated August 3, 2009, to Indenture, dated October 31, 2007.
4(d)	1-12833 Form 8-K (filed July 30, 2010)	99.1	—	Third Supplemental Indenture, dated July 29, 2010, to Indenture, dated October 31, 2007.
4(e)	1-12833 Form 10-Q (Quarter ended September 30, 2011) (filed October 28, 2011)	4(b)	—	Fourth Supplemental Indenture, dated October 18, 2011, to Indenture dated October 31, 2007.
4(f)	1-12833 Form 8-K (filed November 20, 2009)	4.1	—	Indenture, dated November 16, 2009, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019.
4(g)	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(h)	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(i)	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.

170

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2011

4(j)	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(k)	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(l)	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(m)	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(n)	333-171253 Form S-4 (filed January 24, 2011)	4(r)	—	Seventh Supplemental Indenture, dated July 7, 2010, to Indenture, dated January 12, 2010.
Texas Competitive Electric Holdings Company LLC
4(o)	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(p)	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(q)	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(r)	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(s)	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(t)	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.

171

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2011

4(u)	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(v)	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(w)	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(x)	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(y)	1-12833 Form 10-K (filed February 18, 2011)	4(aaa)	—	Form of Second Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of The Bank of New York Mellon Trust Company, N.A., as Collateral Agent and Initial Second Priority Representative for the benefit of the Second Lien Secured Parties, as Beneficiary.
4(z)	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(aa)	1-12833 Form 8-K (filed April 20, 2011)	4.2	—	Form of Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Collateral Agent for the benefit of the Holders of the 11.5% Senior Secured Notes due 2020, as Beneficiary.
4(bb)	1-12833 Form 8-K (filed April 20, 2011)	4.3	—	Form of Deed of Trust and Security Agreement to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as Collateral Agent for the benefit of the Holders of the 11.5% Senior Secured Notes due 2020, as Beneficiary.
4(cc)	1-12833 Form 8-K (filed April 20, 2011)	4.4	—	Form of Subordination and Priority Agreement, among Citibank, N.A., as beneficiary under the First Lien Credit Deed of Trust, The Bank of New York Mellon Trust Company, N.A., as beneficiary under the Second Lien Indenture Deed of Trust, Citibank, N.A., as beneficiary under the First Lien Indenture Deed of Trust, Texas Competitive Electric Holdings Company LLC and the subsidiary guarantors party thereto.
(10)	Material Contracts
	Credit Agreements and Related Agreements

172

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2011

10(a)	333-171253 Post-Effective Amendment #1 to Form S-4 (filed February 7, 2011)	10(rr)	—	$24,500,000,000 Credit Agreement, dated October 10, 2007, among Energy Future Competitive Holdings Company; Texas Competitive Electric Holdings Company LLC, as the borrower; the several lenders from time to time parties thereto; Citibank, N.A., as administrative agent, collateral agent, swingline lender, revolving letter of credit issuer and deposit letter of credit issuer; Goldman Sachs Credit Partners L.P., as posting agent, posting syndication agent and posting documentation agent; JPMorgan Chase Bank, N.A., as syndication agent and revolving letter of credit issuer; Citigroup Global Markets Inc., J.P. Morgan Securities Inc., Goldman Sachs Credit Partners L.P., Lehman Brothers Inc., Morgan Stanley Senior Funding, Inc. and Credit Suisse Securities (USA) LLC, as joint lead arrangers and bookrunners; Goldman Sachs Credit Partners L.P., as posting lead arranger and bookrunner; Credit Suisse, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc., Morgan Stanley Senior Funding, Inc., as co-documentation agents; and J. Aron & Company, as posting calculation agent.
10(b)	1-12833 Form 8-K (filed August 10, 2009)	10.1	—	Amendment No. 1, dated August 7, 2009, to the $24,500,000,000 Credit Agreement.
10(c)	1-12833 Form 8-K (filed April 20, 2011)	10.1	—	Amendment No. 2, dated April 7, 2011, to the $24,500,000,000 Credit Agreement
10(d)	1-12833 Form 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(e)	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(f)	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(g)	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(h)	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.

173

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2011

10(i)	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(j)	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(k)	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(l)	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(m)	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(n)	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(o)	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(p)	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(q)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10 (uuu)	—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(r)	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(s)	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(t)	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.

174

EFCH’s Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2011

(12)	Statement Regarding Computation of Ratios
12(a)		—	Computation of Ratio of Earnings to Fixed Charges
(31)	Rule 13a - 14(a)/15d - 14(a) Certifications
31(a)		—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)		—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
32(a)		—	Certification of John Young, principal executive officer of Energy Future Competitive Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b)		—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Competitive Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(95)	Mine Safety Disclosures
95(a)		—	Mine Safety Disclosures
(99)	Additional Exhibits
99(a)	33-55408                                                     99(b) Post-Effective Amendment No. 1 to Form S-3 (filed July, 1993)	—	Amended Agreement dated January 30, 1990, between Energy Future Competitive Holdings Company and Tex- La Electric Cooperative of Texas, Inc.
99(b)		—	Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2011 and 2010.
99(c)		—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2011 and 2010.
	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 references

** 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.

175

SIGNATURES

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

	ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY
Date: February 20, 2012	By	/S/    JOHN F. YOUNG
		(John F. Young, President and Chief Executive)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Energy Future Competitive Holdings Company and in the capacities and on the date indicated.

Signature	Title	Date
/S/ JOHN F. YOUNG	Principal Executive Officer and Director	February 20, 2012
(John F. Young, Chair, President and Chief Executive)
/S/ PAUL M. KEGLEVIC	Principal Financial Officer and Director	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 / FREDERICK M. GOLTZ	Director	February 20, 2012
(Frederick M. Goltz)
/S/ SCOTT LEBOVITZ	Director	February 20, 2012
(Scott Lebovitz)
/ S/ MICHAEL MACDOUGALL	Director	February 20, 2012
(Michael MacDougall)

176

EXHIBIT 12(a)

	Successor														Predecessor Period
	Year Ended December 31,											Period from October 11, 2007 through December 31,			from January 1, 2007 through October 10,
	2011			2010			2009		2008			2007			2007
EARNINGS:
Income (loss) from continuing operations	$	(1,802	)	$	(3,530	)	$	515	$	(9,039	)	$	(1,266	)	$	1,306
Add: Total federal income tax expense (benefit)		943			318			351		(504	)		(675	)		618
Fixed charges (see detail below)		3,849			3,150			2,420		4,518			715			394
Total earnings (loss)	$	2,990		$	(62	)	$	3,286	$	(5,025	)	$	(1,226	)	$	2,318
FIXED CHARGES:
Interest expense	$	3,824		$	3,127		$	2,395	$	4,492		$	709		$	370
Rentals representative of the interest factor		25			23			25		26			6			24
Total fixed charges	$	3,849		$	3,150		$	2,420	$	4,518		$	715		$	394
RATIO OF EARNINGS TO FIXED CHARGES (a)		—			—			1.36		—			—			5.88

(a) Fixed charges exceeded “earnings” by $859 million, $3.212 billion, $9.543 billion and $1.941 billion for the years ended December 31, 2011, 2010 and 2008 and for the period from October 11, 2007 through December 31, 2007, respectively.

Exhibit 31(a)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 302

of Sarbanes—Oxley Act of 2002

I, John F. Young, certify that:\

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

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

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

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

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

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

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

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

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

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

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

Date: February 20, 2012		/s/ JOHN F. YOUNG
	Name:	John F. Young
	Title:	Chair, President and Chief Executive

Exhibit 31(b)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 302

of Sarbanes—Oxley Act of 2002

I, Paul M. Keglevic, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 20, 2012		/s/ PAUL M. KEGLEVIC
	Name:	Paul M. Keglevic
	Title:	Executive Vice President and Chief Financial Officer

Exhibit 32(a)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 906

of Sarbanes—Oxley Act of 2002

CERTIFICATION OF CEO

The undersigned, John F. Young, Chair, President and Chief Executive of Energy Future Competitive Holdings Company (the “Company”), DOES HEREBY CERTIFY that, to his knowledge:

1. The Company’s Annual Report on Form 10-K for the period ended December 31, 2011 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 20th day of February, 2012.

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

A signed original of this written statement required by Section 906 has been provided to Energy Future Competitive Holdings Company and will be retained by Energy Future Competitive Holdings Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY

Certificate Pursuant to Section 906

of Sarbanes—Oxley Act of 2002

CERTIFICATION OF CEO

The undersigned, Paul M. Keglevic, Executive Vice President and Chief Financial Officer of Energy Future Competitive Holdings Company (the “Company”), DOES HEREBY CERTIFY that, to his knowledge:

1. The Company’s Annual Report on Form 10-K for the period ended December 31, 2011 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 20th day of February, 2012.

	/s/ PAUL M. KEGLEVIC
Name:	Paul M. Keglevic
Title:	Executive Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Energy Future Competitive Holdings Company and will be retained by Energy Future Competitive Holdings Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 95(a)

Mine Safety Disclosures

Safety is a top priority in all our businesses, and accordingly, it is a key component of our focus on operational excellence, our employee performance reviews and employee compensation. Our health and safety program objectives are to prevent workplace accidents and ensure that all employees return home safely and comply with all regulations.

We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. These mining operations are regulated by the US Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other regulatory agencies such as the RRC. The MSHA inspects US mines, including ours, on a regular basis and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed to the Federal Mine Safety and Health Review Commission (FMSHRC), which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. The number of citations, orders and proposed assessments vary depending on the size of the mine as well as other factors.

Disclosures related to specific mines pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K sourced from data documented as of January 3, 2012 in the MSHA Data Retrieval System for the twelve months ended December 31, 2011 (except pending legal actions, which are as of December 31, 2011), are as follows:

Mine (a)	Section 104 S and  S Citations (b)		Section 104(b) Orders		Section 104(d) Citations and Orders		Section 110(b)(2) Violations		Section 107(a) Orders		Total Dollar Value of MSHA Assessments Proposed (c)		Total Number of Mining Related Fatalities		Received Notice of Pattern of Violations Under Section 104(e)		Received Notice of Potential to Have Pattern Under Section 104(e)		Legal Actions Pending as of Last Day of Period (d)		Legal Actions Initiated During Period		Legal Actions Resolved During Period
Beckville		9		—		3		—		2		20		—		—		—		5		5		2
Big Brown		6		—		—		—		—		26		—		—		—		3		3		—
Kosse		4		—		3		—		—		118		—		—		—		3		3		—
Oak Hill		2		—		—		—		—		16		—		—		—		3		2		1
Sulphur Springs		5		—		—		—		—		12		—		—		—		2		3		7
Tatum		1		—		—		—		—		5		—		—		—		2		2		1
Three Oaks		4		—		—		—		—		9		—		—		—		3		3		1
Turlington		3		—		1		—		—		2		—		—		—		—		—		—
Winfield South		2		—		—		—		—		4		—		—		—		1		—		—

(a) Excludes mines for which there were no applicable events.

(b) Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.

(c) Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in the twelve months ended December 31, 2011, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.

(d) Pending actions before the FMSHRC involving a coal or other mine. All 22 are contests of citations and orders.

Exhibit 99(b)

Texas Competitive Electric Holdings Company LLC Consolidated

Adjusted EBITDA Reconciliation

(millions of dollars)

	Year Ended December 31,
	2011			2010
Net loss	$	(1,740	)	$	(3,383	)
Income tax expense (benefit)		(917	)		402
Interest expense and related charges		3,699			2,837
Depreciation and amortization		1,470			1,380
EBITDA	$	2,512		$	1,236
Interest income		(87	)		(91	)
Amortization of nuclear fuel		142			140
Purchase accounting adjustments (a)		157			163
Impairment of goodwill		—			4,100
Impairment and write-down of other assets (b)		430			13
Debt extinguishment gains		—			(687	)
Unrealized net gain resulting from hedging and trading transactions		(58	)		(1,221	)
EBITDA amount attributable to consolidated unrestricted subsidiaries		(7	)		1
Amortization of “day one” net loss on Sandow 5 power purchase agreement		—			(22	)
Corporate depreciation, interest and income tax expenses included in SG&A expense		16			9
Noncash compensation expense (c)		12			14
Severance expense		5			3
Transition and business optimization costs (d)		42			9
Transaction and merger expenses (e)		37			38
Restructuring and other (f)		67			(116	)
Expenses incurred to upgrade or expand a generation station (g)		100			100
Adjusted EBITDA per Incurrence Covenant	$	3,368		$	3,689
Expenses related to unplanned generation station outages		181			132
Proforma adjustment for Oak Grove 2 reaching 70% capacity in Q2 2011 (h)		27			—
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (i)		8			29
Adjusted EBITDA per Maintenance Covenant	$	3,584		$	3,850

(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. 2011 includes $46 million related to an asset sale.

(b) Impairment of assets in 2011 includes impairment of emission allowances and certain mining assets due to EPA rule issued in July 2011.

(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and exclude capitalized amounts.

(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costs related to generation plant reliability and supply chain efficiency initiatives.

(e) Transaction and merger expenses primarily represent Sponsor Group management fees.

(f) Restructuring and other includes gains on termination of a long-term power sales contract and settlement of amounts due from hedging/ trading counterparty, fees related to the April 2011 amendment and extension of the TCEH Senior Secured Facilities, and reversal of certain liabilities accrued in purchase accounting.

(g) Expenses incurred to upgrade or expand a generation station reflect noncapital outage costs.

(h) Proforma adjustment represents the annualization of the actual nine months ended December 31, 2011 EBITDA results for Oak Grove 2, which achieved the requisite 70% average capacity factor in the second quarter 2011.

(i) Primarily pre-operating expenses relating to Oak Grove and Sandow 5.

Exhibit 99(c)

Energy Future Holdings Corp. Consolidated

Adjusted EBITDA Reconciliation

(millions of dollars)

	Year Ended December 31,
	2011			2010
Net loss	$	(1,913	)	$	(2,812	)
Income tax expense (benefit)		(1,134	)		389
Interest expense and related charges		4,294			3,554
Depreciation and amortization		1,499			1,407
EBITDA	$	2,746		$	2,538
Oncor distributions/dividends		116			169
Interest income		(2	)		(10	)
Amortization of nuclear fuel		142			140
Purchase accounting adjustments (a)		204			210
Impairment of goodwill		—			4,100
Impairment and write-down of other assets (b)		433			15
Debt extinguishment gains		(51	)		(1,814	)
Equity in earnings of unconsolidated subsidiary		(286	)		(277	)
Unrealized net gain resulting from hedging and trading transactions		(58	)		(1,221	)
EBITDA amount attributable to consolidated unrestricted subsidiaries		—			1
Amortization of “day one” net loss on Sandow 5 power purchase agreement		—			(22	)
Noncash compensation expense (c)		13			18
Severance expense		7			4
Transition and business optimization costs (d)		39			4
Transaction and merger expenses (e)		37			48
Restructuring and other (f)		73			(117	)
Expenses incurred to upgrade or expand a generation station (g)		100			100
Adjusted EBITDA per Incurrence Covenant	$	3,513		$	3,886
Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions)		1,523			1,354
Adjusted EBITDA per Restricted Payments Covenant	$	5,036		$	5,240

(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits and gains on asset sales not recognized in net income due to purchase accounting. 2011 includes $46 million related to an asset sale.

(b) Impairment of assets in 2011 includes impairment of emission allowances and certain mining assets due to EPA rule issued in July 2011.

(c) Noncash compensation expenses represent amounts recorded under stock-based compensation accounting standards and exclude capitalized amounts.

(d) Transition and business optimization costs include certain incentive compensation expenses, as well as professional fees and other costs related to generation plant reliability and supply chain efficiency initiatives.

(e) Transaction and merger expenses primarily represent Sponsor Group management fees.

(f) Restructuring and other includes gains on termination of a long-term power sales contract and settlement of amounts due from hedging/ trading counterparty, fees related to the April 2011 amendment and extension of the TCEH Senior Secured Facilities, and reversal of certain liabilities accrued in purchase accounting.

(g) Expenses incurred to upgrade or expand a generation station reflect noncapital outage costs.